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~~June 3130, 2016

¨	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~~As ~~number~~ of July 29, 2016, there were 1,000 shares of TECO Energy, Inc.’s common stock outstanding, asall of ~~April~~which 29were held, ~~2016~~beneficially ~~was~~and ~~235~~of record,~~550,000~~ by Emera Inc. As of ~~April~~July 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

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
NO_x		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

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	~~Mar.~~June 3130,			Dec. 31,
(millions)	2016			2015
Current assets
Cash and cash equivalents	$	4629.12		$	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
Receivables, less allowance for uncollectibles of $2.0 and $2.1 at June 30, 2016 and Dec. 31, 2015, respectively		256.5			280.7
Inventories, at average cost
Fuel	~~118~~106.38			113.4
Materials and supplies		7778.18			76.8
Regulatory assets		4018.24			44.8
Prepayments and other current assets		2529.4			30.8
Total current assets		~~547~~519.21			570.3
Property, plant and equipment
Utility plant in service
Electric		7,~~328~~419.35			7,270.3
Gas		2,~~154~~191.19			2,113.8
Construction work in progress		~~816~~855.9			794.7
Other property		16.14			15.9
Property, plant and equipment, at original costs		10,~~315~~483.47			10,194.7
Accumulated depreciation		(2,~~762~~810.41	)		(2,712.9	)
Total property, plant and equipment, net		7,~~553~~673.06			7,481.8
Other assets
Regulatory assets		~~393~~392.49			395.2
Goodwill		408.4			408.4
Deferred charges and other assets		7985.17			77.8
Total other assets		~~880~~887.90			881.4
Total assets	$	89,~~981~~079.17		$	8,933.5

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

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	~~Mar.~~June 3130,			Dec. 31,
(millions)	2016			2015
Current liabilities
Long-term debt due within one year	$	830.30		$	333.3
Notes payable		~~513~~615.0			247.0
Accounts payable		~~189~~295.51			255.4
Customer deposits		~~176~~168.75			182.1
Regulatory liabilities		~~108~~130.41			84.8
Derivative liabilities		221.31			24.1
Interest accrued		5434.03			36.2
Taxes accrued		2846.20			13.2
Other		25.2			22.6
Dividends declared		26.8			0.0
Total current liabilities		1,200.6			1,198.7
Other		21.8			22.6
Total current liabilities		1,338.7			1,198.7
Other liabilities
Deferred income taxes		~~607~~635.01			570.7
Investment tax credits		10.43			10.5
Regulatory liabilities		~~709~~723.48			715.8
Derivative liabilities		0.8			2.1
Deferred credits and other liabilities		371.5			389.6
Deferred credits and other liabilities		380.9			387.5
Long-term debt, less amount due within one year		3,490.0			3,489.2
Long-term debt, less amount due within one year		3,489.7			3,489.2
Total other liabilities		5,230.7			5,175.8
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
Common equity (400.0 million shares authorized; par value $1; 235.5 million and 235.3 million shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively)		235.5			235.3
Additional paid in capital		1,~~894~~898.85			1,894.5
Retained earnings		~~463~~387.57			441.4
Accumulated other comprehensive loss		(11.54	)		(12.2	)
Total capital		2,~~582~~510.3			2,559.0
Total liabilities and capital	$	89,~~981~~079.17		$	8,933.5

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

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Mar. 31,
		Three months ended June 30,
(millions, except per share amounts)		2016			2015
Revenues
Regulated electric		$	~~423~~498.40		$	~~449~~531.7
Regulated gas			~~232~~151.94			~~240~~146.25
Unregulated			3.2.9			32.14
Total revenues			~~659~~652.53			~~693~~680.06
Expenses
Regulated operations and maintenance
Fuel			~~115~~137.24			~~144~~171.18
Purchased power			1427.48			1719.16
Cost of natural gas sold			9650.8			~~103~~49.01
Other			~~142~~154.36			~~143~~155.74
Operation and maintenance other expense			0.0			1.6
Operations and maintenance other expense			1.4			1.1
Depreciation and amortization			89.8			85.5
Merger transaction-related costs			71.4			0.0
Taxes, other than income			52.9			51.8
Depreciation and amortization			90.2			87.0
Total expenses			511.4			546.8
Taxes, other than income			52.0			53.3
Income from operations			148.1			146.2
Total expenses			585.6			537.3
Income from operations			66.7			143.3
Other income
Allowance for other funds used during construction			5.79			3.87
Other income, net			1.50			1.64
Total other income			76.29			5.41
Interest charges
Interest expense			4846.97			4948.82
Allowance for borrowed funds used during construction			(32.09	)		(1.98	)
Total interest charges			4543.98			4746.94
Income from continuing operations before provision for income taxes			~~109~~29.48			~~103~~102.70
Provision for income taxes			3524.73			3940.95
Net income from continuing operations			735.75			6361.85
Discontinued operations
Income (loss) from discontinued operations			0.2			(9.6	)
Loss from discontinued operations			(0.4	)		(78.1	)
Provision (benefit) from income taxes			0.1			(3.8	)
Benefit for income taxes			(0.2	)		(28.4	)
Income (loss) from discontinued operations, net			0.1			(5.8	)
Loss from discontinued operations, net			(0.2	)		(49.7	)
Net income		$	735.83		$	5811.08
Average common shares outstanding	– Basic		234.03			~~232~~233.80
	– Diluted		235.25			233.56
Earnings per share from continuing operations	– Basic	$	0.3103		$	0.2726
	– Diluted	$	0.3103		$	0.2726
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.0221	)
	– Diluted	$	0.00		$	(0.0221	)
Earnings per share	– Basic	$	0.3103		$	0.2505
	– Diluted	$	0.3103		$	0.2505
Dividends paid per common share outstanding		$	0.230		$	0.225

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

TECO ENERGY, INC.

Consolidated Condensed Statements of ~~Comprehensive~~ Income

Unaudited

	Three months ended Mar. 31,
			Six months ended June 30,
(millions)	2016				2015
(millions, except per share amounts)			2016				2015
Net income	$	73.8			$	58.0
Revenues
Other comprehensive income, net of tax
Regulated electric			$	921.4			$	981.4
Gain on cash flow hedges		0.2				0.3
Regulated gas				384.3				386.7
Amortization of unrecognized benefit costs		0.5				0.6
Unregulated				6.1				5.5
Other comprehensive income, net of tax		0.7				0.9
Total revenues				1,311.8				1,373.6
Comprehensive income	$	74.5			$	58.9
Expenses
Regulated operations and maintenance
Fuel				252.6				315.9
Purchased power				42.2				36.7
Cost of natural gas sold				147.6				152.1
Other				296.9				299.1
Operations and maintenance other expense				1.3				2.7
Merger transaction-related costs				71.5				0.0
Depreciation and amortization				180.0				172.5
Taxes, other than income				104.9				105.1
Total expenses				1,097.0				1,084.1
Income from operations				214.8				289.5
Other income
Allowance for other funds used during construction				11.6				7.5
Other income, net				2.5				3.0
Total other income				14.1				10.5
Interest charges
Interest expense				95.6				98.0
Allowance for borrowed funds used during construction				(5.9	)			(3.7	)
Total interest charges				89.7				94.3
Income from continuing operations before provision for income taxes				139.2				205.7
Provision for income taxes				60.0				80.4
Net income from continuing operations				79.2				125.3
Discontinued operations
Loss from discontinued operations				(0.2	)			(87.7	)
Benefit for income taxes				(0.1	)			(32.2	)
Loss from discontinued operations, net				(0.1	)			(55.5	)
Net income			$	79.1			$	69.8
Average common shares outstanding	– Basic			234.1				232.9
	– Diluted			235.4				233.5
Earnings per share from continuing operations	– Basic		$	0.34			$	0.53
	– Diluted		$	0.34			$	0.53
Earnings per share from discontinued operations	– Basic		$	0.00			$	(0.23	)
	– Diluted		$	0.00			$	(0.23	)
Earnings per share	– Basic		$	0.34			$	0.30
	– Diluted		$	0.34			$	0.30
Dividends paid per common share outstanding			$	0.46			$	0.45

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

TECO ENERGY, INC.

Consolidated Condensed Statements of ~~Cash~~Comprehensive ~~Flows~~Income

Unaudited

	Three months ended Mar. 31,
		Three months ended June 30,						Six months ended June 30,
(millions)	~~2016~~	2016			~~2015~~	2015		2016		2015
Cash flows from operating activities
Net income		$	5.3			$	11.8	$	79.1	$	69.8
Net income	$	73.8			$	58.0
Other comprehensive income, net of tax
Adjustments to reconcile net income to net cash from operating activities:
Gain on cash flow hedges			0.2				2.8		0.4		3.1
Depreciation and amortization		89.8				85.9
Amortization of unrecognized benefit costs and other			(0.2	)			1.0		0.3		1.6
Deferred income taxes and investment tax credits		36.1				36.0
Recognized cost due to curtailment			0.1				0.0		0.1		0.0
Allowance for other funds used during construction		(5.7	)			(3.8	)
Other comprehensive income, net of tax			0.1				3.8		0.8		4.7
Non-cash stock compensation		3.0				3.9
Comprehensive income		$	5.4			$	15.6	$	79.9	$	74.5
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.

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended June 30,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	79.1		$	69.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		180.0			173.3
Deferred income taxes and investment tax credits		60.3			46.9
Allowance for other funds used during construction		(11.6	)		(7.5	)
Non-cash stock compensation		6.4			6.9
Loss on disposals of business/assets, pretax		0.3			0.0
Deferred recovery clauses		42.5			(4.1	)
Asset impairment, pretax		0.0			78.6
Receivables, less allowance for uncollectibles		24.2			39.8
Inventories		4.6			(37.2	)
Prepayments and other current assets		2.9			(12.2	)
Taxes accrued		35.9			19.0
Interest accrued		(1.9	)		(1.8	)
Accounts payable		55.7			(58.3	)
Other		(20.2	)		(15.1	)
Cash flows from operating activities		458.2			298.1
Cash flows from investing activities
Capital expenditures		(384.8	)		(335.7	)
Net proceeds from sale of business/assets		8.7			0.0
Other investing activities		(0.2	)		(0.1	)
Cash flows used in investing activities		(376.3	)		(335.8	)
Cash flows from financing activities
Dividends and dividend equivalents		(108.6	)		(105.9	)
Proceeds from the sale of common stock		4.1			3.5
Proceeds from long-term debt issuance		0.0			500.0
Repayment of long-term debt		(333.3	)		(274.5	)
Net decrease in short-term debt (maturities of 90 days or less)		(32.0	)		(53.5	)
Proceeds from other short-term debt (maturities over 90 days)		400.0			0.0
Other financing activities		(6.7	)		(1.3	)
Cash flows from (used in) financing activities		(76.5	)		68.3
Net increase in cash and cash equivalents		5.4			30.6
Cash and cash equivalents at beginning of the period		23.8			25.4
Cash and cash equivalents at end of the period	$	29.2		$	56.0
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(14.2	)	$	1.6
Dividends declared and not paid	$	26.8		$	0.0

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

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.~~June 3130, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended ~~Mar.~~June 3130, 2016 and 2015. The results of operations for the three and six months ended ~~Mar.~~June 3130, 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~~July 1, ~~2015~~2016, TECO Energy and Emera ~~entered~~completed ~~into~~the Merger contemplated by the Merger Agreement entered into on Sept. 4, ~~Upon~~2015. ~~closing~~As a result of the Merger, Merger Sub merged with and into TECO Energy ~~will~~with ~~become~~TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

Revenues

As of ~~Mar.~~June 3130, 2016 and Dec. 31, 2015, unbilled revenues of $6773.32 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 $2728.96 million and $2756.45 million for the three and six months ended ~~Mar.~~June 3130, 2016, respectively, compared to $29.3 million and $56.6 million for the three and six months ended June 30, 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.~~June 3130, 2016 and Dec. 31, 2015, the company classified $2625.42 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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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.~~June 3130, 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~~Therefore, the company ~~presented~~reclassified it$1.3 asmillion anfrom operating ~~activity.~~activities ~~There was an immaterial amount of activity that did not result in an adjustment~~ to ~~the~~financing ~~statement~~activities ~~of cash flows~~ for the ~~three~~six months ended ~~Mar.~~June 3130, 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~~will to adopt this guidance effective Jan. 1, 2018,. The company has developed an implementation plan 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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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.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. In addition, the guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective for the company beginning in 2020, with early adoption permitted in 2019, 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.

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:~~ 13

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

Details of the regulatory assets and liabilities are presented in the following table:

Regulatory Assets and Liabilities
(millions)	June 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	80.8	$	74.7
Cost-recovery clauses - deferred balances⁽²⁾		2.5		5.5
Cost-recovery clauses - offsets to derivative liabilities ⁽²⁾		1.1		26.5
Environmental remediation ⁽³⁾		54.6		54.0
Postretirement benefits ⁽⁴⁾		236.2		240.6
Deferred bond refinancing costs ⁽⁵⁾		7.4		6.5
Debt basis adjustment ⁽⁶⁾		15.8		17.5
Competitive rate adjustment ⁽²⁾		2.5		2.6
Other		10.4		12.1
Total regulatory assets		411.3		440.0
Less: Current portion		18.4		44.8
Long-term regulatory assets	$	392.9	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.3	$	7.9
Cost-recovery clauses⁽²⁾		98.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal ⁽⁷⁾		678.6		679.9
Other		13.9		0.8
Total regulatory liabilities		853.9		800.6
Less: Current portion		130.1		84.8
Long-term regulatory liabilities	$	723.8	$	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. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

4. Income Taxes

The effective tax rate ~~decreased~~increased to 3243.6310% for the ~~three~~six months ended ~~Mar.~~June 3130, 2016 from 3839.4809% for the same period in 2015 primarily due to non-deductible Merger transaction costs offset by the tax benefit related to long-term incentive compensation ~~share vestings~~ (see ~~Note~~Notes 2 and 16 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.

remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, the company is only eligible to participate in the CAP through its short tax year ending June 30, 2016. 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
Three months ended June 30,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.46		$	46.54		$	0.54		$	0.65
Interest cost		8.13			78.47			2.2			2.01
Expected return on assets		(11.34	)		(1012.85	)		(0.3	)		(0.32	)
Amortization of:
Prior service (benefit) cost		0.02			(0.10	)		(0.67	)		(0.6	)
Actuarial loss		3.45			3.4.8			0.0			0.0
Regulatory asset		0.0			0.0			0.23			0.32
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.6		$	4.4		$	2.0		$	2.0
Curtailment cost		1.3			0.0			0.0			0.0
Settlement cost		0.6			0.0			0.0			0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	7.1		$	7.4		$	1.9		$	2.0
Six months ended June 30,
Components of net periodic benefit expense
Service cost	$	9.0		$	10.9		$	0.9		$	1.1
Interest cost		16.4			16.1			4.4			4.1
Expected return on assets		(22.7	)		(23.3	)		(0.6	)		(0.5	)
Amortization of:
Prior service (benefit) cost		0.2			(0.1	)		(1.3	)		(1.2	)
Actuarial loss		6.9			8.2			0.0			0.0
Regulatory asset		0.0			0.0			0.5			0.5
Curtailment cost		1.3			0.0			0.0			0.0
Settlement cost		0.6			0.0			0.0			0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	11.7		$	11.8		$	3.9		$	4.0

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 $415.76 million and $1424.95 million to its pension plan for the ~~three~~six months ended ~~Mar.~~June 3130, 2016 and 2015, respectively.

For the three and six months ended ~~Mar.~~June 3130, 2016 ~~and 2015~~, TECO Energy and its subsidiaries reclassified $0.82 million and $1.0 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $1.4 Inmillion ~~addition,~~and ~~during~~$2.2 million for the three and six months ended ~~Mar~~June 30, 2015, respectively. 31In addition, ~~2016~~during the three and ~~2015~~six months ended June, 2016, the regulated companies reclassified $23.21 million and $5.3 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $3.0 million and $5.2 million for the three and six months ended June 30, 2015, respectively.

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The settlement cost recognized relates to the settlement of the SERP liability for the TECO Coal participant. An estimated curtailment loss for the SERP of $1.3 million was recognized in the second quarter of 2016 as a result of retirements expected in the third quarter of 2016 due to the Merger.

The company’s postretirement benefit plans were not explicitly impacted by the Merger. However, TECO Energy expects to recognize a settlement charge related to the SERP of approximately $8.0 million in the first quarter of 2017 due to retirements that will take place as a result of the Merger.

6. Short-Term Debt

AtDetails ~~Mar.~~of ~~31, 2016 and Dec. 31, 2015,~~ the ~~following~~ credit facilities and related borrowings ~~existed~~are presented in the following table:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
	June 30, 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		0123.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		~~113~~90.0		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		02.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	~~513~~615.0	$	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.~~June 3130, 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.~~June 3130, 2016 and Dec. 31, 2015 was 1.4433% 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.~~June 3130, 2016, total long-term debt had a carrying amount of $3,~~573~~490.0 million and an estimated fair market value of $3,~~879~~845.18 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~~The fair value of debt securities ~~are~~totaling $58.8 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 ~~instruments~~measurements (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.

14As of June 30, 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.

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, recognized cost due to curtailment and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
	Three months ended June 30,									Six months ended June 30,
(millions)	Gross			Tax			Net			Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.3			(0.1	)		0.2			0.7		(0.3	)		0.4
Gain on cash flow hedges		0.3			(0.1	)		0.2			0.7		(0.3	)		0.4
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5
Amortization of unrecognized benefit costs and other (2)		(0.3	)		0.1			(0.2	)		0.5		(0.2	)		0.3
Total other comprehensive income	$	1.1		$	(0.4	)	$	0.7
Recognized cost due to curtailment (3)		0.1			0.0			0.1			0.1		0.0			0.1
2015
Total other comprehensive income	$	0.1		$	0.0		$	0.1		$	1.3	$	(0.5	)	$	0.8
Unrealized gain on cash flow hedges	$	0.3		$	(0.2	)	$	0.1
2015
Reclassification from AOCI to net income (1)		0.4			(0.2	)		0.2
Unrealized gain on cash flow hedges	$	4.0		$	(1.4	)	$	2.6		$	4.3	$	(1.5	)	$	2.8
Gain on cash flow hedges		0.7			(0.4	)		0.3
Reclassification from AOCI to net income (1)		0.3			(0.1	)		0.2			0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs (2)		0.9			(0.3	)		0.6
Gain on cash flow hedges		4.3			(1.5	)		2.8			5.0		(1.9	)		3.1
Total other comprehensive income	$	1.6		$	(0.7	)	$	0.9
Amortization of unrecognized benefit costs (2)		1.6			(0.6	)		1.0			2.5		(0.9	)		1.6
(1) Related to interest rate contracts recognized in Interest expense.
Total other comprehensive income	$	5.9		$	(2.1	)	$	3.8		$	7.5	$	(2.8	)	$	4.7
(2) Related to postretirement and postemployment benefits. See Note 5 for additional information.
(1) Related to interest rate contracts recognized in Interest expense.
(2) Related to postretirement benefits. See Note 5 for additional information.
(3) Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.

Accumulated Other Comprehensive Loss
(millions)	~~Mar.~~June 3130, 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)		25.54			25.6
Net unrealized losses from cash flow hedges (3)		(3.42	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.54	)	$	(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.
(1) Net of tax benefit of $20.9 million and $21.5 million as of June 30, 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.
(2) Net of tax expense of $15.8 million and $16.1 million as of June 30, 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.
(3) Net of tax benefit of $2.0 million and $2.3 million as of June 30, 2016 and Dec. 31, 2015, respectively.

1517

9. Earnings Per Share

	For the three months ended Mar. 31,
	For the three months ended June 30,						For the six months ended June 30,
(millions, except per share amounts)	2016			2015			2016			2015
Basic earnings per share
Net income from continuing operations	$	735.75		$	6361.85		$	79.2		$	125.3
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Income before discontinued operations available to common shareholders - Basic	$	735.64		$	6361.63		$	79.0		$	124.9
Income (loss) from discontinued operations, net	$	(0.12	)	$	(549.87	)	$	(0.1	)	$	(55.5	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Basic	$	(0.12	)	$	(549.87	)	$	(0.1	)	$	(55.5	)
Net income	$	735.83		$	5811.08		$	79.1		$	69.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Net income available to common shareholders - Basic	$	735.72		$	5711.86		$	78.9		$	69.4
Average common shares outstanding - Basic		234.03			~~232~~233.80			234.1			232.9
Earnings per share from continuing operations available to common shareholders - Basic	$	0.3103		$	0.2726		$	0.34		$	0.53
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.0		$	(0.0221	)	$	0.0		$	(0.23	)
Earnings per share available to common shareholders - Basic	$	0.3103		$	0.2505		$	0.34		$	0.30
Diluted earnings per share
Net income from continuing operations	$	735.75		$	6361.85		$	79.2		$	125.3
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Income before discontinued operations available to common shareholders - Diluted	$	735.64		$	6361.63		$	79.0		$	124.9
Income (loss) from discontinued operations, net	$	(0.12	)	$	(549.87	)	$	(0.1	)	$	(55.5	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Diluted	$	(0.12	)	$	(549.87	)	$	(0.1	)	$	(55.5	)
Net income	$	735.83		$	5811.08		$	79.1		$	69.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Net income available to common shareholders - Diluted	$	735.72		$	5711.86		$	78.9		$	69.4
Unadjusted average common shares outstanding - Diluted		234.03			~~232~~233.80			234.1			232.9
Assumed conversion of stock options, unvested restricted stock, unvested RSUs and contingent performance shares, net		1.2			0.76			1.3			0.6
Average common shares outstanding - Diluted		235.25			233.56			235.4			233.5
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.3103		$	0.2726		$	0.34		$	0.53
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.0		$	(0.0221	)	$	0.0		$	(0.23	)
Earnings per share available to common shareholders - Diluted	$	0.3103		$	0.2505		$	0.34		$	0.30
Anti-dilutive shares		0.20			0.14			0.3			0.3

1618

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~~a suit was 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,. The suit remains pending, with a trial currently expected in October 2016. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

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. In late May 2016, ~~which~~a issettlement ~~pending~~was reached with all the named plaintiffs in the subrogation lawsuits.

~~Proceedings~~The insettlements ~~connection~~are ~~with~~not material to the ~~Pending~~company’s ~~Merger~~financial ~~with~~position ~~Emera~~as of June 30, 2016.

Proceedings in connection with the 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.

1719

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~~Subsequent to the ~~terms~~Merger ofclosing the ~~Memorandum~~parties ofare ~~Understanding,~~expected ~~the~~to ~~parties~~enter ~~will~~into ~~negotiate~~ a formal settlement agreement ~~and~~in ~~submit~~August, itwhich towill ~~the~~be ~~court~~filed ~~for~~with ~~approval~~the ~~after~~Hillsborough ~~the~~Circuit ~~Merger~~Court isJudge ~~complete~~for approval. 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. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

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. While the outcome of such matter is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

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.~~June 3130, 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.

1820

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.

Merger Commitments

In connection with the Merger with Emera, TECO Energy made certain commitments approved by the NMPRC. See Note 16 for additional information.

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.~~June 3130, 2016 is as follows:

(millions)							Maximum
					After (1)		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at ~~Mar.~~June 3130, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	9293.9	$	9293.9	$	0.0
Letters of indemnity - coal mining permits (3)		8985.49		0.0		0.0		8985.49		0.0
	$	8985.49	$	0.0	$	9293.9	$	~~182~~179.38	$	0.0
							Maximum
(millions)					After (1)		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at ~~Mar.~~June 3130, 2016 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.08
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.19
(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.
(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 June 30, 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.
(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. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred, subject to the indemnification terms set forth in the SPA, 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.

(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 June 30, 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 June 30, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

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
Segment Information (1)
(millions)	Tampa		Peoples		New Mexico			TECO											TECO
Three months ended June 30,	Electric		Gas		Gas Co. (2)			Coal (1)			Other (2)				Eliminations				Energy
2016
Revenues - external	$	~~423~~498.41	$	~~126~~99.89	$	~~106~~51.67		$	0.0		$	2.76			$	0.0			$	~~659~~652.53
Sales to affiliates		1.1		42.40		0.0			0.0			0.0				(53.51	)			0.0
Total revenues		~~424~~499.52		~~131~~101.29		~~106~~51.67			0.0			2.76				(53.51	)			~~659~~652.53
Depreciation and amortization		66.15		14.89		8.45			0.0			0.53				0.0				8990.82
Total interest charges		2322.86		3.7		3.03			0.0			1514.65				(0.23	)			4543.98
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		2736.49		94.26		9.(0.1	)		0.0			(517.71	)			0.0				3924.93
Net income (loss) from continuing operations		4868.26		147.61		13(0.92	)		0.0			(1270.90	)	(5)		0.0				635.85
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0			(60.0	)		(0.2	)			0.0				(50.82	)
Net income (loss)	$	4868.26	$	147.61	$	13(0.92	)	$	(60.0	)	$	(1270.72	)		$	0.0			$	585.03
At Mar. 31, 2016
2015
Total assets	$	6,988.2	$	1,147.0	$	1,210.9		$	0.0		$	1,982.1			$	(2,347.1	)	(4)	$	8,981.1
Revenues - external	$	531.6	$	92.2	$	54.0		$	0.0		$	2.8			$	0.0			$	680.6
At Dec. 31, 2015
Sales to affiliates		0.8		1.3		0.0			0.0			0.1				(2.2	)			0.0
Total assets (3)	$	7,003.8	$	1,136.1	$	1,229.7		$	0.0		$	1,945.1			$	(2,381.2	)	(4)		8,933.5
Total revenues		532.4		93.5		54.0			0.0			2.9				(2.2	)			680.6
(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.
Depreciation and amortization		64.0		14.0		8.4			0.0			0.6				0.0				87.0
(2) NMGI is included in the Other segment.
Total interest charges		23.6		3.6		3.3			0.0			16.3				(0.4	)			46.4
(3) Certain prior year amounts have been reclassified to conform to current year presentation.
Internally allocated interest		0.0		0.0		0.0			0.0			0.4				(0.4	)			0.0
(4) Amounts primarily relate to intercompany advances and consolidated tax eliminations.
Provision (benefit) for income taxes		38.9		4.8		0.0			0.0			(3.2	)			0.0				40.5
Net income (loss) from continuing operations		67.7		7.6		(0.1	)		0.0			(13.7	)			0.0				61.5
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0			(51.5	)		1.8				0.0				(49.7	)
Net income (loss)	$	67.7	$	7.6	$	(0.1	)	$	(51.5	)	$	(11.9	)		$	0.0				11.8

2022

(millions)	Tampa		Peoples		New Mexico		TECO											TECO
Six months ended June 30,	Electric		Gas		Gas Co. ⁽²⁾		Coal ⁽¹⁾			Other ⁽²⁾				Eliminations				Energy
2016
Revenues - external	$	921.5	$	226.7	$	158.3	$	0.0		$	5.3			$	0.0			$	1,311.8
Sales to affiliates		2.2		6.4		0.0		0.0			0.0				(8.6	)			0.0
Total revenues		923.7		233.1		158.3		0.0			5.3				(8.6	)			1,311.8
Depreciation and amortization		132.6		29.7		16.9		0.0			0.8				0.0				180.0
Total interest charges		46.4		7.4		6.3		0.0			30.1				(0.5	)			89.7
Internally allocated interest		0.0		0.0		0.0		0.0			0.5				(0.5	)			0.0
Provision (benefit) for income taxes		64.7		13.5		9.6		0.0			(27.8	)			0.0				60.0
Net income (loss) from continuing operations		118.8		20.2		15.0		0.0			(74.8	)	⁽⁵⁾		0.0				79.2
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0		0.0			(0.1	)			0.0				(0.1	)
Net income (loss)	$	118.8	$	20.2	$	15.0	$	0.0		$	(74.9	)		$	0.0			$	79.1
2015
Revenues - external	$	981.4	$	213.9	$	173.0	$	0.0		$	5.3			$	0.0			$	1,373.6
Sales to affiliates		1.6		2.5		0.0		0.0			0.1				(4.2	)			0.0
Total revenues		983.0		216.4		173.0		0.0			5.4				(4.2	)			1,373.6
Depreciation and amortization		126.9		27.9		16.8		0.0			0.9				0.0				172.5
Total interest charges		47.1		7.1		6.6		0.0			34.2				(0.7	)			94.3
Internally allocated interest		0.0		0.0		0.0		0.0			0.7				(0.7	)			0.0
Provision (benefit) for income taxes		66.3		14.0		9.0		0.0			(8.9	)			0.0				80.4
Net income (loss) from continuing operations		115.9		22.2		13.8		0.0			(26.6	)			0.0				125.3
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0		(57.5	)		2.0				0.0				(55.5	)
Net income (loss)	$	115.9	$	22.2	$	13.8	$	(57.5	)	$	(24.6	)		$	0.0			$	69.8
At June 30, 2016
Total assets	$	7,103.4	$	1,135.9	$	1,200.9	$	0.0		$	1,945.8			$	(2,306.3	)	⁽⁴⁾		9,079.7
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.
(5) Comprised primarily of transaction costs associated with the Merger with Emera. See Note 16.

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.~~June 3130, 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.~~June 3130, 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 $05.05 million and $0.2 million as of ~~Mar.~~June 3130, 2016 and Dec. 31, 2015, respectively~~, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets~~. Derivative liabilities totaled $231.1 million and $26.2 million as of ~~Mar.~~June 3130, 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.~~June 3130, 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.~~June 3130, 2016, net pretax losses of $~~22.~~3.0 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.~~June 3130, 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 and six months ended ~~Mar.~~June 3130, 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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the three and six months ended ~~Mar.~~June 3130, 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.~~June 2830, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of ~~Mar.~~June 3130, 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		2519.13
2017		0.0		917.97
2018		0.0		02.76
Total		0.0		3539.76

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.~~June 3130, 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:

2225

(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

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
	As of June 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	5.5	$	0.0	$	5.5
Liabilities
Natural gas derivatives	$	0.0	$	231.1	$	0.0	$	231.1
	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.~~June 3130, 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.

As of June 30, 2016 and Dec. 31, 2015, the carrying value of the company’s short-term debt is not materially different from the fair value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value is determined using Level 2 measurements. See Note 7 for information regarding the fair value of the company’s long-term debt.

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.

2326

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 $16.4 million and $29.0 million under these PPAs for the three and six months ended June 30, 2016, respectively, and $9.9 million and $15.3 million for the three and six months ended June 30, 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.

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~~has not ~~have~~had 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						Six months ended
	Mar. 31,
	June 30,						June 30,
(millions)	2016			2015			2016			2015
Revenues—TECO Coal	$	0.0		$	7276.71		$	0.0		$	148.8
Loss from operations—TECO Coal		0.0			(9.5	)
Income (loss) from operations—TECO Coal		(0.3	)		0.5			(0.1	)		(9.0	)
Loss from operations—TECO Guatemala		0.0			(0.1	)
Loss on impairment—TECO Coal		0.0			(78.6	)		0.0			(78.6	)
Income (loss) from discontinued operations—TECO Coal		0.2			(9.5	)
Loss from operations—TECO Guatemala		(0.1	)		0.0			(0.1	)		(0.1	)
Loss from discontinued operations—TECO Guatemala		0.0			(0.1	)
Loss from discontinued operations—TECO Coal		(0.3	)		(78.1	)		(0.1	)		(87.6	)
Income (loss) from discontinued operations		0.2			(9.6	)
Loss from discontinued operations—TECO Guatemala		(0.1	)		0.0			(0.1	)		(0.1	)
Provision (benefit) for income taxes		0.1			(3.8	)
Loss from discontinued operations		(0.4	)		(78.1	)		(0.2	)		(87.7	)
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Benefit for income taxes		(0.2	)		(28.4	)		(0.1	)		(32.2	)
Loss from discontinued operations, net	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)

16. Mergers and Acquisitions

~~Pending~~ Merger with Emera Inc.

OnDescription ~~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.~~ Transaction

~~Upon~~On ~~the~~July ~~terms~~1, 2016, TECO Energy and ~~subject~~Emera tocompleted the ~~conditions~~Merger ~~set~~contemplated ~~forth~~by in the Merger Agreement, ~~which~~entered ~~was~~into ~~unanimously~~on ~~approved~~Sept. 4, ~~and~~2015. ~~adopted~~As bya ~~the~~result ~~board~~ of ~~directors of TECO Energy, at~~ the ~~effective time~~Merger, Merger Sub ~~will~~merged ~~merge~~ with and into TECO Energy with TECO Energy continuing as the surviving corporation. and becoming a wholly owned indirect subsidiary of Emera.

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~~was 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 $10.47 billion including ~~assumption~~Emera’s purchase price allocation for debt of approximately $34.92 billion ~~of debt~~.

24The Merger Agreement requires Emera, among other things, (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.

~~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~~Related ~~Act~~Regulatory 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. Matters

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~~then ~~case currently~~ pending ~~before~~proceeding seeking the ~~NMPRC for~~ approval of the ~~transaction. In~~Merger ~~the~~by ~~stipulation,~~ the ~~parties~~NMPRC. ~~state~~On ~~that~~May ~~they~~2, ~~believe~~2016, the ~~settlement~~Hearing isExaminer inheld ~~the~~a ~~public~~hearing ~~interest and have recommended approval~~ to ~~the~~consider ~~NMPRC. Amongst other elements,~~ the stipulation ~~includes~~agreement. ~~Emera’s~~On ~~agreement~~June to8, ~~maintain~~2016, the ~~commitments~~Hearing ~~made~~Examiner byfiled ~~TECO~~a ~~Energy~~Certificate ~~in its 2014 case relating to its acquisition~~ of ~~NMGC~~Stipulation, ~~invest~~recommending inapproval by the ~~expansion~~NMPRC of the ~~natural~~stipulation ~~gas~~with ~~system~~respect to ~~underserved~~which ~~communities~~all ~~and~~intervenors ~~the~~had ~~Mexican~~either ~~border,~~consented ~~and~~or ~~provide~~filed ~~resources~~a tonotice ~~support~~of ~~certain economic growth projects and programs~~non-opposition. ~~The~~ On ~~stipulation~~June is22, ~~subject~~2016, ~~to review and approval by~~ the NMPRC. ~~The~~approved ~~NMPRC~~the ~~hearing~~stipulation, toand ~~consider~~an ~~the~~order ~~acquisition~~was isentered ~~scheduled~~on tothat ~~begin~~same ~~in May 2016~~day.

~~The~~As ~~Merger~~part ~~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~~stipulation ~~course~~agreement ~~during~~filed ~~the~~with ~~interim period between~~ the ~~execution~~NMPRC ofnoted ~~the~~above, ~~Merger~~upon ~~Agreement and the~~ closing of the Merger, ~~and~~NMGC ~~(ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera~~agreed, among ~~others~~other things, ~~that Emera will use its reasonable best efforts~~ to ~~take all actions necessary to obtain all governmental and regulatory approvals.~~ :

In· ~~addition,~~make ~~the~~commitments ~~Merger Agreement requires Emera (i)~~ to ~~maintain TECO Energy’s historic levels of community involvement and~~ charitable contributions and ~~support~~enterprises inengaged ~~TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters~~ in ~~Tampa,~~economic ~~Florida,~~and ~~(iii) to~~business ~~honor~~development ~~current union contracts~~ in ~~accordance~~New ~~with~~Mexico ~~their~~of ~~terms~~$0.8 ~~and~~million ~~(iv)~~annually ~~to provide each continuing non-union employee,~~ for athree ~~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~~continue ~~is also subject~~ to aprovide ~~“no~~an ~~shop”~~annual ~~restriction~~bill ~~that~~reduction ~~limits~~credit ~~its~~of ~~ability~~$4 tomillion ~~solicit~~through ~~alternative~~June ~~acquisition proposals or provide nonpublic information to~~30, ~~and engage in discussion with~~2018, ~~third parties.~~

~~Either~~· ~~party~~evaluate ~~may~~and ~~terminate~~construct, ~~the~~at ~~Merger~~shareholder ~~Agreement if (i) the closing of the Merger has not occurred by Sept. 30~~expense, ~~2016~~an ~~(subject~~enlarged topipeline afrom ~~6-month~~its ~~extension~~current ifsystem ~~required~~ to ~~obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting~~ the ~~closing~~New ofMexico/Mexican ~~the~~border ~~Merger~~at ~~has~~an ~~become~~estimated ~~final.~~cost ~~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 approximately $~~326.9~~5 million. ,

~~During~~· ~~the~~establish, ~~three~~at ~~months~~shareholder ~~ended Mar. 31~~expense, ~~2016,~~a ~~TECO~~matching ~~Energy~~fund ~~incurred~~of ~~approximately~~ $~~0.1~~10 million ~~pretax~~to ofextend ~~incremental~~its ~~transaction-related~~natural ~~costs,~~gas ~~which~~infrastructure ~~are~~to ~~included~~currently inunderserved ~~“Operations~~or ~~and~~unserved ~~maintenance~~areas ~~other~~in ~~expense”~~New onMexico, ~~the Consolidated Condensed Statements of Income.~~and

25· contribute, at shareholder expense, $5 million within 5 years to economic development projects or programs throughout New Mexico.

The preceding pretax costs of up to $30.4 million (or approximately $18.5 million after tax) will be recorded in the third quarter of 2016 in the Consolidated Condensed Statements of Income.

Transaction-Related Costs

During the three and six months ended June 30, 2016, TECO Energy incurred approximately $71.4 million and $71.5 million, respectively, of pretax incremental transaction-related costs ($58.4 million after tax for the three months ended June 30, 2016), which are presented in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income. For the three months ended June 30, 2016, these costs include $27.7 million of investment banking, legal and other consultant costs, $42.4 million for change-in-control and other compensation payments, and $1.3 million for a non-cash SERP curtailment charge. These costs are expected to be primarily paid in the third quarter of 2016 and the first quarter of 2017. The company will record $15.2 million in the third quarter of 2016, primarily for accelerated vesting of outstanding stock-based compensation awards in accordance with the Merger Agreement which will be paid in the third quarter of 2016.

See Notes 4 and 5 for information regarding impacts to the company’s taxes and employee postretirement benefits, respectively, as a result of the Merger.

Dividends Paid

On June 22, 2016, in preparation for the Merger with Emera and in accordance with the Merger Agreement, the TECO Energy board of directors declared a special pro-rated dividend at the then-current rate of $0.002527 per share per day that accrued from May 16, 2016 (the prior TECO Energy dividend record date) until and including June 30, 2016 (the day prior to the effective day of the Merger). This dividend was accrued on the company’s Consolidated Condensed Balance Sheet as of June 30, 2016. On July 12, 2016, TECO Energy paid the dividends of $26.8 million to shareholders of record as of the close of business on the last trading day prior to the effective date of the Merger.

17. Subsequent Events

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, Merger Sub merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	~~Mar.~~June 3130,			Dec. 31,
(millions)	2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,~~328~~419.35		$	7,270.3
Gas		1,~~419~~447.30			1,398.6
Construction work in progress		~~797~~832.01			771.1
Utility plant in service, at original costs		9,~~544~~698.6			9,440.0
Accumulated depreciation		(2,~~720~~762.30	)		(2,676.8	)
Utility plant in service, net		6,~~824~~936.36			6,763.2
Other property		910.92			9.7
Total property, plant and equipment, net		6,~~834~~946.28			6,772.9
Current assets
Cash and cash equivalents		2813.28			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
Receivables, less allowance for uncollectibles of $1.6 and $1.5 at June 30, 2016 and Dec. 31, 2015, respectively		238.7			230.2
Inventories, at average cost
Fuel		~~115~~102.42			105.6
Materials and supplies		7375.61			73.1
Regulatory assets		3918.90			44.3
Taxes receivable from affiliate		0.0			61.3
Prepayments and other current assets		1720.06			21.5
Total current assets		~~479~~468.64			545.1
Deferred debits
Regulatory assets		373.18			373.8
Other		1727.97			16.8
Total deferred debits		~~391~~401.05			390.6
Total assets	$	7,~~704~~816.87		$	7,708.6

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

2630

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	~~Mar.~~June 3130,			Dec. 31,
(millions)	2016			2015
Capitalization
Common stock	$	2,~~330~~395.4		$	2,305.4
Accumulated other comprehensive loss		(3.42	)		(3.6	)
Retained earnings		~~314~~270.46			313.7
Total capital		2,~~641~~662.48			2,615.5
Long-term debt		2,162.03			2,161.7
Total capitalization		4,~~803~~825.41			4,777.2
Current liabilities
Long-term debt due within one year		830.30			83.3
Notes payable		0123.0			61.0
Accounts payable		~~174~~209.65			221.6
Customer deposits		~~170~~162.97			176.3
Regulatory liabilities		~~104~~124.54			83.2
Derivative liabilities		220.27			24.1
Interest accrued		4117.27			16.9
Taxes accrued		3372.62			13.2
Other		10.10			10.2
Total current liabilities		~~640~~720.42			689.8
Deferred credits
Deferred income taxes		1,~~342~~352.01			1,308.8
Investment tax credits		10.43			10.5
Derivative liabilities		0.8			2.1
Regulatory liabilities		608.0			603.5
Regulatory liabilities		595.5			603.5
Deferred credits and other liabilities		301.0			318.8
Deferred credits and other liabilities		312.3			316.7
Total deferred credits		2,271.4			2,241.6
Total deferred credits		2,261.0			2,241.6
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	7,~~704~~816.87		$	7,708.6

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

2731

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
	Three months ended June 30,
(millions)	2016			2015
Revenues
Electric	$	~~424~~498.28		$	~~450~~532.4
Gas		~~126~~100.80			~~121~~92.72
Total revenues		~~551~~598.08			~~572~~624.16
Expenses
Regulated operations and maintenance
Fuel		~~115~~137.14			~~144~~171.18
Purchased power		1427.48			1719.16
Cost of natural gas sold		5035.37			4330.31
Other		~~121~~132.25			~~121~~134.83
Depreciation and amortization		8081.94			7678.80
Taxes, other than income		4847.5			4749.65
Total expenses		~~430~~462.43			~~450~~483.73
Income from operations		~~120~~136.65			~~121~~141.43
Other income
Allowance for other funds used during construction		5.6.0			3.87
Other income, net		10.39			1.2
Total other income		6.9			54.09
Interest charges
Interest on long-term debt		2927.08			27.78
Interest expense		1.2			1.1
Other interest		1.2			1.2
Allowance for borrowed funds used during construction		(2.78	)		(1.8	)
Total interest charges		2726.52			27.02
Income before provision for income taxes		~~100~~117.02			99119.40
Provision for income taxes		3641.75			3643.67
Net income		6375.37			6275.83
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			02.38
Total other comprehensive income, net of tax		0.2			02.38
Comprehensive income	$	6375.59		$	6378.1

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

2832

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Six months ended June 30,
(millions)	2016			2015
Revenues
Electric	$	923.0		$	982.8
Gas		226.8			213.9
Total revenues		1,149.8			1,196.7
Expenses
Regulated operations and maintenance
Fuel		252.6			315.9
Purchased power		42.2			36.7
Cost of natural gas sold		86.0			73.4
Other		253.6			256.1
Depreciation and amortization		162.3			154.8
Taxes, other than income		96.0			97.1
Total expenses		892.7			934.0
Income from operations		257.1			262.7
Other income
Allowance for other funds used during construction		11.6			7.5
Other income, net		2.2			2.4
Total other income		13.8			9.9
Interest charges
Interest on long-term debt		56.8			55.5
Interest expense		2.4			2.3
Allowance for borrowed funds used during construction		(5.5	)		(3.6	)
Total interest charges		53.7			54.2
Income before provision for income taxes		217.2			218.4
Provision for income taxes		78.2			80.3
Net income		139.0			138.1
Other comprehensive income, net of tax
Gain on cash flow hedges		0.4			3.1
Total other comprehensive income, net of tax		0.4			3.1
Comprehensive income	$	139.4		$	141.2

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

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
	Six months ended June 30,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	63139.30		$	62138.81
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80162.93			76154.8
Deferred income taxes and investment tax credits		3036.45			2130.20
Allowance for funds used during construction		(511.6	)		(37.85	)
Deferred recovery clauses		2741.0			(43.72	)
Receivables, less allowance for uncollectibles		24(8.75	)		13(24.54	)
Inventories		~~(10~~1.34	)		(2142.1	)
Prepayments		4.63			(56.02	)
Taxes accrued		81120.73			7293.71
Interest accrued		240.38			222.90
Accounts payable		~~(41~~3.26	)		(2814.3	)
Other		(1125.69	)		(614.9	)
Cash flows from operating activities		~~268~~463.2			~~200~~305.14
Cash flows from investing activities
Capital expenditures		(~~150~~353.58	)		(~~148~~312.84	)
Cash flows used in investing activities		(150.5	)		(148.8	)
Net proceeds from sale of assets		8.7			0.0
Cash flows used in investing activities		(345.1	)		(312.4	)
Cash flows from financing activities
Common stock		2590.0			2030.0
Net decrease in short-term debt		(61.0	)		(11.0	)
Proceeds from long-term debt issuance		0.0			251.3
Dividends		(62.6	)		(55.7	)
Repayment of long-term debt		(83.3	)		(83.3	)
Cash flows used in financing activities		(98.6	)		(46.7	)
Net decrease in short-term debt		62.0			(58.0	)
Net increase in cash and cash equivalents		19.1			4.6
Dividends		(182.1	)		(109.5	)
Cash flows from (used in) financing activities		(113.4	)		30.5
Net increase in cash and cash equivalents		4.7			23.5
Cash and cash equivalents at beginning of period		9.1			10.4
Cash and cash equivalents at end of period	$	2813.28		$	1533.09
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(413.89	)	$	111.45

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

2934

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.~~June 3130, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended ~~Mar.~~June 3130, 2016 and 2015. The results of operations for the three and six months ended ~~Mar.~~June 3130, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

Revenues

As of ~~Mar.~~June 3130, 2016 and Dec. 31, 2015, unbilled revenues of $5666.86 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 $2728.96 million and $2756.45 million for the three and six months ended ~~Mar.~~June 3130, 2016, respectively, and $29.3 million and $56.6 million for the three and six months ended June 30, 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.~~June 3130, 2016 and Dec. 31, 2015, TEC classified $17.95 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.~~

3035

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~~will to adopt this guidance effective Jan. 1, 2018,. TEC has developed an implementation plan 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.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. In addition, the guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective for TEC beginning in 2020, with early adoption permitted in 2019, 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.

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)	June 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	80.6	$	74.6
Cost-recovery clauses - deferred balances ⁽²⁾		2.5		5.2
Cost-recovery clauses - offsets to derivative liabilities⁽²⁾		0.8		26.2
Environmental remediation⁽³⁾		54.6		54.0
Postretirement benefits ⁽⁴⁾		234.3		238.3
Deferred bond refinancing costs⁽⁵⁾		6.1		6.5
Competitive rate adjustment ⁽²⁾		2.5		2.6
Other		10.4		10.7
Total regulatory assets		391.8		418.1
Less: Current portion		18.0		44.3
Long-term regulatory assets	$	373.8	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.3	$	5.7
Cost-recovery clauses ⁽²⁾		92.5		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal⁽⁶⁾		564.7		570.0
Other		13.8		0.7
Total regulatory liabilities		732.4		686.7
Less: Current portion		124.4		83.2
Long-term regulatory liabilities	$	608.0	$	603.5

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)

(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)

(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)

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

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~~six months ended ~~Mar.~~June 3130, 2016 and 2015 differ from the statutory rate principally due to ~~state income taxes,~~ the ~~domestic~~tax ~~activity~~benefit ~~production~~related ~~deduction~~to ~~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 (CAP). Due to the Merger with Emera, TECO Energy is only eligible to participate in the CAP through its short tax year ending June 30, 2016. 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.

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.~~June 3130, 2016 and 2015, respectively, was $23.92 million and $24.62 million for pension benefits, and $1.5 million and $1.45 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2016 and 2015, respectively, was $6.1 million and $6.8 million for pension benefits, and $3.0 million and $2.9 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 $415.76 million and $1424.95 million to its pension plan in the ~~three~~six months ended ~~Mar.~~June 3130, 2016 and 2015, respectively. TEC’s portion of the contributions was $312.9 million and $1118.05 million, respectively.

Included in the benefit expenses discussed above, for the three and six months ended ~~Mar.~~June 3130, 2016 ~~and 2015~~, TEC reclassified $2.08 million and $1 4.98 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.8 million and $4.7 million for the three and six months ended June 30, 2015, respectively.

6. Short-Term Debt

AtDetails ~~Mar.~~of ~~31, 2016 and Dec. 31, 2015,~~ the ~~following~~ credit facilities and related borrowings ~~existed~~are presented in the following table:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
	June 30, 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		0123.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0123.0	$	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.

7. Long-Term Debt

Fair Value of Long-Term Debt

At ~~Mar.~~June 3130, 2016, TEC’s total long-term debt had a carrying amount of $2,~~245~~162.3 million and an estimated fair market value of $2,~~483~~446.12 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~~The fair value of debt securities ~~are~~totaling $58.8 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 ~~instruments~~measurements (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.

33As of June 30, 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.

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

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.~~

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

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.~~June 3130, 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.~~June 3130, 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.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at June 30, 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.~~June 3130, 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
Three months ended June 30,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	~~424~~498.28	$	~~126~~100.80	$	0.0		$	~~551~~598.08
Intracompany sales		0.34		41.49		(42.73	)		0.0
Total revenues		~~424~~499.52		~~131~~101.29		(42.73	)		~~551~~598.08
Depreciation and amortization		66.15		14.89		0.0			8081.94
Total interest charges		2322.86		3.7		(0.01	)		2726.52
Provision for income taxes		2736.89		84.96		0.0			3641.75
Net income	$	5068.26	$	137.1	$	0.0		$	6375.37
2015
Revenues - external	$	~~450~~532.4	$	~~121~~92.72	$	0.0		$	~~572~~624.16
Intracompany sales		0.20		1.23		(1.43	)		0.0
Total revenues		~~450~~532.64		~~122~~93.95		(1.43	)		~~572~~624.16
Depreciation and amortization		6264.90		1314.90		0.0			7678.80
Total interest charges		23.56		3.56		0.0			27.02
Provision for income taxes		2738.49		94.28		0.0			3643.67
Net income	$	4867.27	$	147.6	$	0.0		$	6275.83
Total assets at Mar. 31, 2016	$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Six months ended June 30,
2016
Revenues - external	$	923.0	$	226.8	$	0.0		$	1,149.8
Intracompany sales		0.7		6.3		(7.0	)		0.0
Total revenues		923.7		233.1		(7.0	)		1,149.8
Depreciation and amortization		132.6		29.7		0.0			162.3
Total interest charges		46.4		7.4		(0.1	)		53.7
Provision for income taxes		64.7		13.5		0.0			78.2
Net income	$	118.8	$	20.2	$	0.0		$	139.0
2015
Revenues - external	$	982.8	$	213.9	$	0.0		$	1,196.7
Intracompany sales		0.2		2.5		(2.7	)		0.0
Total revenues		983.0		216.4		(2.7	)		1,196.7
Depreciation and amortization		126.9		27.9		0.0			154.8
Total interest charges		47.1		7.1		0.0			54.2
Provision for income taxes		66.3		14.0		0.0			80.3
Net income	$	115.9	$	22.2	$	0.0		$	138.1
Total assets at June 30, 2016	$	6,720.1	$	1,099.8	$	(3.2	)	$	7,816.7
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.

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.~~June 3130, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at ~~Mar.~~June 3130, 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~~Derivative ~~were~~assets nototaled ~~derivative~~$4.9 ~~assets~~million and $0.0 as of ~~Mar.~~June 3130, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $~~23.~~0.7 million and $26.2 million as of ~~Mar.~~June 3130, 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.~~June 3130, 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.~~June 3130, 2016, net pretax losses of $~~22.~~2.7 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.~~June 3130, 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.

36The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to June 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of June 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

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		17.0
2017		0.0		13.9
2018		0.0		2.6
Total		0.0		33.5

	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. 42

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of June 30, 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

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

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. 43

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

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 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 June 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	4.9	$	0.0	$	4.9

Liabilities
Natural gas swaps	$	0.0	$	0.7	$	0.0	$	0.7

	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.~~June 3130, 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 June 30,	~~Three months ended Mar. 31,~~									Six months ended June 30,
(millions)	Gross	~~Gross~~		Tax	~~Tax~~			Net	~~Net~~		Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	$0.0	~~0.0~~	$	$0.0	~~0.0~~		$	$0.0	~~0.0~~	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3	~~0.3~~		(0.1	~~(0.1~~)	)		0.2	~~0.2~~		0.7		(0.3	)		0.4
Gain on cash flow hedges		0.3	~~0.3~~		(0.1	~~(0.1~~)	)		0.2	~~0.2~~		0.7		(0.3	)		0.4
Total other comprehensive income	$	$0.3	~~0.3~~	$	$(0.1	~~(0.1~~)	)	$	$0.2	~~0.2~~	$	0.7	$	(0.3	)	$	0.4
2015
Unrealized gain on cash flow hedges	$	$4.0	~~0.3~~	$	$(1.4	~~(0.2~~)	)	$	$2.6	~~0.1~~	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		0.3	~~0.4~~		(0.1	~~(0.2~~)	)		0.2	~~0.2~~		0.7		(0.4	)		0.3
Gain on cash flow hedges		4.3	~~0.7~~		(1.5	~~(0.4~~)	)		2.8	~~0.3~~		5.0		(1.9	)		3.1
Total other comprehensive income	$	$4.3	~~0.7~~	$	$(1.5	~~(0.4~~)	)	$	$2.8	~~0.3~~	$	5.0	$	(1.9	)	$	3.1

Accumulated Other Comprehensive Loss
(millions)	June 30, 2016	~~Mar. 31, 2016~~			Dec. 31, 2015	~~Dec. 31, 2015~~
Net unrealized losses from cash flow hedges (1)	$	$(3.2	~~(3.4~~)	)	$	$(3.6	~~(3.6~~)	)
Total accumulated other comprehensive loss	$	$(3.2	~~(3.4~~)	)	$	$(3.6	~~(3.6~~)	)

38(1) Net of tax benefit of $2.0 million and $2.3 million as of June 30, 2016 and Dec. 31, 2015, respectively.

~~(1) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.~~44

13. Variable Interest Entities

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 $1216.64 million and $529.40 million under these PPAs for the three and six months ended ~~Mar.~~June 3130, 2016, respectively, and $9.9 million and $15.3 million for the three and six months ended June 30, 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.

OnAs ~~Sept~~disclosed in Note 1, TEC is a wholly owned subsidiary of TECO Energy. 4 On July 1, ~~2015~~2016, TECO Energy and Emera ~~entered~~completed ~~into~~the Merger contemplated by the Merger Agreement entered into on Sept. 4, ~~Upon~~2015. ~~closing~~As a result of the Merger, Merger Sub merged with and into TECO Energy ~~will~~with ~~become~~TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016.

~~Upon~~Pursuant to the ~~terms~~Merger ~~and~~Agreement, ~~subject~~upon tothe closing of the ~~conditions~~Merger, ~~set~~each ~~forth~~issued inand ~~the~~outstanding ~~Merger~~share ~~Agreement,~~of ~~which~~TECO ~~was~~Energy ~~unanimously~~common ~~approved~~stock was cancelled and ~~adopted~~converted byautomatically into the ~~board~~right ofto ~~directors~~receive of$27.55 ~~TECO~~in ~~Energy~~cash, atwithout ~~the~~interest ~~effective~~(Merger ~~time,~~Consideration). ~~Merger~~This ~~Sub~~represents ~~will~~an ~~merge~~aggregate ~~with~~purchase ~~and~~price ~~into~~of ~~TECO~~approximately ~~Energy~~$10.7 ~~with~~billion ~~TECO~~including ~~Energy~~Emera’s ~~continuing~~purchase asprice ~~the~~allocation ~~surviving~~for ~~corporation~~debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion).

~~Pursuant~~The ~~to the~~ Merger Agreement, ~~upon~~requires ~~the~~Emera, ~~closing~~among ofother ~~the Merger~~things, ~~which~~(i) to ismaintain ~~expected~~TECO toEnergy’s ~~occur~~historic inlevels ~~the~~of ~~summer~~community ofinvolvement ~~2016,~~and ~~each~~charitable ~~issued~~contributions and ~~outstanding~~support ~~share~~in of TECO Energy’s ~~common~~existing ~~stock~~service ~~will~~territories, be(ii) to ~~cancelled~~maintain TECO Energy’s and ~~converted~~TEC’s ~~automatically~~headquarters ~~into~~in ~~the~~Tampa, ~~right~~Florida, (iii) to ~~receive~~honor ~~$27.55~~current union contracts in ~~cash,~~accordance ~~without~~with ~~interest~~their ~~(Merger~~terms ~~Consideration~~and (iv). ~~This~~to ~~represents~~provide aneach ~~aggregate~~continuing ~~purchase~~non-union ~~price~~employee, for a period of ~~approximately~~two ~~$10.4~~years ~~billion~~following ~~including~~the ~~assumption~~closing of ~~approximately~~the ~~$3.9~~Merger, ~~billion~~with ofa ~~debt~~base ~~(of~~salary ~~which~~or ~~TEC’s~~wage ~~portion~~rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those that they received as of ~~debt~~immediately ~~was~~prior ~~$2.3~~to ~~billion)~~the closing.

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 Dec15. 3,Subsequent 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. Events

On ~~Apr.~~July 111, 2016, ~~Emera~~TECO Energy and ~~TECO~~Emera ~~Energy~~completed ~~filed~~the ~~with~~Merger contemplated by the ~~NMPRC~~Merger anAgreement ~~unopposed~~entered ~~stipulation~~into ~~agreement~~on ~~reflecting~~Sept. 4, 2015. As a ~~settlement~~result ~~reached~~of the Merger, Merger Sub merged with ~~certain~~and ~~intervening~~into ~~parties~~TECO inEnergy with TECO Energy continuing as the ~~acquisition~~surviving ~~case~~corporation ~~currently~~and ~~pending~~becoming ~~before~~a ~~the~~wholly ~~NMPRC~~owned ~~for~~indirect ~~approval~~subsidiary of ~~the transaction~~Emera. ~~The~~As ~~stipulation~~TEC is ~~subject~~a towholly ~~review~~owned ~~and~~subsidiary ~~approval~~of byTECO ~~the~~Energy, ~~NMPRC.~~TEC ~~The~~became ~~NMPRC~~an ~~hearing~~indirect towholly ~~consider~~owned ~~the~~subsidiary ~~acquisition~~of isEmera. ~~scheduled~~See toNote ~~begin~~14 infor ~~May~~further ~~2016~~information.

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. 45

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.

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~~retain ~~close~~and motivate the ~~Merger~~workforce ~~with~~during ~~Emera on~~ the ~~anticipated~~period ~~schedule,~~of ifintegration atwith ~~all~~Emera; 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~~Item ~~Energy,~~1A ~~Inc.'s~~Risk ~~Annual~~Factors ~~Report~~of onPart ~~Form~~II ~~10-K~~of ~~for~~this ~~the~~Quarterly ~~period ended Dec~~Report. ~~31, 2015.~~

Acquisition by Emera

On July 1, 2016, the acquisition of TECO Energy by Emera closed. Upon closing, TECO Energy became a wholly owned indirect subsidiary of Emera. Pursuant to the Merger Agreement, upon closing, each issued and outstanding share of TECO Energy common stock was cancelled and converted into the right to receive $27.55 in cash, without interest (see Note 16 to the TECO Energy Consolidated Financial Statements).

Earnings Summary - Unaudited

	Three Months Ended Mar. 31,
	Three Months Ended June 30,						Six Months Ended June 30,
(millions) Except per-share amounts	2016			2015			2016			2015
Consolidated revenues	$	~~659~~652.53		$	~~693~~680.06		$	1,311.8		$	1,373.6
Net income from continuing operations		735.75			6361.85			79.2			125.3
Loss on discontinued operations, net		(0.12	)		(549.87	)		(0.1	)		(55.5	)
Net income		735.83			5811.08			79.1			69.8
Average common shares outstanding
Basic		234.03		~~232.8~~	233.0			234.1		232.9
Diluted	235.25			233.56			235.4			233.5
Earnings per share – basic
Continuing operations	$	0.3103		$	0.2726		$	0.34		$	0.53
Discontinued operations		0.00			(0.0221	)		0.00			(0.23	)
Earnings per share - basic	$	0.3103		$	0.2505		$	0.34		$	0.30
Earnings per share – diluted
Continuing operations	$	0.3103		$	0.2726		$	0.34		$	0.53
Discontinued operations		0.00			(0.0221	)		0.00			(0.23	)
Earnings per share - diluted	$	0.3103		$	0.2505		$	0.34		$	0.30

Operating Results

Three Months Ended ~~Mar.~~June 3130, 2016

~~First~~Second-quarter 2016 net income was $735.83 million, or $0.3103 per share, compared with $5811.08 million, or $0.2505 per share, in the ~~first~~second quarter of 2015. Net income from continuing operations was $735.75 million, or $0.3103 per share, in the 2016 ~~first~~second quarter, compared with $6361.85 million, or $0.2726 per share, for the same period in 2015. Net income from continuing operations in the 2016 period reflects $58.4 million of Emera acquisition-related costs ($71.4 million pretax) (see Note 16 to the TECO Energy Consolidated Financial Statements). The ~~first~~second quarter losses in discontinued operations of $549.87 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).

Six Months Ended June 30, 2016

Year-to-date net income through the second quarter of 2016 was $79.1 million, or $0.34 per share, compared with $69.8 million, or $0.30 per share, in the 2015 year-to-date period. Net income from continuing operations was $79.2 million, or $0.34 per share, in

the 2016 year-to-date period, compared with $125.3 million, or $0.53 per share, for the same period in 2015. Year-to-date 2016 net income reflects $58.5 million of Emera acquisition-related costs. The $55.5 million year-to-date loss in discontinued operations in 2015 reflected the operating results and charges associated with TECO Coal, which was sold in 2015.

Operating Company Results

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

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the ~~first~~second quarter of 2016 was $5068.26 million, compared with $4867.27 million for the same period in 2015. ~~Results~~Second-quarter ~~for~~net ~~the~~income ~~quarter~~in ~~reflected~~2016 aincluded 1$6.7%0 ~~higher~~million ~~average number~~ of ~~customers~~AFUDC-equity, ~~and~~which ~~higher~~represents ~~energy~~allowed ~~sales~~equity ~~primarily~~cost ~~due~~capitalized to ~~the~~construction ~~higher~~costs, ~~number~~compared ofwith ~~customers~~$3.7 ~~Results~~million ~~reflected~~in ~~operations~~the ~~and~~2015 ~~maintenance~~quarter. ~~expense~~Results ~~slightly~~for ~~higher~~the ~~than~~quarter ~~2015,~~reflected ~~and~~a 1.6% higher ~~depreciation~~average ~~and~~number ~~interest~~of ~~expenses~~customers. ~~First-quarter~~Energy ~~net~~sales ~~income~~were inlower ~~2016~~due ~~included~~to ~~$5.6~~more ~~million~~normal ofweather ~~AFUDC-equity,~~compared ~~which~~to ~~represents~~the ~~allowed~~second ~~equity~~quarter ~~cost~~of ~~capitalized~~2015 towhen ~~construction~~consistently ~~costs,~~higher ~~compared~~than ~~with~~normal $3spring temperatures were experienced.8 ~~million~~Results inreflected ~~the~~operations and maintenance expense slightly higher than in 2015 ~~quarter~~and higher depreciation expenses.

Total degree days in Tampa Electric's service area in the ~~first~~second quarter of 2016 were 35% above normal, but 410% below the 2015 period, when degree days were 615% above normal. Total net energy for load ~~increased~~decreased 12.76% in the ~~first~~second quarter of 2016, compared with the same period in 2015. In the 2016 period, pretax base revenues were $6.2.5 million ~~higher~~lower than in 2015, ~~driven~~as bylower ~~customer~~energy ~~growth~~sales ~~and~~from ~~higher~~more ~~energy~~normal ~~sales.~~weather ~~The~~was ~~quarter~~only ~~included~~partially ~~more~~offset ~~than~~by customer growth and $1.6 million of higher pretax base revenue from higher base rates effective Nov. 1, 2015, 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~~decreased in the second quarter of 2016 primarily ~~from~~due to milder weather ~~and~~compared ~~customer~~to ~~growth~~the 2015 quarter when spring temperatures were higher. 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 and mining activity migrates out of Tampa Electric’s service area.

~~Operations~~In the second quarter of 2016 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~~system and ~~distribution~~provide ~~systems~~high-quality customer service, 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 $21.05 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~~year-to-date ~~operating~~net ~~statistics~~income ~~for~~through the ~~three~~second ~~months~~quarter ~~ended~~of ~~Mar~~2016 was $118.8 31million, compared with $115.9 million for the same period in 2015. Year-to-date net income in 2016 included $11.6 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $7.5 million in the 2015 period. Results for the year-to-date period reflected a 1.6% higher average number of customers. Energy sales were lower compared to 2015 due to the well-above-normal second quarter temperatures experienced in the 2015 period. Results reflected operations and maintenance expense slightly higher than in 2015 ~~follows:~~and higher depreciation expense.

(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.

Total degree days in Tampa Electric's service area for the year-to-date period of 2016 were 5% above normal, but 9% below the 2015 period. Total net energy for load decreased 0.9% in the year-to-date 2016 period, compared with the same period in 2015. In the 2016 year-to-date period, pretax base revenues were $3.8 million higher than in 2015, as lower energy sales to residential customers from more normal weather was more than offset by customer growth, higher sales to industrial customers, and $2.7 million of higher pretax base revenue from higher base rates effective Nov. 1, 2015 as a result of the 2013 rate case settlement.

In the 2016 year-to-date period, retail energy sales to residential customers decreased primarily from milder spring weather than was experienced in the 2015 period. 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 a result of the same factors as the second quarter.

In the 2016 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was almost $1.0 million higher than in the 2015 period, reflecting higher costs to safely and reliably operate and maintain the generating, transmission and distribution systems and provide high-quality customer service, 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 expense increased $3.5 million in 2016, as a result of normal additions to facilities to reliably serve customers.

A summary of Tampa Electric’s regulated operating statistics for the three and six months ended June 30, 2016 and 2015 follows:

(millions, except average customers and total degree days)	Operating Revenues							Kilowatt-hour sales
Three months ended June 30,	2016		2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	252.6	$	267.4		(5.5	)		2,240.7		2,330.6		(3.9	)
Commercial		147.6		154.9		(4.7	)		1,565.2		1,609.9		(2.8	)
Industrial – Phosphate		12.7		13.8		(8.0	)		158.1		173.2		(8.7	)
Industrial – Other		27.4		27.9		(1.8	)		320.7		319.5		0.4
Other sales of electricity		43.3		44.9		(3.6	)		446.7		456.0		(2.0	)
Deferred and other revenues ⁽¹⁾		1.9		9.3		(79.6	)
Total energy sales	$	485.5	$	518.2		(6.3	)		4,731.4		4,889.2		(3.2	)
Sales for resale		0.7		1.0		(30.0	)		18.3		31.2		(41.3	)
Other operating revenue		13.0		13.3		(2.3	)
Total revenues	$	499.2	$	532.5		(6.3	)		4,749.7		4,920.4		(3.5	)
Average customers (thousands)		729.3		717.9		1.6
Retail net energy for load (kilowatt hours)									5,261.5		5,401.2		(2.6	)
Total degree days									1,255		1,404		(10.6	)

Six months ended June 30,
By Customer Type

Filing Compare · TECO ENERGY INC