10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2016

OR

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

For the transition period from to

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

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

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

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

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

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

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

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of April 29, 2016 was 235,550,000. As of April 29, 2016, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

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

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
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
CAIR	Clean Air Interstate Rule
Cambrian	Cambrian Coal Corporation
capacity clause	capacity cost-recovery clause, as established by the FPSC
CCRs	coal combustion residuals
CES	Continental Energy Systems
CMO	collateralized mortgage obligation
CNG	compressed natural gas
company	TECO Energy, Inc.
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
DR-CAFTA	Dominican Republic Central America – United States Free Trade Agreement
ECRC	environmental cost recovery clause
EEI	Edison Electric Institute
EGWP	Employee Group Waiver Plan
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada
EPA	U.S. Environmental Protection Agency
EPS	earnings per share
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FPSC	Florida Public Service Commission
GCBF	gas cost billing factor
GHG	greenhouse gas(es)
HAFTA	Highway and Transportation Funding Act
HCIDA	Hillsborough County Industrial Development Authority
ICSID	International Centre for the Settlement of Investment Disputes
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ITCs	investment tax credits
KW	kilowatt(s)
KWH	kilowatt-hour(s)
LIBOR	London Interbank Offered Rate
MAP-21	Moving Ahead for Progress in the 21st Century Act
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	Merger of Merger Sub with and into TECO Energy, with TECO Energy as the surviving corporation
Merger Agreement	Agreement and Plan of Merger dated Sept. 4, 2015, by and among TECO Energy, Emera and Merger Sub
Merger Sub	Emera US Inc., a Florida corporation
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003

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Term	Meaning
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board
NAV	net asset value
NMGC	New Mexico Gas Company, Inc.
NMGI	New Mexico Gas Intermediate, Inc.
NMPRC	New Mexico Public Regulation Commission
NOL	net operating loss
Note	Note to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
OPC	Office of Public Counsel
OPEB	other postretirement benefits
OTC	over-the-counter
Parent	TECO Energy (the holding company, excluding subsidiaries)
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PGA	purchased gas adjustment
PGAC	purchased gas adjustment clause
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
REIT	real estate investment trust
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
ROW	rights-of-way
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
SPA	Securities Purchase Agreement dated Sept. 21, 2015, by and between TECO Diversified and Cambrian relating to the purchase of TECO Coal by Cambrian
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 Coal	TECO Coal LLC, and its subsidiaries, a coal producing subsidiary of TECO Diversified
TECO Diversified	TECO Diversified, Inc., a subsidiary of TECO Energy, Inc. and parent of TECO Coal Corporation
TECO Energy	TECO Energy, Inc.
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
TGH	TECO Guatemala Holdings, LLC
TRC	TEC Receivables Company
TSI	TECO Services, Inc.
U.S. GAAP	generally accepted accounting principles in the United States
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

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PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

4

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2016			2015
Current assets
Cash and cash equivalents	$	46.1		$	23.8
Receivables, less allowance for uncollectibles of $2.1 and $2.1    at Mar. 31, 2016 and Dec. 31, 2015, respectively		240.1			280.7
Inventories, at average cost
Fuel	118.3			113.4
Materials and supplies		77.1			76.8
Regulatory assets		40.2			44.8
Prepayments and other current assets		25.4			30.8
Total current assets		547.2			570.3
Property, plant and equipment
Utility plant in service
Electric		7,328.3			7,270.3
Gas		2,154.1			2,113.8
Construction work in progress		816.9			794.7
Other property		16.1			15.9
Property, plant and equipment, at original costs		10,315.4			10,194.7
Accumulated depreciation		(2,762.4	)		(2,712.9	)
Total property, plant and equipment, net		7,553.0			7,481.8
Other assets
Regulatory assets		393.4			395.2
Goodwill		408.4			408.4
Deferred charges and other assets		79.1			77.8
Total other assets		880.9			881.4
Total assets	$	8,981.1		$	8,933.5

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

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	Mar. 31,			Dec. 31,
(millions)	2016			2015
Current liabilities
Long-term debt due within one year	$	83.3		$	333.3
Notes payable		513.0			247.0
Accounts payable		189.5			255.4
Customer deposits		176.7			182.1
Regulatory liabilities		108.4			84.8
Derivative liabilities		22.3			24.1
Interest accrued		54.0			36.2
Taxes accrued		28.2			13.2
Other		25.2			22.6
Total current liabilities		1,200.6			1,198.7
Other liabilities
Deferred income taxes		607.0			570.7
Investment tax credits		10.4			10.5
Regulatory liabilities		709.4			715.8
Derivative liabilities		0.8			2.1
Deferred credits and other liabilities		380.9			387.5
Long-term debt, less amount due within one year		3,489.7			3,489.2
Total other liabilities		5,198.2			5,175.8
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 235.5 million    and 235.3 million shares outstanding at Mar. 31, 2016 and Dec. 31, 2015,    respectively)		235.5			235.3
Additional paid in capital		1,894.8			1,894.5
Retained earnings		463.5			441.4
Accumulated other comprehensive loss		(11.5	)		(12.2	)
Total capital		2,582.3			2,559.0
Total liabilities and capital	$	8,981.1		$	8,933.5

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Mar. 31,
(millions, except per share amounts)		2016			2015
Revenues
Regulated electric		$	423.4		$	449.7
Regulated gas			232.9			240.2
Unregulated			3.2			3.1
Total revenues			659.5			693.0
Expenses
Regulated operations and maintenance
Fuel			115.2			144.1
Purchased power			14.4			17.1
Cost of natural gas sold			96.8			103.0
Other			142.3			143.7
Operation and maintenance other expense			0.0			1.6
Depreciation and amortization			89.8			85.5
Taxes, other than income			52.9			51.8
Total expenses			511.4			546.8
Income from operations			148.1			146.2
Other income
Allowance for other funds used during construction			5.7			3.8
Other income, net			1.5			1.6
Total other income			7.2			5.4
Interest charges
Interest expense			48.9			49.8
Allowance for borrowed funds used during construction			(3.0	)		(1.9	)
Total interest charges			45.9			47.9
Income from continuing operations before provision for    income taxes			109.4			103.7
Provision for income taxes			35.7			39.9
Net income from continuing operations			73.7			63.8
Discontinued operations
Income (loss) from discontinued operations			0.2			(9.6	)
Provision (benefit) from income taxes			0.1			(3.8	)
Income (loss) from discontinued operations, net			0.1			(5.8	)
Net income		$	73.8		$	58.0
Average common shares outstanding	– Basic		234.0			232.8
	– Diluted		235.2			233.5
Earnings per share from continuing operations	– Basic	$	0.31		$	0.27
	– Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.02	)
	– Diluted	$	0.00		$	(0.02	)
Earnings per share	– Basic	$	0.31		$	0.25
	– Diluted	$	0.31		$	0.25
Dividends paid per common share outstanding		$	0.230		$	0.225

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2016		2015
Net income	$	73.8	$	58.0
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2		0.3
Amortization of unrecognized benefit costs		0.5		0.6
Other comprehensive income, net of tax		0.7		0.9
Comprehensive income	$	74.5	$	58.9

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	73.8		$	58.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		89.8			85.9
Deferred income taxes and investment tax credits		36.1			36.0
Allowance for other funds used during construction		(5.7	)		(3.8	)
Non-cash stock compensation		3.0			3.9
Deferred recovery clauses		26.4			(5.7	)
Receivables, less allowance for uncollectibles		40.6			51.0
Inventories		(5.2	)		(15.7	)
Prepayments and other current assets		2.8			(10.9	)
Taxes accrued		18.1			1.7
Interest accrued		17.8			17.8
Accounts payable		(59.1	)		(63.5	)
Other		(6.8	)		(7.7	)
Cash flows from operating activities		231.6			147.0
Cash flows from investing activities
Capital expenditures		(168.0	)		(156.2	)
Other investing activities		(0.2	)		(0.2	)
Cash flows used in investing activities		(168.2	)		(156.4	)
Cash flows from financing activities
Dividends and dividend equivalents		(54.3	)		(53.0	)
Proceeds from the sale of common stock		3.9			2.8
Repayment of long-term debt/purchase in lieu of redemption		(250.0	)		0.0
Net increase (decrease) in short-term debt (maturities of 90 days or less)		(134.0	)		67.0
Proceeds from other short-term debt (maturities over 90 days)		400.0			0.0
Other financing activities		(6.7	)		0.0
Cash flows from (used in) financing activities		(41.1	)		16.8
Net increase in cash and cash equivalents		22.3			7.4
Cash and cash equivalents at beginning of the period		23.8			25.4
Cash and cash equivalents at end of the period	$	46.1		$	32.8
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(6.0	)	$	11.5

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

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2015 Annual Report on Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the company classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.

Stock Compensation

In March 2016, the FASB issued guidance regarding employee share-based payment accounting. The guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liability, and presentation on the statement of cash flows. This guidance will be required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact and was implemented as follows:

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· Income tax consequences – Under the new guidance, the company will no longer recognize excess tax benefits and certain tax deficiencies in additional paid in capital. Instead, the company will recognize all excess tax benefits and tax deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize them. Accordingly, the company recorded a $2.6 million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. In accordance with the new guidance, the company will no longer include excess tax benefits and tax deficiencies in the dilutive EPS calculation on a prospective basis.

· Accounting for forfeitures – The company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods.

· Classification of awards - The company had no share-based payments classified as liability awards as of Mar. 31, 2016 or Dec. 31, 2015.  

· Presentation on the statement of cash flows – Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a retrospective basis for all periods presented. Previously, the company presented it as an operating activity. There was an immaterial amount of activity that did not result in an adjustment to the statement of cash flows for the three months ended Mar. 31, 2015.

Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for the company beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on future derivative contract novations, if any.

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3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. 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 requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC 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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.1	$	74.7
Cost-recovery clauses - deferred balances (2)		0.1		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		26.0		26.5
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		238.5		240.6
Deferred bond refinancing costs (5)		6.2		6.5
Debt basis adjustment (6)		16.7		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		12.1		12.1
Total regulatory assets		433.6		440.0
Less: Current portion		40.2		44.8
Long-term regulatory assets	$	393.4	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.6	$	7.9
Cost-recovery clauses (2)		80.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		673.6		679.9
Other		0.5		0.8
Total regulatory liabilities		817.8		800.6
Less: Current portion		108.4		84.8
Long-term regulatory liabilities	$	709.4	$	715.8

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

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(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

(7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

The effective tax rate decreased to 32.63% for the three months ended Mar. 31, 2016 from 38.48% for the same period in 2015 primarily due to the tax benefit related to long-term incentive compensation share vestings (see Note 2 for further description).

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. 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 and foreign jurisdictions include 2005 and forward. TECO Energy does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Mar. 31,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.4		$	4.5		$	0.5		$	0.6
Interest cost		8.1			7.4			2.2			2.0
Expected return on assets		(11.3	)		(10.8	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		3.4			3.4			0.0			0.0
Regulatory asset		0.0			0.0			0.2			0.3
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	4.6		$	4.4		$	2.0		$	2.0

For the fiscal 2016 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan for the three months ended Mar. 31, 2016 and 2015, respectively.

For the three months ended Mar. 31, 2016 and 2015, TECO Energy and its subsidiaries reclassified $0.8 million of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2016 and 2015, the regulated companies reclassified $2.2 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

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6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		113.0		0.0		300.0		163.0		0.0
1-year term facility (4)(5)		400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility (2)		125.0		0.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	513.0	$	2.2	$	900.0	$	247.0	$	2.2
(1)           Borrowings outstanding are reported as notes payable.
(2)           This 5-year facility matures Dec. 17, 2018.
(3)           Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.
(4)           TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5)           This 1-year facility matures Mar. 14, 2017.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.44% and 1.29%, respectively.  

TECO Energy/TECO Finance Credit Facility

On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, total long-term debt had a carrying amount of $3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 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 (see Note 13 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012.  On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016.  On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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.

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As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5
Total other comprehensive income	$	1.1	$	(0.4	)	$	0.7
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income (1)		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs (2)		0.9		(0.3	)		0.6
Total other comprehensive income	$	1.6	$	(0.7	)	$	0.9
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement and postemployment benefits. See Note 5 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and    transition obligations (2)		25.5			25.6
Net unrealized losses from cash flow hedges (3)		(3.4	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.5	)	$	(12.2	)
(1)  Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

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9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2016			2015
Basic earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Basic	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Basic	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Basic	$	73.7		$	57.8
Average common shares outstanding - Basic		234.0			232.8
Earnings per share from continuing operations available to    common shareholders - Basic	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Basic		0.0		$	(0.02	)
Earnings per share available to common shareholders - Basic	$	0.31		$	0.25
Diluted earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Diluted	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Diluted	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Diluted	$	73.7		$	57.8
Unadjusted average common shares outstanding - Diluted		234.0			232.8
Assumed conversion of stock options, unvested restricted stock,    unvested RSUs and contingent performance shares, net		1.2			0.7
Average common shares outstanding - Diluted		235.2			233.5
Earnings per share from continuing operations available to    common shareholders - Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Diluted		0.0		$	(0.02	)
Earnings per share available to common shareholders - Diluted	$	0.31		$	0.25
Anti-dilutive shares		0.2			0.1

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10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. 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.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Mar. 31, 2016.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.  

Proceedings in connection with the Pending Merger with Emera

Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction.  Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida.  They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger.  In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

The company also received two separate shareholder demand letters from purported shareholders of the company.  Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices.  One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.  

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In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.  Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete.  There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Claim in connection with the Sale of TECO Coal

As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. On Mar. 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting breach of certain representations, and fraud and willful misconduct in connection therewith, of the SPA.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

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

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.

On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to TGH.  As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

PGS Compliance Matter
          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

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 Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” 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 rates.

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.

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows:

(millions)							Maximum
					After (1)		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits (3)		89.4		0.0		0.0		89.4		0.0
	$	89.4	$	0.0	$	92.9	$	182.3	$	0.0
							Maximum
(millions)					After (1)		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.0
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.1
(1)    These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Mar. 31, 2016. See Note 12 for additional information.
(3)    These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.
(4)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive

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covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

11. Segment Information

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

Three months ended Mar. 31,	Tampa Electric		PGS		NMGC (2)		TECO Coal (1)			Other (2) (3)			Eliminations (3)				TECO Energy
2016
Revenues - external	$	423.4	$	126.8	$	106.6	$	0.0		$	2.7		$	0.0			$	659.5
Sales to affiliates		1.1		4.4		0.0		0.0			0.0			(5.5	)			0.0
Total revenues		424.5		131.2		106.6		0.0			2.7			(5.5	)			659.5
Depreciation and amortization		66.1		14.8		8.4		0.0			0.5			0.0				89.8
Total interest charges		23.8		3.7		3.0		0.0			15.6			(0.2	)			45.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.2			(0.2	)			0.0
Provision (benefit) for income taxes		27.8		8.9		9.7		0.0			(10.7	)		0.0				35.7
Net income (loss) from continuing operations		50.2		13.1		15.2		0.0			(4.8	)		0.0				73.7
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		0.0			0.1			0.0				0.1
Net income (loss)	$	50.2	$	13.1	$	15.2	$	0.0		$	(4.7	)	$	0.0			$	73.8
2015
Revenues - external	$	449.8	$	121.7	$	119.0	$	0.0		$	2.5		$	0.0			$	693.0
Sales to affiliates		0.8		1.2		0.0		0.0			0.0			(2.0	)			0.0
Total revenues		450.6		122.9		119.0		0.0			2.5			(2.0	)			693.0
Depreciation and amortization		62.9		13.9		8.4		0.0			0.3			0.0				85.5
Total interest charges		23.5		3.5		3.3		0.0			17.9			(0.3	)			47.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.3			(0.3	)			0.0
Provision (benefit) for income taxes		27.4		9.2		9.0		0.0			(5.7	)		0.0				39.9
Net income (loss) from continuing operations		48.2		14.6		13.9		0.0			(12.9	)		0.0				63.8
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		(6.0	)		0.2			0.0				(5.8	)
Net income (loss)	$	48.2	$	14.6	$	13.9	$	(6.0	)	$	(12.7	)	$	0.0			$	58.0
At Mar. 31, 2016
Total assets	$	6,988.2	$	1,147.0	$	1,210.9	$	0.0		$	1,982.1		$	(2,347.1	)	(4)	$	8,981.1
At Dec. 31, 2015
Total assets (3)	$	7,003.8	$	1,136.1	$	1,229.7	$	0.0		$	1,945.1		$	(2,381.2	)	(4)		8,933.5
(1)    All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
(2)    NMGI is included in the Other segment.
(3)    Certain prior year amounts have been reclassified to conform to current year presentation.
(4)    Amounts primarily relate to intercompany advances and consolidated tax eliminations.

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12. Accounting for Derivative Instruments and Hedging Activities

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

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

· To optimize the utilization of NMGC’s physical natural gas storage capacity, and

· To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ 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 13). 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 and sale of natural gas for the benefit of its regulated companies’ ratepayers. These standards, in accordance with the FPSC and NMPRC, 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 Mar. 31, 2016, all of the company’s physical contracts qualify for the NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 million and $0.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative liabilities totaled $23.1 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the

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threemonths ended Mar. 31, 2016 and 2015 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

Derivative Volumes	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

The company is exposed to credit risk by 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. 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 Mar. 31, 2016, 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 generally do not require a nonperformance risk adjustment 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.

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 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.

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

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(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).  

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

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 Mar. 31, 2016 and Dec. 31, 2015. 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.     

Recurring Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas derivatives	$	0.0	$	23.1	$	0.0	$	23.1
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are estimated utilizing the income approach. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap, forward and option positions to determine the fair value (see Note 12). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

14. Variable Interest Entities

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.

Tampa Electric 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 250 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 variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

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

15. Discontinued Operations and Asset Impairments

TECO Coal

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 10). The SPA contained customary representations, warranties and covenants (see Note 10 for description of a claim related to the SPA). The income shown for the first quarter of 2016 in the table below reflects a refund of prepaid costs.

Since the closing of the sale, TECO Energy does not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries 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 (see Note 10). The charges shown in the table below are legal costs associated with that claim.  

Combined Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

Components of income from discontinued operations	Three months ended
	Mar. 31,
(millions)	2016		2015
Revenues—TECO Coal	$	0.0	$	72.7
Loss from operations—TECO Coal		0.0		(9.5	)
Loss from operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations—TECO Coal		0.2		(9.5	)
Loss from discontinued operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations		0.2		(9.6	)
Provision (benefit) for income taxes		0.1		(3.8	)
Income (loss) from discontinued operations, net	$	0.1	$	(5.8	)

16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.

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The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction.  In the stipulation, the parties state that they believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its acquisition of NMGC, invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs.  The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

During the three months ended Mar. 31, 2016, TECO Energy incurred approximately $0.1 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,328.3		$	7,270.3
Gas		1,419.3			1,398.6
Construction work in progress		797.0			771.1
Utility plant in service, at original costs		9,544.6			9,440.0
Accumulated depreciation		(2,720.3	)		(2,676.8	)
Utility plant in service, net		6,824.3			6,763.2
Other property		9.9			9.7
Total property, plant and equipment, net		6,834.2			6,772.9
Current assets
Cash and cash equivalents		28.2			9.1
Receivables, less allowance for uncollectibles of $1.6 and $1.5 at Mar. 31, 2016    and Dec. 31, 2015, respectively		205.5			230.2
Inventories, at average cost
Fuel		115.4			105.6
Materials and supplies		73.6			73.1
Regulatory assets		39.9			44.3
Taxes receivable from affiliate		0.0			61.3
Prepayments and other current assets		17.0			21.5
Total current assets		479.6			545.1
Deferred debits
Regulatory assets		373.1			373.8
Other		17.9			16.8
Total deferred debits		391.0			390.6
Total assets	$	7,704.8		$	7,708.6

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	Mar. 31,			Dec. 31,
(millions)	2016			2015
Capitalization
Common stock	$	2,330.4		$	2,305.4
Accumulated other comprehensive loss		(3.4	)		(3.6	)
Retained earnings		314.4			313.7
Total capital		2,641.4			2,615.5
Long-term debt		2,162.0			2,161.7
Total capitalization		4,803.4			4,777.2
Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		0.0			61.0
Accounts payable		174.6			221.6
Customer deposits		170.9			176.3
Regulatory liabilities		104.5			83.2
Derivative liabilities		22.2			24.1
Interest accrued		41.2			16.9
Taxes accrued		33.6			13.2
Other		10.1			10.2
Total current liabilities		640.4			689.8
Deferred credits
Deferred income taxes		1,342.0			1,308.8
Investment tax credits		10.4			10.5
Derivative liabilities		0.8			2.1
Regulatory liabilities		595.5			603.5
Deferred credits and other liabilities		312.3			316.7
Total deferred credits		2,261.0			2,241.6
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	7,704.8		$	7,708.6

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Revenues
Electric	$	424.2		$	450.4
Gas		126.8			121.7
Total revenues		551.0			572.1
Expenses
Regulated operations and maintenance
Fuel		115.1			144.1
Purchased power		14.4			17.1
Cost of natural gas sold		50.3			43.3
Other		121.2			121.8
Depreciation and amortization		80.9			76.8
Taxes, other than income		48.5			47.6
Total expenses		430.4			450.7
Income from operations		120.6			121.4
Other income
Allowance for other funds used during construction		5.6			3.8
Other income, net		1.3			1.2
Total other income		6.9			5.0
Interest charges
Interest on long-term debt		29.0			27.7
Interest expense		1.2			1.1
Allowance for borrowed funds used during construction		(2.7	)		(1.8	)
Total interest charges		27.5			27.0
Income before provision for income taxes		100.0			99.4
Provision for income taxes		36.7			36.6
Net income		63.3			62.8
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			0.3
Total other comprehensive income, net of tax		0.2			0.3
Comprehensive income	$	63.5		$	63.1

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	63.3		$	62.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80.9			76.8
Deferred income taxes and investment tax credits		30.4			21.2
Allowance for funds used during construction		(5.6	)		(3.8	)
Deferred recovery clauses		27.0			(4.7	)
Receivables, less allowance for uncollectibles		24.7			13.5
Inventories		(10.3	)		(21.1	)
Prepayments		4.6			(5.0	)
Taxes accrued		81.7			72.7
Interest accrued		24.3			22.9
Accounts payable		(41.2	)		(28.3	)
Other		(11.6	)		(6.9	)
Cash flows from operating activities		268.2			200.1
Cash flows from investing activities
Capital expenditures		(150.5	)		(148.8	)
Cash flows used in investing activities		(150.5	)		(148.8	)
Cash flows from financing activities
Common stock		25.0			20.0
Net decrease in short-term debt		(61.0	)		(11.0	)
Dividends		(62.6	)		(55.7	)
Cash flows used in financing activities		(98.6	)		(46.7	)
Net increase in cash and cash equivalents		19.1			4.6
Cash and cash equivalents at beginning of period		9.1			10.4
Cash and cash equivalents at end of period	$	28.2		$	15.0
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(4.8	)	$	11.4

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2015 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 14 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $56.8 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, TEC classified $17.9 million and $18.1 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified as an asset in the “Unamortized debt expense” line item). The guidance did not affect TEC’s results of operations or cash flows.

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Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. TEC does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for TEC beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for TEC beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for TEC beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect TEC’s current financial statements. However, TEC will assess the impact of this guidance on future derivative contract novations, if any.

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. 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 requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

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Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.0	$	74.6
Cost-recovery clauses - deferred balances (2)		0.0		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		25.9		26.2
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		236.4		238.3
Deferred bond refinancing costs (5)		6.2		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.6		10.7
Total regulatory assets		413.0		418.1
Less: Current portion		39.9		44.3
Long-term regulatory assets	$	373.1	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.6	$	5.7
Cost-recovery clauses (2)		76.1		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		561.7		570.0
Other		0.5		0.7
Total regulatory liabilities		700.0		686.7
Less: Current portion		104.5		83.2
Long-term regulatory liabilities	$	595.5	$	603.5

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three months ended Mar. 31, 2016 and 2015 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. 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 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

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5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Mar. 31, 2016 and 2015, respectively, was $2.9 million and $2.6 million for pension benefits, and $1.5 million and $1.4 million for other postretirement benefits.

For the fiscal 2016 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.685%.  For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan in the three months ended Mar. 31, 2016 and 2015, respectively. TEC’s portion of the contributions was $3.9 million and $11.0 million, respectively.

Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2016 and 2015, TEC reclassified $2.0 million and $1.9 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0.0	$	0.5	$	475.0	$	61.0	$	0.5

(1) Borrowings outstanding are reported as notes payable.

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

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.0% and 0.89%, respectively.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, TEC’s total long-term debt had a carrying amount of $2,245.3 million and an estimated fair market value of $2,483.1 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 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 (see Note 11 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012. On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is

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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.

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. 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.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

PGS Compliance Matter

          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

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 Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” 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 rates.

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

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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.

Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Mar. 31, 2016 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Total		at Mar. 31, 2016
TEC (2)	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
(1)These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TEC was in compliance with all applicable financial covenants.

9. Segment Information

(millions)	Tampa							Tampa Electric
Three months ended Mar. 31,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	424.2	$	126.8	$	0.0		$	551.0
Intracompany sales		0.3		4.4		(4.7	)		0.0
Total revenues		424.5		131.2		(4.7	)		551.0
Depreciation and amortization		66.1		14.8		0.0			80.9
Total interest charges		23.8		3.7		0.0			27.5
Provision for income taxes		27.8		8.9		0.0			36.7
Net income	$	50.2	$	13.1	$	0.0		$	63.3
2015
Revenues - external	$	450.4	$	121.7	$	0.0		$	572.1
Intracompany sales		0.2		1.2		(1.4	)		0.0
Total revenues		450.6		122.9		(1.4	)		572.1
Depreciation and amortization		62.9		13.9		0.0			76.8
Total interest charges		23.5		3.5		0.0			27.0
Provision for income taxes		27.4		9.2		0.0			36.6
Net income	$	48.2	$	14.6	$	0.0		$	62.8
Total assets at Mar. 31, 2016	$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Total assets at Dec. 31, 2015 (1)		6,620.2		1,097.7		(9.3	)		7,708.6

(1) Certain prior year amounts have been reclassified to conform to current year presentation.

10. Accounting for Derivative Instruments and Hedging Activities

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

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

· To limit the exposure to interest rate fluctuations on debt securities.

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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 11). 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 Mar. 31, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative assets as of Mar. 31, 2016 and Dec. 31, 2015. Derivative liabilities totaled $23.0 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2016 and 2015 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassification to income was reflected in “Interest expense”.

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The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

TEC is exposed to credit risk by 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 Mar. 31, 2016, 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 generally do not require a nonperformance risk adjustment 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.

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 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.

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

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(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. 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.  

Recurring Derivative Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	23.0	$	0.0	$	23.0
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Total other comprehensive income	$	0.7	$	(0.4	)	$	0.3

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.4	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.4	)	$	(3.6	)

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(1) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.  

13. 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.

Tampa Electric 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 250 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 variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

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

14. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion).

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction. The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company's current expectations and assumptions, and the company does not undertake to update that information or any other  information contained in this Managements Discussion & Analysis, except as may be required by law. Factors that could impact actual results include:the ability to successfully close the Merger with Emera on the anticipated schedule, if at all; regulatory actions by federal, state or local authorities; the ability to successfully implement the integration plans for NMGC and generate the expected financial results; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices  affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under "Risk Factors" in TECO Energy, Inc.'s Annual Report on Form 10-K for the period ended Dec. 31, 2015.

Earnings Summary - Unaudited

	Three Months Ended Mar. 31,
(millions) Except per-share amounts	2016		2015
Consolidated revenues	$	659.5	$	693.0
Net income from continuing operations		73.7		63.8
Loss on discontinued operations, net		0.1		(5.8	)
Net income		73.8		58.0
Average common shares outstanding
Basic		234.0	232.8
Diluted	235.2		233.5
Earnings per share – basic
Continuing operations	$	0.31	$	0.27
Discontinued operations		0.00		(0.02	)
Earnings per share - basic	$	0.31	$	0.25
Earnings per share – diluted
Continuing operations	$	0.31	$	0.27
Discontinued operations		0.00		(0.02	)
Earnings per share - diluted	$	0.31	$	0.25

Operating Results

Three Months Ended Mar. 31, 2016

First-quarter 2016 net income was $73.8 million, or $0.31 per share, compared with $58.0 million, or $0.25 per share, in the first quarter of 2015.  Net income from continuing operations was $73.7 million, or $0.31 per share, in the 2016 first quarter, compared with $63.8 million, or $0.27 per share, for the same period in 2015. The first quarter losses in discontinued operations of $5.8 million in 2015 reflected the operating results and charges associated with TECO Coal, which was sold in 2015 (see Note 15 to the TECO Energy Consolidated Financial Statements).

Operating Company Results

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

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Tampa Electric Company – Electric Division

Tampa Electric’s net income for the first quarter of 2016 was $50.2 million, compared with $48.2 million for the same period in 2015.  Results for the quarter reflected a 1.7% higher average number of customers, and higher energy sales primarily due to the higher number of customers. Results reflected operations and maintenance expense slightly higher than 2015, and higher depreciation and interest expenses. First-quarter net income in 2016 included $5.6 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $3.8 million in the 2015 quarter.

Total degree days in Tampa Electric's service area in the first quarter of 2016 were 3% above normal, but 4% below the 2015 period, when degree days were 6% above normal. Total net energy for load increased 1.7% in the first quarter of 2016, compared with the same period in 2015. In the 2016 period, pretax base revenues were $6.2 million higher than in 2015, driven by customer growth and higher energy sales. The quarter included more than $1 million of higher pretax base revenue from higher base rates, as a result of the 2013 rate case settlement.  

While net energy for load is a calendar measurement of retail energy sales rather than a billing-cycle measurement, the quarterly energy sales shown on the following table reflect the energy sales based on billing cycles, which can vary period to period. Retail energy sales to residential and commercial customers increased primarily from weather and customer growth.  Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy.  Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.  

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was slightly higher than in the 2015 quarter, reflecting higher costs to safely and reliably operate and maintain the generating, transmission and distribution systems, essentially offset by lower employee-related costs, primarily due to the lower level of short-term incentive accruals for all employees in 2016 compared to 2015.  Depreciation and amortization expense increased $2.0 million in 2016, as a result of normal additions to facilities to reliably serve customers, and interest expense increased $0.7 million due to higher long-term debt balances.  

A summary of Tampa Electric’s regulated operating statistics for the three months ended Mar. 31, 2016 and 2015 follows:

(millions, except average customers)	Operating Revenues								Kilowatt-hour sales
Three months ended Mar. 31,	2016			2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	217.4		$	213.4		1.9			1,914.6		1,839.4		4.1
Commercial		132.8			133.0		(0.2	)		1,388.0		1,350.1		2.8
Industrial – Phosphate		13.1			13.4		(2.4	)		163.5		167.7		(2.5	)
Industrial – Other		25.5			24.8		2.9			297.2		279.4		6.4
Other sales of electricity		39.5			40.5		(2.5	)		401.3		400.1		0.3
Deferred and other revenues (1)		(19.4	)		7.5		(360.2	)
Total energy sales	$	408.9		$	432.6		(5.5	)		4,164.6		4,036.7		3.2
Sales for resale		1.4			1.9		(25.8	)		50.3		53.5		(6.0	)
Other operating revenue		14.2			16.1		(11.6	)
Total revenues	$	424.5		$	450.6		(5.8	)		4,214.9		4,090.2		3.0
Average customers (thousands)		726.1			714.0		1.7
Retail net energy for load (kilowatt hours)										4,317.0		4,242.3		1.7
(1)     Primarily reflects the timing of environmental and fuel clause recoveries.

Tampa Electric Company – Natural Gas Division

PGS reported net income of $13.1 million for the first quarter, compared with $14.6 million in the 2015 quarter. Average customer growth was 2.4% in the quarter. Therm sales to residential customers decreased as a result of mild winter weather that was partially offset by customer growth. Sales to commercial customers increased due to customer growth from the stronger economy and increased sales of compressed natural gas to vehicle fleets.  Sales to power-generation customers and off-system sales increased, reflecting higher levels of operation by gas-fired generation in the state due to lower natural gas prices. First-quarter results in 2016 reflected non-fuel operations and maintenance expense $1.0 million higher than in 2015, driven by higher operating and compliance costs, partially offset by lower employee-related costs, primarily due to the lower level of short-term incentive accruals for all employees in 2016 compared to 2015. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers.

A summary of PGS’s regulated operating statistics for the three months ended Mar. 31, 2016 and 2015 follows:

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(millions, except average customers)	Operating Revenues						Therms
Three months ended Mar. 31,	2016		2015		% Change		2016		2015		% Change
By Customer Type
Residential	$	50.5	$	49.3		2.5		32.9		34.4		(4.2	)
Commercial		42.8		41.6		2.9		141.1		138.2		2.1
Industrial		3.3		3.2		1.6		83.5		76.1		9.6
Off system sales		12.9		7.8		65.1		53.9		23.4		130.0
Power generation		2.1		1.9		7.9		190.6		184.6		3.2
Other revenues		16.6		16.1		3.0
Total	$	128.2	$	119.9		6.8		502.0		456.7		9.9
By Sales Type
System supply	$	75.5	$	69.4		8.6		94.1		66.3		42.0
Transportation		36.1		34.4		5.1		407.9		390.4		4.5
Other revenues		16.6		16.1		3.0
Total	$	128.2	$	119.9		6.8		502.0		456.7		9.9
Average customers (thousands)		367.5		359.0		2.4

New Mexico Gas Company

NMGC reported first-quarter net income of $15.2 million, compared with $13.9 million in the 2015 period. Results reflected the benefit of heating degree days that were almost 3% higher than 2015, but nearly 7% below normal.  Growth in the average number of customers in the 2016 quarter was 0.6%. Operating and maintenance expense was slightly lower from acquisition synergies and a focus on cost control.  Results included $1.9 million of pretax rate credits to customers under the Certification of Stipulation approved by the NMPRC in 2014.

A summary of NMGC’s regulated operating statistics for the three months ended Mar. 31, 2016 and 2015 follows:

(millions, except average customers)	Operating Revenues							Therms
Three months ended Mar. 31,	2016		2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	77.7	$	87.5		(11.1	)		122.6		121.2		1.1
Commercial		19.8		23.2		(14.6	)		42.0		41.1		2.3
Industrial		0.2		0.2		(22.5	)		0.4		0.4		1.9
Off system sales		0.6		0.3		98.4			3.9		1.2		222.5
On system transportation		6.6		6.1		8.2			95.1		84.7		12.2
Off system transportation		0.2		0.2		3.4			11.1		10.3		8.0
Other revenues		1.5		1.5		(1.1	)
Total	$	106.6	$	119.0		(10.4	)		275.1		258.9		6.2
By Sales Type
System supply	$	98.3	$	111.2		(11.6	)		168.9		163.9		3.0
Transportation		6.8		6.3		8.0			106.2		95.0		11.7
Other revenues		1.5		1.5		(1.1	)
Total	$	106.6	$	119.0		(10.4	)		275.1		258.9		6.2
Average customers (thousands)		519.7		516.8		0.6

Other (net)

The first quarter 2016 cost from continuing operations for Other – net of $4.8 million included $0.1 million of costs associated with the pending Emera transaction, compared with the cost of $12.9 million in 2015, which included $0.7 million of NMGC-related integration costs.  First-quarter results in 2016 reflected a $5.8 million tax benefit due to an accounting rule change related to stock-based incentive compensation, and lower interest expense as a result of refinancing debt maturities.

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The segment data in Note 11to the TECO Energy Consolidated Condensed Financial Statementspresents Other and Eliminations as separate segments. The discussion above nets the two segments.

Discontinued Operations – TECO Coal

The sale of TECO Coal closed in September 2015. The $0.1 million first quarter gain recorded in discontinued operations reflects a refund of prepaid costs recorded in the Other – net segment, compared with a $5.8 million loss in the 2015 period, which reflected  TECO Coal’s operating results prior to its sale.

Income Taxes

The provisions for income taxes from continuing operations for the three month periods ended Mar. 31, 2016 and 2015 were $35.7 million and $39.9 million, respectively. The provision for income taxes for the three months ended Mar. 31, 2016 was impacted by higher operating income offset bya tax benefit related to long-term incentive compensation share vestings (see Note 2 to the TECO Energy Consolidated Financial Statements).

Pending Acquisition by Emera Status

· On Oct. 19, 2015, TECO Energy and Emera filed for approval of the Merger with the NMPRC Docket No. 15-00327-UT. On Apr. 11, TECO Energy and Emera announced that they had filed an unopposed stipulation with the NMPRC reflecting a settlement reached with intervening parties in the acquisition case currently pending before the NMPRC for approval of Emera’s acquisition of TECO Energy and the indirect acquisition of NMGC. This stipulation was subject to a public hearing before the hearing examiner, which was held May 2. A final recommendation by the hearing examiner and final approval by the NMPRC are required.

· On Dec. 3, 2015, TECO Energy shareholders approved the Merger with Emera.

· On Jan. 20, 2016, the FERC issued an order authorizing the Merger, finding that it is consistent with the public interest.

· On Feb. 8 the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired without comment.

· On Mar. 23, Emera announced thatthe Committee on Foreign Investment in the United States had completed its review of the acquisition of TECO Energy and had determined that there are no unresolved national security concerns with respect to the acquisition.

Liquidity and Capital Resources

The table below sets forth the Mar. 31, 2016 consolidated liquidity and cash balances, the cash balances at the operating companies and Parent, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

							TECO Finance
(millions)	Consolidated		TEC		NMGC		Parent/other
Credit facilities (1)	$	1,300.0	$	475.0	$	125.0	$	700.0
Drawn amounts/letters of credit (1)		515.2		0.5		1.7		513.0
Available credit facilities		784.8		474.5		123.3		187.0
Cash and short-term investments		46.1		28.2		3.1		14.8
Total liquidity	$	830.9	$	502.7	$	126.4	$	201.8

(1) Includes amounts under the TECO Energy/TECO Finance $400 million one-year term loan facility that was fully funded on Mar. 14, 2016.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Mar. 31, 2016. Reference is made to the specific agreements and instruments for more details.

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Significant Financial Covenants

(millions, unless otherwise indicated)
			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	Mar. 31, 2016
TEC
Credit facility (2)	Debt/capital	Cannot exceed 65%		45.9%
Accounts receivable credit facility (2)	Debt/capital	Cannot exceed 65%		45.9%
6.25% senior notes	Debt/capital Limit on liens (3)	Cannot exceed 60% Cannot exceed $700	45.9% $0 liens outstanding
NMGC
Credit facility (2)	Debt/capital	Cannot exceed 65%		28.7%
3.54% and 4.87% senior unsecured notes	Debt/capital	Cannot exceed 65%		28.7%
NMGI
2.71% and 3.64% senior unsecured notes	Debt/capital	Cannot exceed 65%		45.9%
TECO Energy/TECO Finance
Credit facility - 2013 $300 million (2)	Debt/capital	Cannot exceed 65%		61.6%
Credit facility - 2016 $400 million (2)	Debt/capital	Cannot exceed 65%		61.6%

(1) As defined in each applicable instrument.

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

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

Credit Ratings of Senior Unsecured Debt at Mar. 31, 2016

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

On Sept. 8, 2015, S&P affirmed the issuer credit rating of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance, TEC and NMGC and revised the outlook to negative from developing, following the announcement of the pending Merger with Emera.  

On Sept. 8, 2015, Moody’s Investors Service, Inc. announced that the pending Merger with Emera had no immediate impact on the senior unsecured debt ratings of TECO Energy and subsidiaries.  

On Sept. 8, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC, following the announcement of the pending Merger with Emera. On Oct. 9, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy at BBB and TEC at BBB+ and affirmed the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC. Fitch Ratings also described the ratings outlook as "Stable".

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, the credit rating agencies assign TECO Energy, TECO Finance, TEC and NMGC’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 in Item 1A of TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2015). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, the changes in value of natural gas derivatives of Tampa

44

Electric, PGS and NMGC 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.

The valuation methods used to determine fair value are described in Notes 7 and 13 to the TECO Energy Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets, goodwill and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2015.

Regulatory

PGS Compliance Activities

In 2013, the FPSC audit staff cited PGS for not fully complying with FPSC rules mostly focused on record keeping for maintenance and record keeping in two of its divisions.  PGS took immediate and significant corrective actions, including organizational, operational and system changes over the course of multiple years.

In 2015, the FPSC staff met with PGS officials to discuss perceived continuing issues associated with the PGS pipeline safety program.  PGS was presented with a summary of safety rule violations, many of which were identified during PGS’ implementation of its action plan as a result of the 2013 audit findings. Through ongoing discussions with the audit staff, PGS was made aware of concerns regarding falsification of documentation in one division.  PGS determined that leak-inspection reports in 2014 were falsified.  PGS took immediate actions to correct the findings, including reinspecting all pipes due for inspection in that division in 2014 and repaired deficiencies as appropriate.

The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the OPC filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1.0 million civil penalty and make refunds to customers of $2.0 million. The FPSC approved the settlement agreement on May 5, 2016 (see Note 10 to the TECO Energy Consolidated Financial Statements).

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK  

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to settlements of natural gas swaps and the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 5% from Dec. 31, 2015 to Mar. 31, 2016. For natural gas, the company maintained a similar volume hedged as of Mar. 31, 2016 as compared to Dec. 31, 2015.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three month period ended Mar. 31, 2016:

Change in Fair Value of Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2015	$	(26.0	)
Additions and net changes in unrealized fair value of derivatives		(9.7	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		12.6
Net fair value of derivatives as of Mar. 31, 2016	$	(23.1	)

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

Total derivative net assets (liabilities) as of Dec. 31, 2015	$	(26.0	)
Change in fair value of derivative net asset (liabilities):
Recorded as regulatory assets and liabilities or other comprehensive income		(9.7	)
Recorded in earnings		0.0
Realized net settlement of derivatives		12.6
Net fair value of derivatives as of Mar. 31, 2016	$	(23.1	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Mar. 31, 2016:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0
Other external price sources (1)		(22.3	)		(0.8	)		(23.1	)
Model prices (2)		0.0			0.0			0.0
Total	$	(22.3	)	$	(0.8	)	$	(23.1	)

(1) Reflects over-the-counter natural gas derivative contracts 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.

46

Item 4. CONTROLS AND PROCEDURES  

TECO Energy, Inc.

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

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

Tampa Electric Company

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

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

From time to time, TECO Energy and its subsidiaries are involved in 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.

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Notes 10 and 8, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

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

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

	Total Number of		Average Price		Total Number of Shares		Maximum Number (or
	Shares (or Units)		Paid per Share		(or Units) Purchased as		Approximate Dollar Value)
	Purchased (1)		(or Unit)		Part of Publicly		of Shares (or Units) that
					Announced Plans or		May Yet Be Purchased
					Programs		Under the Plans or
							Programs
Jan. 1, 2016 - Jan. 31, 2016		219,281	$	27.00	0		0
Feb. 1, 2016 - Feb. 29, 2016		6,929	$	27.42	0		0
Mar. 1, 2016 - Mar. 31, 2016		1,390	$	27.51	0		0
Total 1st Quarter 2016		227,600	$	27.02		0		0

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

Item 6. EXHIBITS

Exhibits - See index on page 50.

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SIGNATURES

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

	TECO ENERGY, INC.
	(Registrant)
Date: May 5, 2016	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: May 5, 2016	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

49

INDEX TO EXHIBITS

Exhibit
No.	Description
3.1	Amended and Restated Articles of Incorporation of TECO Energy, Inc., as filed on May 3, 2012 (Exhibit 3.1, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective May 3, 2012 (Exhibit 3.2, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*
3.3	Restated Articles of Incorporation of Tampa Electric Company, as amended on Nov. 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.1	Credit Agreement dated as of Mar. 14, 2016, 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 10.1, Form 8-K dated Mar. 14, 2016 of TECO Energy, Inc.).	*
10.2	Form of Restricted Stock Unit Award Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan, as amended.
10.3	Form of Performance-Based Restricted Stock Unit Award Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan, as amended.
12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.
31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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

50

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

51

EX-10.2

Exhibit 10.2

RESTRICTED STOCK UNIT AWARD AGREEMENT

UNDER THE TECO ENERGY, INC.

2010 EQUITY INCENTIVE PLAN

This Award Agreement (this “RSU Award Agreement”), dated as of February 3, 2016 (the “Date of Grant”), is made by and between TECO Energy, Inc., a Florida corporation (the “Company”), and [______________](the “Grantee”).  Capitalized terms not defined herein shall have the meanings given to them in the Company’s 2010 Equity Incentive Plan (the “Plan”).  Where the context permits, references to “the Company” shall include the Company and any successor to the Company.

1.Grant of Restricted Stock Units.  The Company hereby grants to the Grantee [_______] restricted stock units (the “RSUs”), subject to all of the terms and conditions of this RSU Award Agreement and the Plan.

2.Vesting.  Provided that the Grantee remains in Continuous Service through the applicable event listed in Subsections 2(a) through 2(g) below, and further provided that in event of vesting pursuant to subsections 2(b) – 2(f), that the performance goal set forth in Schedule A has been satisfied, the RSUs will vest on the earliest to occur of such events (each a “Vesting Date”).  “Continuous Service” means remaining in the continuous service as an employee of the Company or any business entity in which the Company owns directly or indirectly 50% or more of the total voting power or has a significant financial interest as determined by the Committee (an “Affiliate”).  If the Grantee ceases to remain in Continuous Service through the applicable Vesting Date set forth in Subsections 2(a) and 2(b) below (other than for the reasons specified in Subsections 2(c) through 2(g) below), the RSUs will be cancelled and forfeited without the payment of any consideration in respect thereof.

(a) On the Closing Date, as such term is defined in the Agreement and Plan of Merger by and among the Company, Emera Inc. and Emera US Inc., dated as of September 4, 2015, as the same may be amended from time to time (the “Merger Agreement”), provided that if the Closing Date does not occur or the Merger Agreement is terminated prior to the occurrence of the Closing Date, this Subsection 2(a) shall be null and void and have no further force and effect;

(b) On the third anniversary of the Date of Grant;  

(c) Upon the termination of the Grantee’s employment with the Company or any Affiliate because of a disability that would entitle the Grantee to benefits under the long-term disability benefits program of the Company for which the Grantee is eligible, as determined by the Committee, the restrictions on a prorated portion of the RSUs will terminate based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36, and all other RSUs will be cancelled and forfeited without the payment of any consideration in respect thereof;

(d)Upon the termination by the Company or any Affiliate of the Grantee’s employment other than for Cause (as defined below), the restrictions on a prorated portion of the RSUs will terminate based on the number of months the Grantee was employed (with partial

months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36, and all other RSUs will be cancelled and forfeited without the payment of any consideration in respect thereof.  For purposes of this Subsection 2(d), termination for “Cause” means any termination effected through the Company’s Positive Discipline program (or any successor thereto). (Provided, however, if termination of the Grantee’s employment occurs within 36 months following a Change in Control (as defined in Subsection 2(g)), or prior to a Change in Control under circumstances described in Subsection 2(g), then “Cause” shall be defined as provided in that subsection.);  

(e)Upon a termination of the Grantee’s employment that the Committee determines will constitute a normal retirement for purposes of this RSU Award Agreement, the restrictions on a prorated portion of the RSUs will terminate based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36, and all other RSUs will be cancelled and forfeited without the payment of any consideration in respect thereof;

(f)Upon the Grantee’s death, the restrictions on a prorated portion of RSUs will terminate based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of the Grantee’s death, divided by 36, and all other RSUs will be cancelled and forfeited without the payment of any consideration in respect thereof; or

(g)Upon the termination of the Grantee’s employment other than by the Company for Cause or by the Grantee without Good Reason within 36 months following a Change in Control, or prior to a Change in Control under circumstances described in the next sentence.  For purposes of this RSU Award Agreement, the Grantee’s employment shall be deemed to have been terminated following a Change in Control of the Company by the Company without Cause or by the Grantee with Good Reason, if (i) the Grantee’s employment is terminated by the Company without Cause prior to a Change in Control of the Company (whether or not such a Change in Control ever occurs) and such termination was at the request or direction of a “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) who has entered into an agreement with the Company the consummation of which would constitute a Change in Control of the Company, (ii) the Grantee terminates the Grantee’s employment for Good Reason prior to a Change in Control of the Company (whether or not such a Change in Control ever occurs) and the circumstance or event which constitutes Good Reason occurs at the request or direction of such person, or (iii) the Grantee’s employment is terminated by the Company without Cause or by the Grantee for Good Reason and such termination or the circumstance or event which constitutes Good Reason is otherwise in connection with or in anticipation of a Change in Control of the Company (whether or not such a Change in Control ever occurs).

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

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

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

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

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

(ii)  “Good Reason” for termination by the Grantee of the Grantee’s employment shall mean the occurrence (without the Grantee’s express written consent) after any Change in Control of the Company, or prior to a Change in Control of the Company under the circumstances described in the second sentence of Subsection 2(g) hereof (treating all references in paragraphs (a) through (h) below to a “Change in Control of the Company” as references to a “potential Change in Control of the Company”), of any one of the following acts by the Company, or failures by the Company to act:

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

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

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

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

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

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

(g)the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform this RSU Award Agreement, as contemplated in Section 11 hereof; or

(h)any purported termination of the Grantee’s employment which is not effected pursuant to a Notice of Termination satisfying the requirements of Subsection 2(g)(iii) below (and, if applicable, the requirements of Subsection 2(d) above), which purported termination shall not be effective for purposes of this RSU Award Agreement.

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

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

(iv) For purposes of this Subsection 2(g), “Cause” means

(a) the willful and continued failure by the Grantee to substantially perform the Grantee’s duties with the Company (other than any such failure resulting from the Grantee’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination by the Grantee for Good Reason, each as defined in Subsection 2(g) after a written demand for substantial performance is delivered to the Grantee by the Board, which demand specifically identifies the manner in which the Board believes that the Grantee has not substantially performed the Grantee’s duties; or

(b) the willful engaging by the Grantee in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise.  

For purposes of this Subsection, no act, or failure to act, on the Grantee’s part will be deemed “willful” unless done, or omitted to be done, by the Grantee not in good faith and without reasonable belief that the Grantee’s action or omission was in the best interest of the Company.  Notwithstanding the foregoing, the Grantee will not be deemed to have been terminated for Cause unless and until there will have been delivered to the Grantee a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters (3/4) of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice to the Grantee and an opportunity for the Grantee, together with the Grantee’s counsel, to be heard before the Board), finding that in the good faith opinion of the Board the Grantee was guilty of conduct set forth above in this Subsection and specifying the particulars thereof in detail.

3.RSU Settlement.  Each RSU granted hereunder shall represent the right to receive:

(a) in the event vesting occurs pursuant to Subsection 2(a) of this RSU Award Agreement: (x) a lump-sum cash payment as calculated pursuant to Section 2.03(c) of the Merger Agreement and (y) a Cash Service Award as defined in the Merger Agreement and calculated pursuant to Section 2.03(d) of the Merger Agreement, which Cash Service Award will be settled pursuant to Section 4 of this RSU Award Agreement; or

(b) in the event vesting occurs pursuant to Subsections 2(b) through (g) of this RSU Award Agreement, in the sole discretion of the Committee, either (x) one share of Common Stock (a “Share”) or (y) an amount of cash equal to the Fair Market Value of one Share, valued based on the closing price of a Share on the date immediately prior to the date of payment (as applicable, the “Settlement”).

The Settlement shall occur as soon as practicable after the applicable Vesting Date, but in no event later than 45 days after the Vesting Date with respect to vesting pursuant to Sections 2(b) through (g) of this RSU Award Agreement, or no later than as provided in the Merger Agreement with respect to vesting pursuant to Section 2(a) of this RSU Award Agreement.  

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4.Cash Service Award Settlement. Provided that the Grantee remains in Continuous Service through the applicable event listed below, the Cash Service Award will vest and be settled on the earliest to occur of the events listed in Subsections 2(b) through 2(g) of this RSU Award Agreement (each a “Cash Service Award Settlement Date”). As promptly as practicable following the applicable Cash Service Award Settlement Date, the Company will pay, less applicable tax withholdings, the Cash Service Award, which in the case of settlement pursuant to Subsections 2(c) through 2(f) of this RSU Award Agreement, will be prorated based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the day after the Closing Date to the date of termination, divided by the number of months between the Closing Date and February 3, 2019. In the case of settlement of the Cash Service Award pursuant to Subsection 2(g) of this RSU Award Agreement, a Change in Control shall be deemed to have occurred (i) on the Closing Date, as such term is defined in the Merger Agreement and (ii) upon the consummation of any other Change in Control transaction under the circumstances described in Subsection 2(g)(i) of this RSU Award Agreement.

5.Voting and Other Rights; Dividend Equivalents.  

(a)The Grantee shall have no rights of a shareholder with respect to the RSUs (including the right to vote and the right to receive distributions or dividends, except as provided in Subsection 5(b) below) unless and until Shares are issued in respect thereof following the Settlement.  The Grantee shall have no rights of a shareholder with respect to a Cash Service Award.

(b) If, prior to the Settlement, the Company declares a dividend on its Shares, then, dividend equivalents in an amount equal to the dividends that would have been paid to the Grantee if one Share had been issued on the Grant Date for each RSU granted to the Grantee as set forth in this RSU Award Agreement (“Dividend Equivalents”), will be accrued on the Grantee’s behalf on the payment date of such dividend, and the Company shall pay currently (and in no case later than the next regular payroll cycle following the payment date), in cash, an amount equal to the Dividend Equivalents with respect to the Grantee’s RSUs, subject to applicable tax withholding.

6.RSU Award Agreement Subject to Plan.  This RSU Award Agreement is made pursuant to all of the provisions of the Plan, which is incorporated herein by this reference, and is intended, and shall be interpreted in a manner, to comply therewith.  In the event of any conflict between the provisions of this RSU Award Agreement and the provisions of the Plan, the provisions of the Plan shall govern.

7.No Rights to Continuation of Employment.  Nothing in the Plan or this RSU Award Agreement shall confer upon the Grantee any right to continue in the employ of the Company or any Affiliate thereof or shall interfere with or restrict the right of the Company or its Affiliates to terminate the Grantee’s employment any time for any reason whatsoever, with or without cause.

8.Tax Withholding.  The Company shall be entitled to require a cash payment by or on behalf of the Grantee and/or to deduct from the cash or Shares otherwise

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issuable hereunder or other compensation payable to the Granteethe minimum amount of any sums required by federal, state or local tax law to be withheld or to satisfy any applicable payroll deductions with respect to the Settlement of any RSUor Cash Service Award or payment of Dividend Equivalents.   

9.Section 409A Compliance.  The intent of the parties is that payments and benefits under this RSU Award Agreement comply with Section 409A of the Code, to the extent subject thereto, and accordingly, to the maximum extent permitted, this RSU Award Agreement shall be interpreted and administered to be in compliance therewith. Notwithstanding anything contained herein to the contrary, the Grantee shall not be considered to have terminated employment with the Company for purposes of any payments under this RSU Award Agreement which are subject to Section 409A of the Code until the Grantee would be considered to have incurred a “separation from service” from the Company within the meaning of Section 409A of the Code. Each amount to be paid or benefit to be provided under this RSU Award Agreement shall be construed as a separate identified payment for purposes of Section 409A of the Code. Without limiting the foregoing and notwithstanding anything contained herein to the contrary, to the extent required in order to avoid accelerated taxation and/or tax penalties under Section 409A of the Code, amounts that would otherwise be payable and benefits that would otherwise be provided pursuant to this RSU Award Agreement or any other arrangement between the Grantee and the Company during the six-month period immediately following the Grantee’s separation from service shall instead be paid on the first business day after the date that is six months following the Grantee’s separation from service (or, if earlier, the Grantee’s date of death).The Company makes no representation that any or all of the payments described in this RSU Award Agreement will be exempt from or comply with Section 409A of the Code and makes no undertaking to preclude Section 409A of the Code from applying to any such payment.

10.Governing Law.  This RSU Award Agreement shall be governed by, interpreted under, and construed and enforced in accordance with the internal laws, and not the laws pertaining to conflicts or choices of laws, of the State of Florida.

11.RSU Award Agreement Binding on Successors.  The terms of this RSU Award Agreement shall be binding upon the Grantee and upon the Grantee’s heirs, executors, administrators, personal representatives, transferees, assignees and successors in interest, and upon the Company and its successors and assignees, subject to the terms of the Plan.  

12.No Assignment.  Notwithstanding anything to the contrary in this RSU Award Agreement, neither this RSU Award Agreement nor any rights granted herein shall be assignable by the Grantee.

13.Necessary Acts.  The Grantee hereby agrees to perform all acts, and to execute and deliver any documents that may be reasonably necessary to carry out the provisions of this RSU Award Agreement, including but not limited to all acts and documents related to compliance with federal and/or state securities and/or tax laws.

14.Severability.  Should any provision of this RSU Award Agreement be held by a court of competent jurisdiction to be unenforceable, or enforceable only if modified, such holding shall not affect the validity of the remainder of this RSU Award Agreement, the balance of which shall continue to be binding upon the parties hereto with any such modification (if any)

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to become a part hereof and treated as though contained in this original RSU Award Agreement.  Moreover, if one or more of the provisions contained in this RSU Award Agreement shall for any reason be held to be excessively broad as to scope, activity, subject or otherwise so as to be unenforceable, in lieu of severing such unenforceable provision, such provision or provisions shall be construed by the appropriate judicial body by limiting or reducing it or them, so as to be enforceable to the maximum extent compatible with the applicable law as it shall then appear, and such determination by such judicial body shall not affect the enforceability of such provisions or provisions in any other jurisdiction. 

15.Entire RSU Award Agreement.  This RSU Award Agreement and the Plan contain the entire agreement and understanding among the parties as to the subject matter hereof, and supersede any other agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof.

16.Headings.  Headings are used solely for the convenience of the parties and shall not be deemed to be a limitation upon or descriptive of the contents of any such Section.

17.Counterparts; Electronic Signature.  This RSU Award Agreement may be executed in counterparts, each of which shall be deemed to be an original and both of which together shall be deemed to be one and the same instrument.  The Grantee’s electronic signature of this RSU Award Agreement shall have the same validity and effect as a signature affixed by the Grantee’s hand.

18.Amendment.  No amendment or modification hereof shall be valid unless it shall be in writing and signed by all parties hereto.

[Signature Page Follows]

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IN WITNESS WHEREOF, the parties hereto have executed this RSU Award Agreement as of the date set forth above. 

TECO ENERGY, INC.

By: ______________________

Phil L. Barringer

Chief Human Resources Officer

_________________________
Grantee

[Signature Page to RSU Award Agreement (Time-Based)]

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SCHEDULE A

The “Performance Period” is the period beginning January 1, 2016 and ending on December 31, 2018, unless one of the events specified in Subsections 2(c) through 2(g) (an “Early Termination Event”) occurs, in which case the Performance Period will end on the last day of the quarter following the Early Termination Event, unless the Early Termination Event occurs on a date that would cause the Performance Period to be shorter than four times as long as the period between the beginning of the Performance Period and the date of this Agreement, then the Performance Period will end on the last day of the quarter after that period of time has elapsed.

The “Performance Goal” for the Performance Period is earnings before interest, taxes, depreciation and amortization (“EBITDA”) of at least $__________, which shall be adjusted to exclude the effect of any of the following events that impact EBITDA: (i) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture (including a spin-off) or any other change in corporate structure or shares; (ii) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business; (iii) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results; or (iv) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Principles Board Opinion No. 30, provided that the exclusion of the impact of the foregoing specified events from the calculation of a Performance Goal shall only be made to the extent permitted by Section 162(m) of the Code.  If the Performance Period ends prior to December 31, 2018 due to the occurrence of an Early Termination Event, the Performance Goal shall be prorated for the number of quarters that elapsed, beginning on January 1, 2016 and ending on the last day of the quarter following the Early Termination Event.

If the Performance Period ends on December 31, 2018 (that is, if an Early Termination Event has not occurred prior to that date), the “Vesting Date” is the date of the Compensation Committee’s certification that the Performance Goal has been achieved according to the terms of this paragraph, on which date, if the Performance Goal is achieved, the RSUs will vest, subject to any restrictions on distributions of shares under the Plan and subject to Section 8 of this Agreement.    If an Early Termination Event occurs, the Vesting Date is the date as soon as practicable after the end of the Performance Period on which the shares shall vest, or on the Compensation Committee certification date, if such certification is required under Section 162(m) of the Internal Revenue Code.  If the Compensation Committee’s certification is required under Section 162(m) of the Internal Revenue Code, promptly after the end of the Performance Period, the Company will submit its calculation regarding the Performance Goal to the Compensation Committee for certification.  In no event will the Vesting Date be more than 45 days after the end of the Performance Period.    

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EX-10.3

Exhibit 10.3

PERFORMANCE-BASED RESTRICTED STOCK UNIT AWARD AGREEMENT

UNDER THE TECO ENERGY, INC.

2010 EQUITY INCENTIVE PLAN

This Award Agreement (this “RSU Award Agreement”), dated as of February 3, 2016 (the “Date of Grant”), is made by and between TECO Energy, Inc., a Florida corporation (the “Company”), and[______________](the “Grantee”).  Capitalized terms not defined herein shall have the meanings given to them in the Company’s 2010 Equity Incentive Plan (the “Plan”).  Where the context permits, references to “the Company” shall include the Company and any successor to the Company.

1.Grant of Restricted Stock Units.  The Company hereby grants to the Grantee [_______]restricted stock units (the “RSUs”), subject to all of the terms and conditions of this RSU Award Agreement and the Plan.  The number of RSUs set forth in this Section 1 are referred to as the “Target RSUs” for purposes of this RSU Award Agreement. The Target RSUs, if not previously forfeited, will vest based on the achievement of the Performance Measurement determined pursuant to Schedule A hereto, or pursuant to Section 5 hereof in the event of a Change in Control.  In addition to the Target RSUs, after the end of the Performance Period (as defined on Schedule A hereto), the Grantee may receive additional RSUs based on the achievement of the Performance Measurement determined pursuant to Schedule A hereto.  These additional RSUs are referred to in this RSU Award Agreement as the “Additional Performance RSUs”, and together with the Target RSUs, are referred to as the “Performance RSUs”.  Provided, however, no Performance Shares shall vest unless the “Executive Officer Performance Goal” set forth in Schedule C has been satisfied. Upon vesting, the RSUs will be settled pursuant to Subsection 6(b) below.

2.Closing Date Pursuant to the Merger Agreement.  

(a)Notwithstanding anything herein to the contrary, if the Closing Date occurs (as such term is defined in the Agreement and Plan of Merger by and among the Company, Emera Inc. and Emera US Inc., dated as of September 4, 2015, as the same may be amended from time to time (the “Merger Agreement”)) and (i) the Grantee remains in continuous service as an employee of the Company or any business entity in which the Company owns directly or indirectly 50% or more of the total voting power or has a significant financial interest as determined by the Committee (an “Affiliate”) through the Closing Date or (ii) the Grantee’s employment is terminated by the Company without Cause or by the Grantee for Good Reason prior to the Closing Date under the circumstances described in the second sentence of Section 5 (substituting “Closing Date” for “Change in Control of the Company” or “Change in Control” in each place in which it appears therein), then the maximum number of Performance RSUs will vest on the Closing Date based on the application of the formula defined in Schedule A hereto as if the maximum Performance Reward Percentage and the TSR Bonus Multiplier is achieved.  Such RSUs will be settled in accordance with Subsection 6(a) below.

(b) Except as provided in Section 2(a), if, prior to the Closing Date, (i) the Company or any Affiliate terminates the Grantee's employment other than for Cause, as such term is defined in Subsection 4(a) or (ii) the Grantee’s employment with the Company or any Affiliate is terminated at any time prior to Closing Date due to death, a disability that would entitle the Grantee to benefits under the long-term disability benefits program of the Company

for which the Grantee is eligible, as determined by the Committee, or retirement at or after any date that the Committee determines will constitute a normal retirement for purposes of this RSU Award Agreement, the Grantee’s Target RSUs will be prorated based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36(the “Subsection 2(b) Prorated Target RSUs”).  If the Closing Date occurs on or prior to December 31 of the year in which such termination of employment occurs, the maximum number of Subsection 2(b) Prorated Target RSUs will vest on the Closing Date based on the application of the formula defined in Schedule A hereto, with the Subsection 2(b) Prorated Target RSUs substituted for the Target RSUs in such formula, as if the maximum Performance Reward Percentage and the TSR Bonus Multiplier is achieved, and such RSUs will be settled in accordance with Subsection 6(a) below.  If the Closing Date does not occur on or prior to December 31 of the year in which such termination of employment occurs, then the Performance Period will end and the number of Subsection 2(b) Prorated Target RSUs that will vest pursuant to this RSU Award Agreement, if any, will be determined based on the application of the formula defined in Schedule A hereto, with the Subsection 2(b) Prorated Target RSUs substituted for the Target RSUs in such formula, and such Performance RSUs will be settled in accordance with Section 6(b) hereof.All other outstanding Subsection 2(b) ProratedTarget RSUs that do not vest pursuant to that formula will be cancelled and forfeited, and any associated accrued dividends will be forfeited and retained by the Company. 

(c)In the event that the Closing Date does not occur or the Merger Agreement is terminated prior to the occurrence of the Closing Date, this Section 2 shall be null and void and have no further force and effect.

3.Certification and Vesting Date.  Except as provided in Section 2 hereof, promptly after the end of the Performance Period, the Company will calculate the number of Performance RSUs that will vest and the amount of dividends payable to the Grantee upon Settlement (as defined below) pursuant to this RSU Award Agreement and will submit its calculation regarding the Performance Measurement, the corresponding Performance Reward Percentage and the TSR Bonus Multiplier, if any, to the Committee for certification. Subject to any restrictions on distributions of shares of Common Stock (“Shares”) under the Plan, and except as otherwise provided in Section 5, the Performance RSUs, if any, will vest as of the last day of the Performance Period, or on the date of the Committee’s certification of the number of RSUs payable pursuant to this RSU Award Agreement (the “Vesting Date”), provided that in no event will the Vesting Date be more than 45 days after the end of the Performance Period.

4.Termination of Employment.

(a)Voluntary Termination or Termination with Cause. If before December 31, 2018, the Grantee terminates his or her employment with the Company or any Affiliate and Subsection 4(c) does not apply to such termination, or the Company or any Affiliate terminates the Grantee’s employment for Cause (as defined below), all of the Grantee’s Target RSUs will be cancelled as of the date of such termination and any dividends accrued with respect to the Grantee’s Target RSUs will be forfeited. The Grantee will not be entitled to any Additional Performance RSUs. For purposes of this Subsection 4(a), “Cause” means any termination effected through the Company’s Positive Discipline program (or any successor thereto). (Provided, however, if termination occurs within 36 months following a Change in

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Control (as defined in Subsection 5(i) hereof), or prior to a Change in Control under circumstances described in Section 5 hereof, then “Cause” shall be defined as provided in that Section.) 

(b)Termination Other than for Cause. If the Company or any Affiliate terminates the Grantee's employment other than for Cause before December 31, 2018, the Grantee’s Target RSUs will be prorated based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36 (the “Subsection 4(b) Prorated Target RSUs”). On the last business day of the year in which the termination occurred, the Performance Period will end and the number of Performance RSUs that vest pursuant to this RSU Award Agreement, if any, will be determined based on the application of the formula defined in Schedule A hereto, with the Subsection 4(b) Prorated Target RSUs substituted for the Target RSUs in such formula. Such Performance RSUs will be settled in accordance with Section 6 hereof.  All other outstanding Target RSUs that do not vest pursuant to that formula will be cancelled and forfeited, and any associated accrued dividends will be forfeited and retained by the Company.

(c)Termination Due to Death, Disability or Retirement. If the Grantee’s employment with the Company or any Affiliate is terminated at any time prior to December 31, 2018, due to death, a disability that would entitle the Grantee to benefits under the long-term disability benefits program of the Company for which the Grantee is eligible, as determined by the Committee, or retirement at or after any date that the Committee determines will constitute a normal retirement for purposes of this RSU Award Agreement, the Grantee’s Target RSUs will be prorated based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this RSU Award Agreement to the date of termination, divided by 36 (the “Subsection 4(c) Prorated Target RSUs”). On the last business day of the year in which the termination occurred, the Performance Period will end and the number of Performance RSUs that vest pursuant to this RSU Award Agreement, if any, will be determined based on the application of the formula defined in Schedule A hereto, with the Subsection 4(c) Prorated Target RSUs substituted for the Target RSUs in such formula. Such Performance RSUs will be settled in accordance with Section 6 hereof.  All other outstanding Target RSUs that do not vest pursuant to that formula will be cancelled and forfeited, and any associated accrued dividends will be forfeited and retained by the Company.

5.Change in Control.  If, prior to December 31, 2018, the Grantee’s employment is terminated other than by the Company for Cause or by the Grantee without Good Reason within 36 months following a Change in Control (as defined below), or prior to a Change in Control under circumstances described in the next sentence, then (i) if the Change in Control occurs after December 31, 2016, the Performance Period will end on the last day of the year prior to the year in which the Change in Control occurred and the Grantee’s RSUs will vest as determined under Schedule A hereto, or (ii) if the Change in Control occurs before December 31, 2016, then the Grantee’s Target RSUs will vest.  For purposes of this RSU Award Agreement, the Grantee’s employment shall be deemed to have been terminated following a Change in Control of the Company by the Company without Cause or by the Grantee with Good Reason, if (i) the Grantee’s employment is terminated by the Company without Cause prior to a Change in Control of the Company (whether or not such a Change in Control ever occurs) and such termination was at the request or

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direction of a “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) who has entered into an agreement with the Company the consummation of which would constitute a Change in Control of the Company, (ii) the Grantee terminates the Grantee’s employment for Good Reason prior to a Change in Control of the Company (whether or not such a Change in Control ever occurs) and the circumstance or event which constitutes Good Reason occurs at the request or direction of such person, or (iii) the Grantee’s employment is terminated by the Company without Cause or by the Grantee for Good Reason and such termination or the circumstance or event which constitutes Good Reason is otherwise in connection with or in anticipation of a Change in Control of the Company (whether or not such a Change in Control ever occurs). If a Change in Control occurs prior to December 31, 2018, and the Grantee remains continuously employed through that date by the Company’s successor or any business entity in which such successor owns directly or indirectly 50% or more of the total voting power or has a significant financial interest as determined by the Committee, then the Grantee’s Target RSUs shall vest as soon as practicable after December 31, 2018. 

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

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

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

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

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defined) acquires 30% or more of the combined voting power of the Company’s then outstanding securities; or 

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

(ii)“Good Reason” for termination by the Grantee of the Grantee’s employment shall mean the occurrence (without the Grantee’s express written consent) after any Change in Control of the Company, or prior to a Change in Control of the Company under the circumstances described in the second sentence of Section 5 hereof (treating all references in paragraphs (a) through (h) below to a “Change in Control of the Company” as references to a “potential Change in Control of the Company”), of any one of the following acts by the Company, or failures by the Company to act:

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

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

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

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

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

(f)the failure by the Company to continue to provide the Grantee with benefits substantially similar to those enjoyed by the Grantee under any of the Company’s pension, life insurance, medical, health and accident, or disability plans in which the Grantee were participating at the time of the Change in Control of the Company, the taking of any action by the Company which would directly or indirectly materially reduce any of such

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benefits or deprive the Grantee of any material fringe benefit enjoyed by the Grantee at the time of the Change in Control of the Company, or the failure by the Company to provide the Grantee with the number of paid vacation days to which the Grantee are entitled on the basis of the Grantee’s years of service with the Company in accordance with the Company’s normal vacation policy in effect at the time of the Change in Control of the Company; 

(g)the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform this RSU Award Agreement, as contemplated in Section 14 hereof; or

(h)any purported termination of the Grantee’s employment which is not effected pursuant to a Notice of Termination satisfying the requirements of Subsection 5(iii) below (and, if applicable, the requirements of Subsection 4(b) above), which purported termination shall not be effective for purposes of this RSU Award Agreement.

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

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

(iv) For purposes of this Section 5, “Cause” means

(a) the willful and continued failure by the Grantee to substantially perform the Grantee’s duties with the Company (other than any such failure resulting from the Grantee’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination by the Grantee for Good Reason, each as defined in this Section 5 after a written demand for substantial performance is delivered to the Grantee by the Board, which demand specifically identifies the manner in which the Board believes that the Grantee has not substantially performed the Grantee’s duties; or

(b) the willful engaging by the Grantee in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise.  

For purposes of this Subsection, no act, or failure to act, on the Grantee’s part will be deemed “willful” unless done, or omitted to be done, by the Grantee not in good faith and without reasonable belief that the Grantee’s action or omission was in the best interest of the Company.  Notwithstanding the foregoing, the Grantee will not be deemed to have been terminated for Cause unless and until there will have been delivered to the Grantee a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters (3/4) of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice to the Grantee and an opportunity for the Grantee, together with the Grantee’s counsel, to be heard before the Board), finding that in the good faith opinion of the Board the

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Grantee was guilty of conduct set forth above in this Subsection and specifying the particulars thereof in detail.

6.RSU Settlement.  Each RSU granted hereunder shall represent the right to receive:

(a) in the event vesting occurs pursuant to Section 2 of this RSU Award Agreement: (x) a lump-sum cash payment as calculated pursuant to Section 2.03(e) of the Merger Agreement and (y) an Additional Cash Service Award as defined in the Merger Agreement and calculated pursuant to Section 2.03(f) of the Merger Agreement, which Additional Cash Service Award will be settled pursuant to Section 7 of this RSU Award Agreement; or

(b) in the event vesting occurs pursuant to Section 3, 4 or 5 of this RSU Award Agreement, in the sole discretion of the Committee, either (x) one Share or (y) an amount of cash equal to the Fair Market Value of one Share, valued based on the closing price of a Share on the date immediately prior to the date of payment (as applicable, the “Settlement”).

In either case, the Settlement shall occur as soon as practicable after the applicable Vesting Date, but in no event later than 45 days after the Vesting Date with respect to vesting pursuant to Section 3, 4 or 5 of this RSU Award Agreement, or no later than as provided in the Merger Agreement with respect to vesting pursuant to Section 2 of this RSU Award Agreement.   

7.Additional Cash Service Award Settlement. Provided that the Grantee remains in continuous service as an employee of the Company or any Affiliate through the applicable event listed below, the Additional Cash Service Award will vest and be settled on the earliest to occur of December 31, 2018 or any of the events listed in Subsections 4(b) and 4(c) and Section 5 of this RSU Award Agreement (each a “Additional Cash Service Award Settlement Date”). As promptly as practicable following the applicable Additional Cash Service Award Settlement Date, the Company will pay, less applicable tax withholdings, the Additional Cash Service Award, which in the case of settlement pursuant to Subsections 4(b) and 4(c) hereof, will be prorated based on the number of months the Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the day after the Closing Date to the date of termination, divided by the number of months between the Closing Date and December 31, 2018.  In the case of settlement of the Additional Cash Service Award pursuant to Section 5 of this RSU Award Agreement, a Change in Control shall be deemed to have occurred (i) on the Closing Date, as such term is defined in the Merger Agreement and (ii) upon the consummation of any other Change in Control transaction under the circumstances described in Subsection 5(i) of this RSU Award Agreement.  

8.Voting and Other Rights; Dividend Equivalents.  

(a)The Grantee shall have no rights of a shareholder with respect to the RSUs (including the right to vote and the right to receive distributions or dividends, except as provided in Subsection 8(b) below) unless and until Shares are issued in respect thereof following the Settlement.  The Grantee shall have no rights of a shareholder with respect to an Additional Cash Service Award.  

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(b) If, prior to the Settlement, the Company declares a dividend on itsShares, then, dividend equivalents in an amount equal to the dividends that would have been paid to the Grantee if one Share had been issued on the Grant Date for each RSU granted to the Grantee as set forth in this RSU Award Agreement (“Dividend Equivalents”), will be accrued on the Grantee’s behalf on the payment date of such dividend, subject to forfeiture as set forth in the last sentence of this paragraph.   If the RSUs vest in accordance with this RSU Award Agreement, the Grantee will receive a cash payment equal to the amount of any dividends accrued prior to the Settlement, and such amount will be multiplied by the same Performance Reward Percentage and TSR Bonus Multiplier, if any, used to determine the amount of PerformanceRSUs that vest.  Any dividends earned pursuant to this Section will be paid in cash to the Grantee upon the Settlement or as soon as practicable thereafter. Any dividends accrued with respect to the RSUs will be forfeited if the related RSUs are forfeited.   

9.RSU Award Agreement Subject to Plan.  This RSU Award Agreement is made pursuant to all of the provisions of the Plan, which is incorporated herein by this reference, and is intended, and shall be interpreted in a manner, to comply therewith.  In the event of any conflict between the provisions of this RSU Award Agreement and the provisions of the Plan, the provisions of the Plan shall govern.

10.No Rights to Continuation of Employment.  Nothing in the Plan or this RSU Award Agreement shall confer upon the Grantee any right to continue in the employ of the Company or any Affiliate thereof or shall interfere with or restrict the right of the Company or its Affiliates to terminate the Grantee’s employment any time for any reason whatsoever, with or without cause.

11.Tax Withholding.  The Company shall be entitled to require a cash payment by or on behalf of the Grantee and/or to deduct from the cash or Shares otherwise issuable hereunder or other compensation payable to the Grantee the minimum amount of any sums required by federal, state or local tax law to be withheld or to satisfy any applicable payroll deductions with respect to the Settlement of any RSU or Additional Cash Service Award or payment of Dividend Equivalents.  

12.Section 409A Compliance.  The intent of the parties is that payments and benefits under this RSU Award Agreement comply with Section 409A of the Code, to the extent subject thereto, and accordingly, to the maximum extent permitted, this RSU Award Agreement shall be interpreted and administered to be in compliance therewith. Notwithstanding anything contained herein to the contrary, the Grantee shall not be considered to have terminated employment with the Company for purposes of any payments under this RSU Award Agreement which are subject to Section 409A of the Code until the Grantee would be considered to have incurred a “separation from service” from the Company within the meaning of Section 409A of the Code. Each amount to be paid or benefit to be provided under this RSU Award Agreement shall be construed as a separate identified payment for purposes of Section 409A of the Code. Without limiting the foregoing and notwithstanding anything contained herein to the contrary, to the extent required in order to avoid accelerated taxation and/or tax penalties under Section 409A of the Code, amounts that would otherwise be payable and benefits that would otherwise be provided pursuant to this RSU Award Agreement or any other arrangement between the Grantee and the Company during the six-month period immediately following the Grantee’s separation from service shall instead be paid on the first business day after the date that is six months

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following the Grantee’s separation from service (or, if earlier, the Grantee’s date of death).The Company makes no representation that any or all of the payments described in this RSU Award Agreement will be exempt from or comply with Section 409A of the Code and makes no undertaking to preclude Section 409A of the Code from applying to any such payment. 

13.Governing Law.  This RSU Award Agreement shall be governed by, interpreted under, and construed and enforced in accordance with the internal laws, and not the laws pertaining to conflicts or choices of laws, of the State of Florida.

14.RSU Award Agreement Binding on Successors.  The terms of this RSU Award Agreement shall be binding upon the Grantee and upon the Grantee’s heirs, executors, administrators, personal representatives, transferees, assignees and successors in interest, and upon the Company and its successors and assignees, subject to the terms of the Plan.  

15.No Assignment.  Notwithstanding anything to the contrary in this RSU Award Agreement, neither this RSU Award Agreement nor any rights granted herein shall be assignable by the Grantee.

16.Necessary Acts.  The Grantee hereby agrees to perform all acts, and to execute and deliver any documents that may be reasonably necessary to carry out the provisions of this RSU Award Agreement, including but not limited to all acts and documents related to compliance with federal and/or state securities and/or tax laws.

17.Severability.  Should any provision of this RSU Award Agreement be held by a court of competent jurisdiction to be unenforceable, or enforceable only if modified, such holding shall not affect the validity of the remainder of this RSU Award Agreement, the balance of which shall continue to be binding upon the parties hereto with any such modification (if any) to become a part hereof and treated as though contained in this original RSU Award Agreement.  Moreover, if one or more of the provisions contained in this RSU Award Agreement shall for any reason be held to be excessively broad as to scope, activity, subject or otherwise so as to be unenforceable, in lieu of severing such unenforceable provision, such provision or provisions shall be construed by the appropriate judicial body by limiting or reducing it or them, so as to be enforceable to the maximum extent compatible with the applicable law as it shall then appear, and such determination by such judicial body shall not affect the enforceability of such provisions or provisions in any other jurisdiction.

18.Entire RSU Award Agreement.  This RSU Award Agreement and the Plan contain the entire agreement and understanding among the parties as to the subject matter hereof, and supersede any other agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof.

19.Headings.  Headings are used solely for the convenience of the parties and shall not be deemed to be a limitation upon or descriptive of the contents of any such Section.

20.Counterparts; Electronic Signature.  This RSU Award Agreement may be executed in counterparts, each of which shall be deemed to be an original and both of which together shall be deemed to be one and the same instrument.  The Grantee’s electronic signature

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of this RSU Award Agreement shall have the same validity and effect as a signature affixed by the Grantee’s hand. 

21.Amendment.  No amendment or modification hereof shall be valid unless it shall be in writing and signed by all parties hereto.

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IN WITNESS WHEREOF, the parties hereto have executed this RSU Award Agreement as of the date set forth above. 

TECO ENERGY, INC.

By: ______________________

Phil L. Barringer

Chief Human Resources Officer

_________________________
Grantee

[Signature Page to Performance-Based RSU Award Agreement]

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SCHEDULE A – PERFORMANCE MEASUREMENT

Upon the Vesting Date (as defined in Section 3 hereof), or any vesting pursuant to Section 2 hereof, the number of Performance RSUs, if any, that will vest, will be determined in accordance with the formula described below.  Any RSUs that do not vest in accordance with this RSU Award Agreement will be forfeited and returned to the Company as of the Vesting Date.

(a)The Performance Reward Percentage (as defined below) multiplied by the Target RSUs;

Plus

(b)If the TSR Bonus Multiplier (as defined below) is achieved, the product of (a) above multiplied by one-third.  

The “Performance Reward Percentage” is the percentage shown in column B corresponding to the Performance Measurement in column A in the table below.  The Performance Reward Percentage will be interpolated in proportion to the corresponding placement in column A.  

A        Performance Measurement	B Performance Reward Percentage
Cumulative EPS of less than $______	0%
Cumulative EPS of $______	50%
Cumulative EPS of $______	100%
Cumulative EPS of $______ or more	150%

The “Performance Period” is the period beginning January 1, 2016 and ending on December 31, 2018, unless terminated earlier pursuant to Section 4 hereof, in which case the Performance Period will end on the last business day of the year in which employment was terminated, or if terminated earlier pursuant to Section 5 hereof, in which case the Performance Period will end on the last day of the year prior to the Change in Control.

The “Performance Measurement” is a measurement at the end of the Performance Period of the Company’s cumulative earnings per share calculated by adding the Company’s earnings per share for each year in the Performance Period (“Cumulative EPS”).  Cumulative EPS shall be calculated to three decimal places and the Company’s earnings per share for any year shall be the Company’s earnings on a per share basis, which may be adjusted at the discretion of the Committee to exclude the effect of any of the following events that impact such calculation: (i) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture (including a spin-off) or any other change in corporate structure or shares; (ii) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business; (iii) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results; (iv) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Principles Board Opinion No. 30, provided that the exclusion of the impact of the foregoing specified events from the calculation shall only be made

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to the extent permitted by Section 162(m) of the Internal Revenue Code.  If the Performance Period is terminated prior to December 31, 2018 pursuant to Section 4 or 5 hereof, the Performance Measurement and Performance Reward Percentage shall be determined as shown on Schedule B hereto.  

The “TSR Bonus Multiplier” is achieved if the Company’s Total Shareholder Return is in the top 25 percent of the companies in the Dow Jones conventional electricity group and multiutility group or the successors to those two groups as may be determined by the Committee (the “Peer Group”).  “Total Shareholder Return” is the amount obtained by dividing (1) the sum of (a) the amount of dividends with respect to the Performance Period, assuming dividend reinvestment, and (b) the difference between the share price at the end and beginning of the Performance Period, by (2) the closing share price at the beginning of the Performance Period, with the share price in each case being determined by using the average closing price during the 20 trading days preceding (and inclusive of) the date of determination.  The share price will be equitably adjusted for stock splits and other similar corporate actions affecting the stock.  If the Company’s Total Shareholder Return is not in the top 25 percent of the Peer Group, then the TSR Bonus Multiplier has not been achieved and it shall be omitted from the formula set forth above.

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SCHEDULE B – PRORATED PERFORMANCE MEASUREMENT

1.  The following table shall replace the table provided in Schedule A hereto for calculating the Performance Reward Percentage with respect to a Performance Period that ends on December 31, 2016 pursuant to Section 4 or 5 of this RSU Award Agreement:

A Performance Measurement	B Performance Reward Percentage
Cumulative EPS of less than $______	0%
Cumulative EPS of $______	50%
Cumulative EPS of $______	100%
Cumulative EPS of $______ or more	150%

2.  The following table shall replace the table provided in Schedule A hereto for calculating the Performance Reward Percentage with respect to a Performance Period that ends on December 31, 2017 pursuant to Section 4 or 5 of this RSU Award Agreement:

A Performance Measurement	B Performance Reward Percentage
Cumulative EPS of less than $______	0%
Cumulative EPS of $______	50%
Cumulative EPS of $______	100%
Cumulative EPS of $______ or more	150%

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SCHEDULE C – EXECUTIVE OFFICER PERFORMANCE GOAL

The “Executive Officer Performance Period” is the period beginning January 1, 2016 and ending on December 31, 2018, unless one of the events specified in Subsections 4(b), 4(c) or Section 5 (an “Early Termination Event”) occurs, in which case the Executive Officer Performance Period will end on the last day of the quarter following the Early Termination Event, unless the Early Termination Event occurs on a date that would cause the Executive Officer Performance Period to be shorter than four times as long as the period between the beginning of the Performance Period and the date of this Agreement, then the Executive Officer Performance Period will end on the last day of the quarter after that period of time has elapsed.

The “Executive Officer Performance Goal” for the Performance Period is earnings before interest, taxes, depreciation and amortization (“EBITDA”) of at least $______, which shall be adjusted to exclude the effect of any of the following events that impact EBITDA: (i) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture (including a spin-off) or any other change in corporate structure or shares; (ii) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business; (iii) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results; or (iv) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Principles Board Opinion No. 30, provided that the exclusion of the impact of the foregoing specified events from the calculation of the Executive Officer Performance Goal shall only be made to the extent permitted by Section 162(m) of the Code.  If the Executive Officer Performance Period ends prior to December 31, 2018 due to the occurrence of an Early Termination Event, the Executive Officer Performance Goal shall be prorated for the number of quarters that elapsed, beginning on January 1, 2016 and ending on the last day of the quarter following the Early Termination Event.

If the Compensation Committee’s certification of achievement of the Executive Officer Performance Goal is required under Section 162(m) of the Internal Revenue Code, promptly after the end of the Executive Officer Performance Period, the Company will submit its calculation regarding the Executive Officer Performance Goal to the Compensation Committee for certification, and the Performance RSUs shall vest pursuant to the terms of this Agreement.      

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EX-12.1

Exhibit 12.1

TECO ENERGY, INC.

RATIO OF EARNINGS TO FIXED CHARGES

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

	3-months ended Mar. 31,		12-months ended Mar. 31,		Year Ended Dec. 31,
(millions)	2016		2016		2015		2014		2013		2012		2011
Income from continuing    operations, before income taxes	$	109.4	$	402.2	$	396.5	$	345.3	$	301.3	$	317.8	$	326.5
Interest expense		50.3		200.7		201.8		181.3		169.2		180.9		193.3
Earnings before taxes    and fixed charges	$	159.7	$	602.9	$	598.3	$	526.6	$	470.5	$	498.7	$	519.8
Interest expense	$	50.3	$	200.7	$	201.8	$	181.3	$	169.2	$	180.9	$	193.3
Total fixed charges	$	50.3	$	200.7	$	201.8	$	181.3	$	169.2	$	180.9	$	193.3
Ratio of earnings to fixed charges	3.17x		3.00x		2.96x		2.90x		2.78x		2.76x		2.69x

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. 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 TECO Guatemala is considered a discontinued operation. Periods prior to 2012 have been adjusted to reflect the classification of TECO Guatemala as discontinued operations.

The sale of TECO Coal was completed in September 2015, and TECO Coal is considered a discontinued operation. Periods prior to 2015 have been adjusted to reflect the classification of TECO Coal as discontinued operations.

EX-12.2

Exhibit 12.2

TAMPA ELECTRIC COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

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

	3-months ended Mar. 31,		12-months ended Mar. 31,		Year Ended Dec. 31,
(millions)	2016		2016		2015		2014		2013		2012		2011
Income from continuing operations,    before income taxes	$	100.0	$	442.4	$	441.8	$	416.2	$	364.4	$	368.9	$	380.7
Interest expense		31.0		123.2		122.1		115.8		112.7		129.9		141.9
Earnings before taxes and    fixed charges	$	131.0	$	565.6	$	563.9	$	532.0	$	477.1	$	498.8	$	522.6
Interest expense	$	31.0	$	123.2	$	122.1	$	115.8	$	112.7	$	129.9	$	141.9
Total fixed charges	$	31.0	$	123.2	$	122.1	$	115.8	$	112.7	$	129.9	$	141.9
Ratio of earnings to fixed charges	4.23x		4.59x		4.62x		4.59x		4.23x		3.84x		3.68x

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

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John B. Ramil, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	May 5, 2016	/s/  J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	May 5, 2016	/s/  S.W. CALLAHAN
		S.W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, John B. Ramil, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	May 5, 2016	/s/  J. B. RAMIL
		J. B. RAMIL
		Chief Executive Officer and Director
		(Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	May 5, 2016	/s/  S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

TECO ENERGY, INC

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of TECO Energy, Inc. (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended Mar. 31, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 5, 2016	/s/  J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)
Date:	May 5, 2016	/s/  S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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

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

EX-32.2

Exhibit 32.2

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended Mar. 31, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 5, 2016	/s/  J. B. RAMIL
		J. B. RAMIL
		Chief Executive Officer and Director
		(Principal Executive Officer)
Date:	May 5, 2016	/s/  S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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

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

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,550,000
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 46.1	$ 23.8
Receivables, less allowance for uncollectibles	240.1	280.7
Inventories, at average cost
Regulatory assets	40.2	44.8
Prepayments and other current assets	25.4	30.8
Total current assets	547.2	570.3
Property, plant and equipment
Construction work in progress	816.9	794.7
Other property	16.1	15.9
Property, plant and equipment, at original costs	10,315.4	10,194.7
Accumulated depreciation	(2,762.4)	(2,712.9)
Total property, plant and equipment, net	7,553.0	7,481.8
Other assets
Regulatory assets	393.4	395.2
Goodwill	408.4	408.4
Deferred charges and other assets	79.1	77.8
Total other assets	880.9	881.4
Total assets	8,981.1	8,933.5
Current liabilities
Long-term debt due within one year	83.3	333.3
Notes payable	513.0	247.0
Accounts payable	189.5	255.4
Customer deposits	176.7	182.1
Regulatory liabilities	108.4	84.8
Derivative liabilities	22.3	24.1
Interest accrued	54.0	36.2
Taxes accrued	28.2	13.2
Other	25.2	22.6
Total current liabilities	1,200.6	1,198.7
Other liabilities
Deferred income taxes	607.0	570.7
Investment tax credits	10.4	10.5
Regulatory liabilities	709.4	715.8
Derivative liabilities	0.8	2.1
Deferred credits and other liabilities	380.9	387.5
Long-term debt, less amount due within one year	3,489.7	3,489.2
Total other liabilities	$ 5,198.2	$ 5,175.8
Commitments and contingencies
Capital
Common equity	$ 235.5	$ 235.3
Additional paid in capital	1,894.8	1,894.5
Retained earnings	463.5	441.4
Accumulated other comprehensive loss	(11.5)	(12.2)
Total capital	2,582.3	2,559.0
Long-term debt	3,489.7	3,489.2
Total liabilities and capital	8,981.1	8,933.5
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	28.2	9.1
Receivables, less allowance for uncollectibles	205.5	230.2
Inventories, at average cost
Taxes receivable from affiliate	0.0	61.3
Regulatory assets	39.9	44.3
Prepayments and other current assets	17.0	21.5
Total current assets	479.6	545.1
Property, plant and equipment
Construction work in progress	797.0	771.1
Utility plant in service, at original costs	9,544.6	9,440.0
Accumulated depreciation	(2,720.3)	(2,676.8)
Utility plant in service, net	6,824.3	6,763.2
Other property	9.9	9.7
Total property, plant and equipment, net	6,834.2	6,772.9
Other assets
Regulatory assets	373.1	373.8
Deferred charges and other assets	391.0	390.6
Other	17.9	16.8
Total assets	7,704.8	7,708.6
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	0.0	61.0
Accounts payable	174.6	221.6
Customer deposits	170.9	176.3
Regulatory liabilities	104.5	83.2
Derivative liabilities	22.2	24.1
Interest accrued	41.2	16.9
Taxes accrued	33.6	13.2
Other	10.1	10.2
Total current liabilities	640.4	689.8
Other liabilities
Deferred income taxes	1,342.0	1,308.8
Investment tax credits	10.4	10.5
Regulatory liabilities	595.5	603.5
Derivative liabilities	0.8	2.1
Deferred credits and other liabilities	312.3	316.7
Long-term debt, less amount due within one year	2,162.0	2,161.7
Total deferred credits	$ 2,261.0	$ 2,241.6
Commitments and contingencies
Capital
Common equity	$ 2,330.4	$ 2,305.4
Retained earnings	314.4	313.7
Accumulated other comprehensive loss	(3.4)	(3.6)
Total capital	2,641.4	2,615.5
Long-term debt	2,162.0	2,161.7
Total capitalization	4,803.4	4,777.2
Total liabilities and capital	7,704.8	7,708.6
Fuel [Member]
Inventories, at average cost
Utility inventories	118.3	113.4
Fuel [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	115.4	105.6
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	77.1	76.8
Materials and Supplies [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	73.6	73.1
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,328.3	7,270.3
Electric [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,328.3	7,270.3
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	2,154.1	2,113.8
Gas [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,419.3	$ 1,398.6

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Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Allowance for uncollectibles	$ 2.1	$ 2.1
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	235,500,000	235,300,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 1.6	$ 1.5

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Consolidated Condensed Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues
Regulated electric	$ 423.4	$ 449.7
Regulated gas	232.9	240.2
Unregulated	3.2	3.1
Total revenues	659.5	693.0
Expenses
Fuel	115.2	144.1
Purchased power	14.4	17.1
Cost of natural gas sold	96.8	103.0
Other	142.3	143.7
Operation and maintenance other expense	0.0	1.6
Depreciation and amortization	89.8	85.5
Taxes, other than income	52.9	51.8
Total expenses	511.4	546.8
Income from operations	148.1	146.2
Other income
Allowance for other funds used during construction	5.7	3.8
Other income, net	1.5	1.6
Total other income	7.2	5.4
Interest charges
Interest expense	48.9	49.8
Allowance for borrowed funds used during construction	(3.0)	(1.9)
Total interest charges	45.9	47.9
Income from continuing operations before provision for income taxes	109.4	103.7
Provision for income taxes	35.7	39.9
Net income from continuing operations	73.7	63.8
Discontinued operations
Income (loss) from discontinued operations	0.2	(9.6)
Provision (benefit) from income taxes	0.1	(3.8)
Income (loss) from discontinued operations, net	0.1	(5.8)
Net income	$ 73.8	$ 58.0
Average common shares outstanding - Basic	234.0	232.8
Average common shares outstanding - Diluted	235.2	233.5
Earnings per share from continuing operations - Basic	$ 0.31	$ 0.27
Earnings per share from continuing operations - Diluted	0.31	0.27
Earnings per share from discontinued operations - Basic	0.00	(0.02)
Earnings per share from discontinued operations - Diluted	0.00	(0.02)
Earnings per share - Basic	0.31	0.25
Earnings per share - Diluted	0.31	0.25
Dividends paid per common share outstanding	$ 0.230	$ 0.225

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Consolidated Condensed Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net income		$ 73.8	$ 58.0
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2	0.3
Amortization of unrecognized benefit costs	[1]	0.5	0.6
Other comprehensive income, net of tax		0.7	0.9
Comprehensive income		$ 74.5	$ 58.9

[1] Related to postretirement and postemployment benefits. See Note 5 for additional information.

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Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities
Net income	$ 73.8	$ 58.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	89.8	85.9
Depreciation and amortization	89.8	85.5
Deferred income taxes and investment tax credits	36.1	36.0
Allowance for other funds used during construction	(5.7)	(3.8)
Non-cash stock compensation	3.0	3.9
Deferred recovery clauses	26.4	(5.7)
Receivables, less allowance for uncollectibles	40.6	51.0
Inventories	(5.2)	(15.7)
Prepayments and other current assets	2.8	(10.9)
Taxes accrued	18.1	1.7
Interest accrued	17.8	17.8
Accounts payable	(59.1)	(63.5)
Other	(6.8)	(7.7)
Cash flows from operating activities	231.6	147.0
Cash flows from investing activities
Capital expenditures	(168.0)	(156.2)
Other investing activities	(0.2)	(0.2)
Cash flows used in investing activities	(168.2)	(156.4)
Cash flows from financing activities
Dividends and dividend equivalents	(54.3)	(53.0)
Proceeds from the sale of common stock	3.9	2.8
Repayment of long-term debt/purchase in lieu of redemption	(250.0)	0.0
Net increase (decrease) in short-term debt (maturities of 90 days or less)	(134.0)	67.0
Proceeds from other short-term debt (maturities over 90 days)	400.0	0.0
Other financing activities	(6.7)	0.0
Cash flows from (used in) financing activities	(41.1)	16.8
Net increase in cash and cash equivalents	22.3	7.4
Cash and cash equivalents at beginning of the period	23.8	25.4
Cash and cash equivalents at end of the period	46.1	32.8
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	(6.0)	11.5
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	63.3	62.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	80.9	76.8
Deferred income taxes and investment tax credits	30.4	21.2
Allowance for other funds used during construction	(5.6)	(3.8)
Deferred recovery clauses	27.0	(4.7)
Receivables, less allowance for uncollectibles	24.7	13.5
Inventories	(10.3)	(21.1)
Prepayments and other current assets	4.6	(5.0)
Taxes accrued	81.7	72.7
Interest accrued	24.3	22.9
Accounts payable	(41.2)	(28.3)
Other	(11.6)	(6.9)
Cash flows from operating activities	268.2	200.1
Cash flows from investing activities
Capital expenditures	(150.5)	(148.8)
Cash flows used in investing activities	(150.5)	(148.8)
Cash flows from financing activities
Dividends and dividend equivalents	(62.6)	(55.7)
Proceeds from the sale of common stock	25.0	20.0
Net increase (decrease) in short-term debt (maturities of 90 days or less)	(61.0)	(11.0)
Cash flows from (used in) financing activities	(98.6)	(46.7)
Net increase in cash and cash equivalents	19.1	4.6
Cash and cash equivalents at beginning of the period	9.1	10.4
Cash and cash equivalents at end of the period	28.2	15.0
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (4.8)	$ 11.4

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Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues
Total revenues	$ 659.5	$ 693.0
Expenses
Fuel	115.2	144.1
Purchased power	14.4	17.1
Cost of natural gas sold	96.8	103.0
Other	142.3	143.7
Depreciation and amortization	89.8	85.5
Taxes, other than income	52.9	51.8
Total expenses	511.4	546.8
Income from operations	148.1	146.2
Other income
Allowance for other funds used during construction	5.7	3.8
Other income, net	1.5	1.6
Total other income	7.2	5.4
Interest charges
Interest expense	48.9	49.8
Allowance for borrowed funds used during construction	(3.0)	(1.9)
Total interest charges	45.9	47.9
Income before provision for income taxes	109.4	103.7
Provision for income taxes	35.7	39.9
Net income	73.8	58.0
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.3
Other comprehensive income, net of tax	0.7	0.9
Comprehensive income	74.5	58.9
Tampa Electric Company [Member]
Revenues
Electric	424.2	450.4
Gas	126.8	121.7
Total revenues	551.0	572.1
Expenses
Fuel	115.1	144.1
Purchased power	14.4	17.1
Cost of natural gas sold	50.3	43.3
Other	121.2	121.8
Depreciation and amortization	80.9	76.8
Taxes, other than income	48.5	47.6
Total expenses	430.4	450.7
Income from operations	120.6	121.4
Other income
Allowance for other funds used during construction	5.6	3.8
Other income, net	1.3	1.2
Total other income	6.9	5.0
Interest charges
Interest on long-term debt	29.0	27.7
Interest expense	1.2	1.1
Allowance for borrowed funds used during construction	(2.7)	(1.8)
Total interest charges	27.5	27.0
Income before provision for income taxes	100.0	99.4
Provision for income taxes	36.7	36.6
Net income	63.3	62.8
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.3
Other comprehensive income, net of tax	0.2	0.3
Comprehensive income	$ 63.5	$ 63.1

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2015 Annual Report on Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

Tampa Electric Company [Member]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TEC’s 2015 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 14 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $56.8 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2016

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the company classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.

Stock Compensation

In March 2016, the FASB issued guidance regarding employee share-based payment accounting. The guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liability, and presentation on the statement of cash flows. This guidance will be required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact and was implemented as follows:

· Income tax consequences – Under the new guidance, the company will no longer recognize excess tax benefits and certain tax deficiencies in additional paid in capital. Instead, the company will recognize all excess tax benefits and tax deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize them. Accordingly, the company recorded a $2.6 million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. In accordance with the new guidance, the company will no longer include excess tax benefits and tax deficiencies in the dilutive EPS calculation on a prospective basis.

· Accounting for forfeitures – The company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods.

· Classification of awards - The company had no share-based payments classified as liability awards as of Mar. 31, 2016 or Dec. 31, 2015.  

· Presentation on the statement of cash flows – Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a retrospective basis for all periods presented. Previously, the company presented it as an operating activity. There was an immaterial amount of activity that did not result in an adjustment to the statement of cash flows for the three months ended Mar. 31, 2015.

Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for the company beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on future derivative contract novations, if any.

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, TEC classified $17.9 million and $18.1 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified as an asset in the “Unamortized debt expense” line item). The guidance did not affect TEC’s results of operations or cash flows.

Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. TEC does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for TEC beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for TEC beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for TEC beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect TEC’s current financial statements. However, TEC will assess the impact of this guidance on future derivative contract novations, if any.

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Regulatory

3 Months Ended

Mar. 31, 2016

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. 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 requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC 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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.1	$	74.7
Cost-recovery clauses - deferred balances (2)		0.1		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		26.0		26.5
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		238.5		240.6
Deferred bond refinancing costs (5)		6.2		6.5
Debt basis adjustment (6)		16.7		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		12.1		12.1
Total regulatory assets		433.6		440.0
Less: Current portion		40.2		44.8
Long-term regulatory assets	$	393.4	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.6	$	7.9
Cost-recovery clauses (2)		80.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		673.6		679.9
Other		0.5		0.8
Total regulatory liabilities		817.8		800.6
Less: Current portion		108.4		84.8
Long-term regulatory liabilities	$	709.4	$	715.8

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

(7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

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. 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 requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

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; 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; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.0	$	74.6
Cost-recovery clauses - deferred balances (2)		0.0		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		25.9		26.2
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		236.4		238.3
Deferred bond refinancing costs (5)		6.2		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.6		10.7
Total regulatory assets		413.0		418.1
Less: Current portion		39.9		44.3
Long-term regulatory assets	$	373.1	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.6	$	5.7
Cost-recovery clauses (2)		76.1		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		561.7		570.0
Other		0.5		0.7
Total regulatory liabilities		700.0		686.7
Less: Current portion		104.5		83.2
Long-term regulatory liabilities	$	595.5	$	603.5

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

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Income Taxes

3 Months Ended

Mar. 31, 2016

Income Taxes

4. Income Taxes

The effective tax rate decreased to 32.63% for the three months ended Mar. 31, 2016 from 38.48% for the same period in 2015 primarily due to the tax benefit related to long-term incentive compensation share vestings (see Note 2 for further description).

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. 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 and foreign jurisdictions include 2005 and forward. TECO Energy does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

Tampa Electric Company [Member]

Income Taxes

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three months ended Mar. 31, 2016 and 2015 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. 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 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

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Employee Postretirement Benefits

3 Months Ended

Mar. 31, 2016

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Mar. 31,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.4		$	4.5		$	0.5		$	0.6
Interest cost		8.1			7.4			2.2			2.0
Expected return on assets		(11.3	)		(10.8	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		3.4			3.4			0.0			0.0
Regulatory asset		0.0			0.0			0.2			0.3
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	4.6		$	4.4		$	2.0		$	2.0

For the fiscal 2016 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan for the three months ended Mar. 31, 2016 and 2015, respectively.

For the three months ended Mar. 31, 2016 and 2015, TECO Energy and its subsidiaries reclassified $0.8 million of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2016 and 2015, the regulated companies reclassified $2.2 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

Tampa Electric Company [Member]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Mar. 31, 2016 and 2015, respectively, was $2.9 million and $2.6 million for pension benefits, and $1.5 million and $1.4 million for other postretirement benefits.

For the fiscal 2016 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.685%.  For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan in the three months ended Mar. 31, 2016 and 2015, respectively. TEC’s portion of the contributions was $3.9 million and $11.0 million, respectively.

Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2016 and 2015, TEC reclassified $2.0 million and $1.9 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

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Short-Term Debt

3 Months Ended

Mar. 31, 2016

Short-Term Debt

6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		113.0		0.0		300.0		163.0		0.0
1-year term facility (4)(5)		400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility (2)		125.0		0.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	513.0	$	2.2	$	900.0	$	247.0	$	2.2
(1)           Borrowings outstanding are reported as notes payable.
(2)           This 5-year facility matures Dec. 17, 2018.
(3)           Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.
(4)           TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5)           This 1-year facility matures Mar. 14, 2017.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.44% and 1.29%, respectively.  

TECO Energy/TECO Finance Credit Facility

On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0.0	$	0.5	$	475.0	$	61.0	$	0.5

(1) Borrowings outstanding are reported as notes payable.

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

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.0% and 0.89%, respectively.

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Long-Term Debt

3 Months Ended

Mar. 31, 2016

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, total long-term debt had a carrying amount of $3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 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 (see Note 13 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012.  On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016.  On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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.

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, TEC’s total long-term debt had a carrying amount of $2,245.3 million and an estimated fair market value of $2,483.1 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 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 (see Note 11 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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 Mar. 19, 2008 to Mar. 15, 2012. On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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.

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2016

Other Comprehensive Income

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5
Total other comprehensive income	$	1.1	$	(0.4	)	$	0.7
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income (1)		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs (2)		0.9		(0.3	)		0.6
Total other comprehensive income	$	1.6	$	(0.7	)	$	0.9
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement and postemployment benefits. See Note 5 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and    transition obligations (2)		25.5			25.6
Net unrealized losses from cash flow hedges (3)		(3.4	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.5	)	$	(12.2	)
(1)  Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Total other comprehensive income	$	0.7	$	(0.4	)	$	0.3

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.4	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.4	)	$	(3.6	)

(1) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

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Earnings Per Share

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share

9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2016			2015
Basic earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Basic	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Basic	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Basic	$	73.7		$	57.8
Average common shares outstanding - Basic		234.0			232.8
Earnings per share from continuing operations available to    common shareholders - Basic	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Basic		0.0		$	(0.02	)
Earnings per share available to common shareholders - Basic	$	0.31		$	0.25
Diluted earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Diluted	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Diluted	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Diluted	$	73.7		$	57.8
Unadjusted average common shares outstanding - Diluted		234.0			232.8
Assumed conversion of stock options, unvested restricted stock,    unvested RSUs and contingent performance shares, net		1.2			0.7
Average common shares outstanding - Diluted		235.2			233.5
Earnings per share from continuing operations available to    common shareholders - Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Diluted		0.0		$	(0.02	)
Earnings per share available to common shareholders - Diluted	$	0.31		$	0.25
Anti-dilutive shares		0.2			0.1

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies

10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. 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.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Mar. 31, 2016.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.  

Proceedings in connection with the Pending Merger with Emera

Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction.  Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida.  They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger.  In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

The company also received two separate shareholder demand letters from purported shareholders of the company.  Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices.  One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.  

In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.  Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete.  There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Claim in connection with the Sale of TECO Coal

As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. On Mar. 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting breach of certain representations, and fraud and willful misconduct in connection therewith, of the SPA.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

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

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.

On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to TGH.  As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

PGS Compliance Matter
          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

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 Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” 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 rates.

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

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows:

(millions)							Maximum
					After (1)		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits (3)		89.4		0.0		0.0		89.4		0.0
	$	89.4	$	0.0	$	92.9	$	182.3	$	0.0
							Maximum
(millions)					After (1)		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.0
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.1
(1)    These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Mar. 31, 2016. See Note 12 for additional information.
(3)    These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.
(4)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

Tampa Electric Company [Member]

Commitments and Contingencies

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. 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.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

PGS Compliance Matter

          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

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 Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” 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 rates.

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.

Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Mar. 31, 2016 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Total		at Mar. 31, 2016
TEC (2)	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
(1)These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TEC was in compliance with all applicable financial covenants.

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Segment Information

3 Months Ended

Mar. 31, 2016

Segment Information

11. Segment Information

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

Three months ended Mar. 31,	Tampa Electric		PGS		NMGC (2)		TECO Coal (1)			Other (2) (3)			Eliminations (3)				TECO Energy
2016
Revenues - external	$	423.4	$	126.8	$	106.6	$	0.0		$	2.7		$	0.0			$	659.5
Sales to affiliates		1.1		4.4		0.0		0.0			0.0			(5.5	)			0.0
Total revenues		424.5		131.2		106.6		0.0			2.7			(5.5	)			659.5
Depreciation and amortization		66.1		14.8		8.4		0.0			0.5			0.0				89.8
Total interest charges		23.8		3.7		3.0		0.0			15.6			(0.2	)			45.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.2			(0.2	)			0.0
Provision (benefit) for income taxes		27.8		8.9		9.7		0.0			(10.7	)		0.0				35.7
Net income (loss) from continuing operations		50.2		13.1		15.2		0.0			(4.8	)		0.0				73.7
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		0.0			0.1			0.0				0.1
Net income (loss)	$	50.2	$	13.1	$	15.2	$	0.0		$	(4.7	)	$	0.0			$	73.8
2015
Revenues - external	$	449.8	$	121.7	$	119.0	$	0.0		$	2.5		$	0.0			$	693.0
Sales to affiliates		0.8		1.2		0.0		0.0			0.0			(2.0	)			0.0
Total revenues		450.6		122.9		119.0		0.0			2.5			(2.0	)			693.0
Depreciation and amortization		62.9		13.9		8.4		0.0			0.3			0.0				85.5
Total interest charges		23.5		3.5		3.3		0.0			17.9			(0.3	)			47.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.3			(0.3	)			0.0
Provision (benefit) for income taxes		27.4		9.2		9.0		0.0			(5.7	)		0.0				39.9
Net income (loss) from continuing operations		48.2		14.6		13.9		0.0			(12.9	)		0.0				63.8
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		(6.0	)		0.2			0.0				(5.8	)
Net income (loss)	$	48.2	$	14.6	$	13.9	$	(6.0	)	$	(12.7	)	$	0.0			$	58.0
At Mar. 31, 2016
Total assets	$	6,988.2	$	1,147.0	$	1,210.9	$	0.0		$	1,982.1		$	(2,347.1	)	(4)	$	8,981.1
At Dec. 31, 2015
Total assets (3)	$	7,003.8	$	1,136.1	$	1,229.7	$	0.0		$	1,945.1		$	(2,381.2	)	(4)		8,933.5
(1)    All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
(2)    NMGI is included in the Other segment.
(3)    Certain prior year amounts have been reclassified to conform to current year presentation.
(4)    Amounts primarily relate to intercompany advances and consolidated tax eliminations.

Tampa Electric Company [Member]

Segment Information

9. Segment Information

(millions)	Tampa							Tampa Electric
Three months ended Mar. 31,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	424.2	$	126.8	$	0.0		$	551.0
Intracompany sales		0.3		4.4		(4.7	)		0.0
Total revenues		424.5		131.2		(4.7	)		551.0
Depreciation and amortization		66.1		14.8		0.0			80.9
Total interest charges		23.8		3.7		0.0			27.5
Provision for income taxes		27.8		8.9		0.0			36.7
Net income	$	50.2	$	13.1	$	0.0		$	63.3
2015
Revenues - external	$	450.4	$	121.7	$	0.0		$	572.1
Intracompany sales		0.2		1.2		(1.4	)		0.0
Total revenues		450.6		122.9		(1.4	)		572.1
Depreciation and amortization		62.9		13.9		0.0			76.8
Total interest charges		23.5		3.5		0.0			27.0
Provision for income taxes		27.4		9.2		0.0			36.6
Net income	$	48.2	$	14.6	$	0.0		$	62.8
Total assets at Mar. 31, 2016	$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Total assets at Dec. 31, 2015 (1)		6,620.2		1,097.7		(9.3	)		7,708.6

(1) Certain prior year amounts have been reclassified to conform to current year presentation.

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Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2016

Accounting for Derivative Instruments and Hedging Activities

12. Accounting for Derivative Instruments and Hedging Activities

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

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

· To optimize the utilization of NMGC’s physical natural gas storage capacity, and

· To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ 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 13). 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 and sale of natural gas for the benefit of its regulated companies’ ratepayers. These standards, in accordance with the FPSC and NMPRC, 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 Mar. 31, 2016, all of the company’s physical contracts qualify for the NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 million and $0.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative liabilities totaled $23.1 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2016 and 2015 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

Derivative Volumes	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

The company is exposed to credit risk by 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. 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 Mar. 31, 2016, 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 generally do not require a nonperformance risk adjustment 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.

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 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.

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

10. Accounting for Derivative Instruments and Hedging Activities

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

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

· To limit the exposure to interest rate fluctuations on debt securities.

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

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

TEC applies the accounting standards for 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 11). 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 Mar. 31, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative assets as of Mar. 31, 2016 and Dec. 31, 2015. Derivative liabilities totaled $23.0 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2016 and 2015 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassification to income was reflected in “Interest expense”.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

TEC is exposed to credit risk by 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 Mar. 31, 2016, 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 generally do not require a nonperformance risk adjustment 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.

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 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.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Measurements

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).  

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

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 Mar. 31, 2016 and Dec. 31, 2015. 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.     

Recurring Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas derivatives	$	0.0	$	23.1	$	0.0	$	23.1
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are estimated utilizing the income approach. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap, forward and option positions to determine the fair value (see Note 12). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Tampa Electric Company [Member]

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. 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.  

Recurring Derivative Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	23.0	$	0.0	$	23.0
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2016

Variable Interest Entities

14. 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.

Tampa Electric 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 250 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 variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

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

Tampa Electric Company [Member]

Variable Interest Entities

13. Variable Interest Entities

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.

Tampa Electric 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 250 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 variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric 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, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

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

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Discontinued Operations and Asset Impairments

3 Months Ended

Mar. 31, 2016

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations and Asset Impairments

15. Discontinued Operations and Asset Impairments

TECO Coal

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 10). The SPA contained customary representations, warranties and covenants (see Note 10 for description of a claim related to the SPA). The income shown for the first quarter of 2016 in the table below reflects a refund of prepaid costs.

Since the closing of the sale, TECO Energy does not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries 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 (see Note 10). The charges shown in the table below are legal costs associated with that claim.  

Combined Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

Components of income from discontinued operations	Three months ended
	Mar. 31,
(millions)	2016		2015
Revenues—TECO Coal	$	0.0	$	72.7
Loss from operations—TECO Coal		0.0		(9.5	)
Loss from operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations—TECO Coal		0.2		(9.5	)
Loss from discontinued operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations		0.2		(9.6	)
Provision (benefit) for income taxes		0.1		(3.8	)
Income (loss) from discontinued operations, net	$	0.1	$	(5.8	)

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Mergers and Acquisitions

3 Months Ended

Mar. 31, 2016

Mergers and Acquisitions

16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction.  In the stipulation, the parties state that they believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its acquisition of NMGC, invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs.  The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

During the three months ended Mar. 31, 2016, TECO Energy incurred approximately $0.1 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

Tampa Electric Company [Member]

Mergers and Acquisitions

14. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion).

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction. The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2016

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

Revenues

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

Tampa Electric Company [Member]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 14 for further information.

Revenues

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $56.8 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

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Regulatory (Tables)

3 Months Ended

Mar. 31, 2016

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.1	$	74.7
Cost-recovery clauses - deferred balances (2)		0.1		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		26.0		26.5
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		238.5		240.6
Deferred bond refinancing costs (5)		6.2		6.5
Debt basis adjustment (6)		16.7		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		12.1		12.1
Total regulatory assets		433.6		440.0
Less: Current portion		40.2		44.8
Long-term regulatory assets	$	393.4	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.6	$	7.9
Cost-recovery clauses (2)		80.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		673.6		679.9
Other		0.5		0.8
Total regulatory liabilities		817.8		800.6
Less: Current portion		108.4		84.8
Long-term regulatory liabilities	$	709.4	$	715.8

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

(7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

Tampa Electric Company [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.0	$	74.6
Cost-recovery clauses - deferred balances (2)		0.0		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		25.9		26.2
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		236.4		238.3
Deferred bond refinancing costs (5)		6.2		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.6		10.7
Total regulatory assets		413.0		418.1
Less: Current portion		39.9		44.3
Long-term regulatory assets	$	373.1	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.6	$	5.7
Cost-recovery clauses (2)		76.1		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		561.7		570.0
Other		0.5		0.7
Total regulatory liabilities		700.0		686.7
Less: Current portion		104.5		83.2
Long-term regulatory liabilities	$	595.5	$	603.5

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

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Employee Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Compensation And Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Mar. 31,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.4		$	4.5		$	0.5		$	0.6
Interest cost		8.1			7.4			2.2			2.0
Expected return on assets		(11.3	)		(10.8	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		3.4			3.4			0.0			0.0
Regulatory asset		0.0			0.0			0.2			0.3
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	4.6		$	4.4		$	2.0		$	2.0

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Short-Term Debt (Tables)

3 Months Ended

Mar. 31, 2016

Short-Term Debt Credit Facilities

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		113.0		0.0		300.0		163.0		0.0
1-year term facility (4)(5)		400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility (2)		125.0		0.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	513.0	$	2.2	$	900.0	$	247.0	$	2.2
(1)           Borrowings outstanding are reported as notes payable.
(2)           This 5-year facility matures Dec. 17, 2018.
(3)           Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.
(4)           TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5)           This 1-year facility matures Mar. 14, 2017.

Tampa Electric Company [Member]

Short-Term Debt Credit Facilities

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0.0	$	0.5	$	475.0	$	61.0	$	0.5

(1) Borrowings outstanding are reported as notes payable.

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

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2016

Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5
Total other comprehensive income	$	1.1	$	(0.4	)	$	0.7
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income (1)		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs (2)		0.9		(0.3	)		0.6
Total other comprehensive income	$	1.6	$	(0.7	)	$	0.9
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement and postemployment benefits. See Note 5 for additional information.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and    transition obligations (2)		25.5			25.6
Net unrealized losses from cash flow hedges (3)		(3.4	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.5	)	$	(12.2	)
(1)  Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Total other comprehensive income	$	0.7	$	(0.4	)	$	0.3

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.4	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.4	)	$	(3.6	)

(1) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2016			2015
Basic earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Basic	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Basic	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Basic	$	73.7		$	57.8
Average common shares outstanding - Basic		234.0			232.8
Earnings per share from continuing operations available to    common shareholders - Basic	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Basic		0.0		$	(0.02	)
Earnings per share available to common shareholders - Basic	$	0.31		$	0.25
Diluted earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Diluted	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Diluted	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Diluted	$	73.7		$	57.8
Unadjusted average common shares outstanding - Diluted		234.0			232.8
Assumed conversion of stock options, unvested restricted stock,    unvested RSUs and contingent performance shares, net		1.2			0.7
Average common shares outstanding - Diluted		235.2			233.5
Earnings per share from continuing operations available to    common shareholders - Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Diluted		0.0		$	(0.02	)
Earnings per share available to common shareholders - Diluted	$	0.31		$	0.25
Anti-dilutive shares		0.2			0.1

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2016

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows:

(millions)							Maximum
					After (1)		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits (3)		89.4		0.0		0.0		89.4		0.0
	$	89.4	$	0.0	$	92.9	$	182.3	$	0.0
							Maximum
(millions)					After (1)		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.0
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.1
(1)    These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Mar. 31, 2016. See Note 12 for additional information.
(3)    These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.
(4)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Tampa Electric Company [Member]

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Mar. 31, 2016 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Total		at Mar. 31, 2016
TEC (2)	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
(1)These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)    The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Schedule of Segment Information

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

Three months ended Mar. 31,	Tampa Electric		PGS		NMGC (2)		TECO Coal (1)			Other (2) (3)			Eliminations (3)				TECO Energy
2016
Revenues - external	$	423.4	$	126.8	$	106.6	$	0.0		$	2.7		$	0.0			$	659.5
Sales to affiliates		1.1		4.4		0.0		0.0			0.0			(5.5	)			0.0
Total revenues		424.5		131.2		106.6		0.0			2.7			(5.5	)			659.5
Depreciation and amortization		66.1		14.8		8.4		0.0			0.5			0.0				89.8
Total interest charges		23.8		3.7		3.0		0.0			15.6			(0.2	)			45.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.2			(0.2	)			0.0
Provision (benefit) for income taxes		27.8		8.9		9.7		0.0			(10.7	)		0.0				35.7
Net income (loss) from continuing operations		50.2		13.1		15.2		0.0			(4.8	)		0.0				73.7
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		0.0			0.1			0.0				0.1
Net income (loss)	$	50.2	$	13.1	$	15.2	$	0.0		$	(4.7	)	$	0.0			$	73.8
2015
Revenues - external	$	449.8	$	121.7	$	119.0	$	0.0		$	2.5		$	0.0			$	693.0
Sales to affiliates		0.8		1.2		0.0		0.0			0.0			(2.0	)			0.0
Total revenues		450.6		122.9		119.0		0.0			2.5			(2.0	)			693.0
Depreciation and amortization		62.9		13.9		8.4		0.0			0.3			0.0				85.5
Total interest charges		23.5		3.5		3.3		0.0			17.9			(0.3	)			47.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.3			(0.3	)			0.0
Provision (benefit) for income taxes		27.4		9.2		9.0		0.0			(5.7	)		0.0				39.9
Net income (loss) from continuing operations		48.2		14.6		13.9		0.0			(12.9	)		0.0				63.8
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		(6.0	)		0.2			0.0				(5.8	)
Net income (loss)	$	48.2	$	14.6	$	13.9	$	(6.0	)	$	(12.7	)	$	0.0			$	58.0
At Mar. 31, 2016
Total assets	$	6,988.2	$	1,147.0	$	1,210.9	$	0.0		$	1,982.1		$	(2,347.1	)	(4)	$	8,981.1
At Dec. 31, 2015
Total assets (3)	$	7,003.8	$	1,136.1	$	1,229.7	$	0.0		$	1,945.1		$	(2,381.2	)	(4)		8,933.5
(1)    All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
(2)    NMGI is included in the Other segment.
(3)    Certain prior year amounts have been reclassified to conform to current year presentation.
(4)    Amounts primarily relate to intercompany advances and consolidated tax eliminations.

Tampa Electric Company [Member]

Schedule of Segment Information

(millions)	Tampa							Tampa Electric
Three months ended Mar. 31,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	424.2	$	126.8	$	0.0		$	551.0
Intracompany sales		0.3		4.4		(4.7	)		0.0
Total revenues		424.5		131.2		(4.7	)		551.0
Depreciation and amortization		66.1		14.8		0.0			80.9
Total interest charges		23.8		3.7		0.0			27.5
Provision for income taxes		27.8		8.9		0.0			36.7
Net income	$	50.2	$	13.1	$	0.0		$	63.3
2015
Revenues - external	$	450.4	$	121.7	$	0.0		$	572.1
Intracompany sales		0.2		1.2		(1.4	)		0.0
Total revenues		450.6		122.9		(1.4	)		572.1
Depreciation and amortization		62.9		13.9		0.0			76.8
Total interest charges		23.5		3.5		0.0			27.0
Provision for income taxes		27.4		9.2		0.0			36.6
Net income	$	48.2	$	14.6	$	0.0		$	62.8
Total assets at Mar. 31, 2016	$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Total assets at Dec. 31, 2015 (1)		6,620.2		1,097.7		(9.3	)		7,708.6

(1) Certain prior year amounts have been reclassified to conform to current year presentation.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Volumes Expected to Settle

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

Derivative Volumes	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

Tampa Electric Company [Member]

Derivative Volumes Expected to Settle

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Schedule of Recurring Fair Value Measurements

Recurring Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas derivatives	$	0.0	$	23.1	$	0.0	$	23.1
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

Tampa Electric Company [Member]

Schedule of Recurring Fair Value Measurements

Recurring Derivative Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	23.0	$	0.0	$	23.0
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

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Discontinued Operations and Asset Impairments (Tables)

3 Months Ended

Mar. 31, 2016

TECO Coal and TECO Guatemala [Member]

Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

Components of income from discontinued operations	Three months ended
	Mar. 31,
(millions)	2016		2015
Revenues—TECO Coal	$	0.0	$	72.7
Loss from operations—TECO Coal		0.0		(9.5	)
Loss from operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations—TECO Coal		0.2		(9.5	)
Loss from discontinued operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations		0.2		(9.6	)
Provision (benefit) for income taxes		0.1		(3.8	)
Income (loss) from discontinued operations, net	$	0.1	$	(5.8	)

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Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	$ 67.3		$ 81.1
Franchise fees and gross receipts taxes	27.9	$ 27.4
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	56.8		$ 53.7
Franchise fees and gross receipts taxes	$ 27.9	$ 27.4

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New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Jan. 01, 2016	Mar. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative adjustment to retained earnings	$ 2.6
Long-term Debt, Less Amount Due Within One Year [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost		$ 26.4	$ 27.7
Long-term Debt, Less Amount Due Within One Year [Member] | Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost		$ 17.9	$ 18.1

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Regulatory assets:
Regulatory assets	$ 433.6	$ 440.0
Less: Current portion	40.2	44.8
Long-term regulatory assets	393.4	395.2
Regulatory liabilities:
Regulatory liabilities	817.8	800.6
Less: Current portion	108.4	84.8
Long-term regulatory liabilities	709.4	715.8
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	413.0	418.1
Less: Current portion	39.9	44.3
Long-term regulatory assets	373.1	373.8
Regulatory liabilities:
Regulatory liabilities	700.0	686.7
Less: Current portion	104.5	83.2
Long-term regulatory liabilities	595.5	603.5
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	77.1	74.7
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	77.0	74.6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	0.1	5.5
Cost-Recovery Clauses - Deferred Balances [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	0.0	5.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	26.0	26.5
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	25.9	26.2
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	54.4	54.0
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	54.4	54.0
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	238.5	240.6
Postretirement Benefit Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	236.4	238.3
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	6.2	6.5
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	6.2	6.5
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	16.7	17.5
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Other [Member]
Regulatory assets:
Regulatory assets	12.1	12.1
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	10.6	10.7
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	7.6	7.9
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.6	5.7
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	80.0	55.9
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	76.1	54.2
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	673.6	679.9
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	561.7	570.0
Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.5	0.8
Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$ 0.5	$ 0.7

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Income Taxes - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Taxes [Line Items]
Effective tax rate	32.63%	38.48%
Income tax examination period	1 year
Tampa Electric Company [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Income tax examination period	1 year
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations	4 years

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.4	$ 4.5
Interest cost	8.1	7.4
Expected return on assets	(11.3)	(10.8)
Amortization of:
Prior service (benefit) cost	0.0	(0.1)
Actuarial loss	3.4	3.4
Regulatory asset	0.0	0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	4.6	4.4
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.5	0.6
Interest cost	2.2	2.0
Expected return on assets	(0.3)	(0.3)
Amortization of:
Prior service (benefit) cost	(0.6)	(0.6)
Actuarial loss	0.0	0.0
Regulatory asset	0.2	0.3
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 2.0	$ 2.0

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Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions		3 Months Ended
	Jan. 01, 2016	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Reclassification of AOCI to net income as part of periodic benefit expense		$ 0.8	$ 0.8
Reclassification of regulatory assets to net income as part of periodic benefit expense		$ 2.2	2.2
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA		7.00%
Reclassification of regulatory assets to net income as part of periodic benefit expense		$ 2.0	1.9
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA		7.00%
Discount rate		4.685%
Employer contributions		$ 4.7	14.9
Net pension expense		$ 4.6	4.4
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.685%
Employer contributions		$ 3.9	11.0
Net pension expense		2.9	2.6
Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.667%
Other Postretirement Benefits, NMGC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.687%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension expense		2.0	2.0
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.667%
Net pension expense		$ 1.5	$ 1.4

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Short-Term Debt - Credit Facilities (Detail) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Credit Facilities	$ 1,300,000,000	$ 900,000,000
Borrowings Outstanding	513,000,000	247,000,000
Letters of Credit Outstanding	2,200,000	2,200,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475,000,000	475,000,000
Borrowings Outstanding	0	61,000,000
Letters of Credit Outstanding	500,000	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	0	0
Letters of Credit Outstanding	500,000	500,000
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000	150,000,000
Borrowings Outstanding	0	61,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000	300,000,000
Borrowings Outstanding	113,000,000	163,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] | 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	400,000,000	0
Borrowings Outstanding	400,000,000	0
Letters of Credit Outstanding	0	0
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125,000,000	125,000,000
Borrowings Outstanding	0	23,000,000
Letters of Credit Outstanding	$ 1,700,000	$ 1,700,000

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Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
TECO Energy [Member] | 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 14, 2017	Mar. 14, 2017
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

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Short-Term Debt - Additional Information (Detail) - USD ($)		3 Months Ended
	Mar. 14, 2016	Mar. 31, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity		$ 1,300,000,000	$ 900,000,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.00%	0.89%
Line of Credit Facility maximum borrowing capacity		$ 475,000,000	$ 475,000,000
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.44%	1.29%
TECO Finance [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.44%	1.29%
Basis spread on federal funds rate	0.50%
Interest rate description		provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.
TECO Finance [Member] | 1-year Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity	$ 400,000,000
Credit facility maturity date	Mar. 14, 2017
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.44%	1.29%
Minimum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Maximum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.30%

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions				3 Months Ended
	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, carrying amount				$ 3,573.0		$ 3,822.5
Estimated fair value				3,879.1		4,061.6
Purchase in lieu of redemption				250.0	$ 0.0
HCIDA Pollution Control Revenue Refunding Bonds [Member] | Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption				232.6
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount				2,245.3		2,245.0
Estimated fair value				$ 2,483.1		$ 2,433.3
Tampa Electric Company [Member] | HCIDA Pollution Control Revenue Refunding Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, repurchase date	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008
Purchase in lieu of redemption			$ 86.0
Stated interest rate	2.00%	1.875%	5.00%

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		$ 0.0	$ 0.3
Reclassification from AOCI to net income, Gross	[1]	0.3	0.4
Gain on cash flow hedges, Gross		0.3	0.7
Amortization of unrecognized benefit costs, Gross	[2]	0.8	0.9
Total other comprehensive income (loss), Gross		1.1	1.6
Unrealized gain on cash flow hedges, Tax		0.0	(0.2)
Reclassification from AOCI to net income, Tax	[1]	(0.1)	(0.2)
Gain on cash flow hedges, Tax		(0.1)	(0.4)
Amortization of unrecognized benefit costs, Tax	[2]	(0.3)	(0.3)
Total other comprehensive income (loss), Tax		(0.4)	(0.7)
Unrealized gain on cash flow hedges, Net		0.0	0.1
Reclassification from AOCI to net income, Net	[1]	0.2	0.2
Gain on cash flow hedges, Net		0.2	0.3
Amortization of unrecognized benefit costs, Net	[2]	0.5	0.6
Other comprehensive income, net of tax		0.7	0.9
Unamortized pension loss and prior service credit	[3]	(33.6)		$ (34.2)
Unamortized other benefit gains, prior service costs and transition obligations	[4]	25.5		25.6
Net unrealized losses from cash flow hedges	[5]	(3.4)		(3.6)
Total accumulated other comprehensive loss		(11.5)		(12.2)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0.0	0.3
Reclassification from AOCI to net income, Gross		0.3	0.4
Gain on cash flow hedges, Gross		0.3	0.7
Total other comprehensive income (loss), Gross		0.3	0.7
Unrealized gain on cash flow hedges, Tax		0.0	(0.2)
Reclassification from AOCI to net income, Tax		(0.1)	(0.2)
Gain on cash flow hedges, Tax		(0.1)	(0.4)
Total other comprehensive income (loss), Tax		(0.1)	(0.4)
Unrealized gain on cash flow hedges, Net		0.0	0.1
Reclassification from AOCI to net income, Net		0.2	0.2
Gain on cash flow hedges, Net		0.2	0.3
Other comprehensive income, net of tax		0.2	$ 0.3
Net unrealized losses from cash flow hedges	[5]	(3.4)		(3.6)
Total accumulated other comprehensive loss		$ (3.4)		$ (3.6)

[1] Related to interest rate contracts recognized in Interest expense.

[2] Related to postretirement and postemployment benefits. See Note 5 for additional information.

[3] Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

[4] Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

[5] Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 2.1	$ 2.3
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	2.1	2.3
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	21.1	21.5
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	$ 16.0	$ 16.1

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Earnings Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Basic earnings per share
Net income from continuing operations	$ 73.7	$ 63.8
Amount allocated to nonvested participating shareholders	(0.1)	(0.2)
Income before discontinued operations available to common shareholders - Basic	73.6	63.6
Income (loss) from discontinued operations, net	0.1	(5.8)
Amount allocated to nonvested participating shareholders	0.0	0.0
Income (loss) from discontinued operations available to common shareholders - Basic	0.1	(5.8)
Net income	73.8	58.0
Amount allocated to nonvested participating shareholders	(0.1)	(0.2)
Net income available to common shareholders - Basic	$ 73.7	$ 57.8
Average common shares outstanding - Basic	234.0	232.8
Earnings per share from continuing operations available to common shareholders - Basic	$ 0.31	$ 0.27
Earnings per share from discontinued operations available to common shareholders - Basic	0.00	(0.02)
Earnings per share - Basic	$ 0.31	$ 0.25
Diluted earnings per share
Net income from continuing operations	$ 73.7	$ 63.8
Amount allocated to nonvested participating shareholders	(0.1)	(0.2)
Income before discontinued operations available to common shareholders - Diluted	73.6	63.6
Income (loss) from discontinued operations, net	0.1	(5.8)
Amount allocated to nonvested participating shareholders	0.0	0.0
Income (loss) from discontinued operations available to common shareholders - Diluted	0.1	(5.8)
Net income	73.8	58.0
Amount allocated to nonvested participating shareholders	(0.1)	(0.2)
Net income available to common shareholders - Diluted	$ 73.7	$ 57.8
Average common shares outstanding - Basic	234.0	232.8
Assumed conversion of stock options, unvested restricted stock, unvested RSUs and contingent performance shares, net	1.2	0.7
Average common shares outstanding - Diluted	235.2	233.5
Earnings per share from continuing operations available to common shareholders - Diluted	$ 0.31	$ 0.27
Earnings per share from discontinued operations available to common shareholders - Diluted	0.00	(0.02)
Earnings per share - Diluted	$ 0.31	$ 0.25
Anti-dilutive shares	0.2	0.1

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Commitments and Contingencies - Additional Information (Detail) $ in Millions					3 Months Ended
	Apr. 18, 2016 USD ($)	Apr. 05, 2016 USD ($)	Dec. 19, 2013 USD ($)	Feb. 08, 2011 Customer InsuranceCarrier Lawsuit	Mar. 31, 2016 USD ($) Claims	Sep. 30, 2015 USD ($)	Mar. 31, 2011 Customer
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers | Customer				28,700			32,000
Number of class actions settled | Claims					2
Number of insurance carriers | InsuranceCarrier				18
Number of lawsuits for insurance carriers | Lawsuit				2
Letters of indemnity coal mining permits						$ 93.8
PGS [Member]
Long Term Commitments [Line Items]
Total potential penalties					$ 3.9
Settlement agreement date					Apr. 18, 2016
Ultimate financial liability to superfund sites and former MGP sites					$ 33.9
PGS [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Total potential penalties					$ 3.9
Settlement agreement date					Apr. 18, 2016
Ultimate financial liability to superfund sites and former MGP sites					$ 33.9
FPSC [Member]
Long Term Commitments [Line Items]
Settlement agreement date					May 05, 2016
FPSC [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Settlement agreement date					May 05, 2016
Subsequent Event [Member]
Long Term Commitments [Line Items]
Dismissed annulment of the award		$ 21.1
Subsequent Event [Member] | PGS [Member]
Long Term Commitments [Line Items]
Civil penalty amount	$ 1.0
Customer refunds	2.0
Subsequent Event [Member] | PGS [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Civil penalty amount	1.0
Customer refunds	$ 2.0
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement amount			$ 7.5
Damages awarded			$ 21.1
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member] | U.S. prime rate plus [Member]
Long Term Commitments [Line Items]
Litigation settlement interest			2.00%

XML

Commitments and Contingencies - Letters of Credit and Guarantees (Detail)	Mar. 31, 2016 USD ($)
Guarantee Obligations [Line Items]
Year of expiration 2016	$ 89,400,000
Year of expiration 2017-2020	0
Year of expiration After 2020	92,900,000
Maximum Theoretical Obligation	182,300,000
Liabilities Recognized at Mar 31, 2016	0
Letter of Credit [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	2,200,000
Maximum Theoretical Obligation	2,200,000
Liabilities Recognized at Mar 31, 2016	100,000
Tampa Electric Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	500,000
Maximum Theoretical Obligation	500,000
Liabilities Recognized at Mar 31, 2016	100,000
New Mexico Gas Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	1,700,000
Maximum Theoretical Obligation	1,700,000
Liabilities Recognized at Mar 31, 2016	0
Fuel Sales and Transportation [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	92,900,000
Maximum Theoretical Obligation	92,900,000
Liabilities Recognized at Mar 31, 2016	0
Letters of Indemnity - Coal Mining Permits
Guarantee Obligations [Line Items]
Year of expiration 2016	89,400,000
Year of expiration 2017-2020	0
Year of expiration After 2020	0
Maximum Theoretical Obligation	89,400,000
Liabilities Recognized at Mar 31, 2016	$ 0

XML

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total revenues	$ 659.5	$ 693.0
Depreciation and amortization	89.8	85.5
Total interest charges	45.9	47.9
Internally allocated interest	0.0	0.0
Provision (benefit) for income taxes	35.7	39.9
Net income (loss) from continuing operations	73.7	63.8
Income (loss) from discontinued operations, net	0.1	(5.8)
Net income	73.8	58.0
Total assets	8,981.1		$ 8,933.5
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	551.0	572.1
Depreciation and amortization	80.9	76.8
Total interest charges	27.5	27.0
Provision (benefit) for income taxes	36.7	36.6
Net income	63.3	62.8
Total assets	7,704.8		7,708.6
Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(5.5)	(2.0)
Depreciation and amortization	0.0	0.0
Total interest charges	(0.2)	(0.3)
Internally allocated interest	(0.2)	(0.3)
Provision (benefit) for income taxes	0.0	0.0
Net income (loss) from continuing operations	0.0	0.0
Income (loss) from discontinued operations, net	0.0	0.0
Net income	0.0	0.0
Total assets	(2,347.1)		(2,381.2)
Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	(4.7)	(1.4)
Depreciation and amortization	0.0	0.0
Total interest charges	0.0	0.0
Provision (benefit) for income taxes	0.0	0.0
Net income	0.0	0.0
Total assets	(5.2)		(9.3)
Eliminations [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(4.7)	(1.4)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	424.5	450.6
Depreciation and amortization	66.1	62.9
Total interest charges	23.8	23.5
Internally allocated interest	0.0	0.0
Provision (benefit) for income taxes	27.8	27.4
Net income (loss) from continuing operations	50.2	48.2
Income (loss) from discontinued operations, net	0.0	0.0
Net income	50.2	48.2
Total assets	6,988.2		7,003.8
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	424.5	450.6
Depreciation and amortization	66.1	62.9
Total interest charges	23.8	23.5
Provision (benefit) for income taxes	27.8	27.4
Net income	50.2	48.2
Total assets	6,600.4		6,620.2
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.3	0.2
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	131.2	122.9
Depreciation and amortization	14.8	13.9
Total interest charges	3.7	3.5
Internally allocated interest	0.0	0.0
Provision (benefit) for income taxes	8.9	9.2
Net income (loss) from continuing operations	13.1	14.6
Income (loss) from discontinued operations, net	0.0	0.0
Net income	13.1	14.6
Total assets	1,147.0		1,136.1
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	131.2	122.9
Depreciation and amortization	14.8	13.9
Total interest charges	3.7	3.5
Provision (benefit) for income taxes	8.9	9.2
Net income	13.1	14.6
Total assets	1,109.6		1,097.7
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	4.4	1.2
NMGC [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	106.6	119.0
Depreciation and amortization	8.4	8.4
Total interest charges	3.0	3.3
Internally allocated interest	0.0	0.0
Provision (benefit) for income taxes	9.7	9.0
Net income (loss) from continuing operations	15.2	13.9
Income (loss) from discontinued operations, net	0.0	0.0
Net income	15.2	13.9
Total assets	1,210.9		1,229.7
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0
Depreciation and amortization	0.0	0.0
Total interest charges	0.0	0.0
Internally allocated interest	0.0	0.0
Provision (benefit) for income taxes	0.0	0.0
Net income (loss) from continuing operations	0.0	0.0
Income (loss) from discontinued operations, net	0.0	(6.0)
Net income	0.0	(6.0)
Total assets	0.0		0.0
Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.7	2.5
Depreciation and amortization	0.5	0.3
Total interest charges	15.6	17.9
Internally allocated interest	0.2	0.3
Provision (benefit) for income taxes	(10.7)	(5.7)
Net income (loss) from continuing operations	(4.8)	(12.9)
Income (loss) from discontinued operations, net	0.1	0.2
Net income	(4.7)	(12.7)
Total assets	1,982.1		$ 1,945.1
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	659.5	693.0
Revenues - External [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	551.0	572.1
Revenues - External [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0
Revenues - External [Member] | Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0
Revenues - External [Member] | Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	423.4	449.8
Revenues - External [Member] | Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	424.2	450.4
Revenues - External [Member] | PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	126.8	121.7
Revenues - External [Member] | PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	126.8	121.7
Revenues - External [Member] | NMGC [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	106.6	119.0
Revenues - External [Member] | TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0
Revenues - External [Member] | Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.7	2.5
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0
Sales to Affiliates [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(5.5)	(2.0)
Sales to Affiliates [Member] | Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	1.1	0.8
Sales to Affiliates [Member] | PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	4.4	1.2
Sales to Affiliates [Member] | NMGC [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0
Sales to Affiliates [Member] | TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0
Sales to Affiliates [Member] | Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	$ 0.0	$ 0.0

XML

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative assets	$ 0	$ 200,000
Derivative liabilities	23,100,000	26,200,000
Cash collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	(22,300,000)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	0	0
Derivative liabilities	23,000,000	26,200,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	$ (22,200,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Feb. 28, 2018
Natural Gas Contracts [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Feb. 28, 2018

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) - Natural Gas Contracts [Member] MMBTU in Millions	Mar. 31, 2016 MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35.7
Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35.7
2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2016 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25.1
2016 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25.1
2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2017 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9.9
2017 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9.9
2018 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2018 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.0
2018 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.7
2018 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.7

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 23,100,000	$ 26,200,000
Natural gas derivatives assets	0	200,000
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	23,000,000	26,200,000
Natural gas derivatives assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural gas derivatives assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural gas derivatives assets	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	23,100,000	26,200,000
Natural gas derivatives assets		200,000
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	23,000,000	26,200,000
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural gas derivatives assets		0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	23,100,000	26,200,000
Natural gas derivatives assets		200,000
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	23,000,000	26,200,000
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural gas derivatives assets		0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 0	$ 0

XML

Fair Value Measurements - Additional Information (Detail) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 200,000
Derivative liabilities	23,100,000	26,200,000
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	23,000,000	26,200,000
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	$ 0	$ 0

XML

Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) MW	Mar. 31, 2015 USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 14.4	$ 17.1
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	14.4	17.1
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	12.6	5.4
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 12.6	$ 5.4
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	117
Minimum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	250
Maximum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	250

XML

Discontinued Operations and Asset Impairments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 21, 2015
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Contingent payments	$ 0	$ 60

XML

Discontinued Operations and Asset Impairments - Components of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations	$ 0.2	$ (9.6)
Provision (benefit) from income taxes	0.1	(3.8)
Income (loss) from discontinued operations, net	0.1	(5.8)
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	0.0	72.7
Loss from operations	0.0	(9.5)
Income (loss) from discontinued operations	0.2	(9.5)
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from operations	0.0	(0.1)
Income (loss) from discontinued operations	0.0	(0.1)
TECO Coal and TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Provision (benefit) from income taxes	$ 0.1	$ (3.8)

XML

Mergers and Acquisitions - Additional Information (Detail) - USD ($)		3 Months Ended
	Sep. 04, 2015	Mar. 31, 2016
Business Acquisition [Line Items]
Business combination incremental transaction related costs		$ 100,000
Emera Inc. [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Emera Inc. [Member] | Tampa Electric Company [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Senior secured notes	$ 2,300,000,000