10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from to

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.     YES  ☒    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  ☒    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	☐	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	☒	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  ☒

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

As of Nov. 4, 2016, there were 1,000 shares of TECO Energy, Inc.’s common stock outstanding, all of which were held, beneficially and of record, by Emera US Holdings Inc. As of Nov. 4, 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
EUSHI	Emera US Holdings Inc.
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 Company with and into TECO Energy, with TECO Energy as the surviving corporation

2

Term	Meaning
Merger Agreement	Agreement and Plan of Merger dated Sept. 4, 2015, by and among TECO Energy, Emera and Merger Sub Company
Merger Sub Company	Emera US Inc., a Florida corporation
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board
NAV	net asset value
NMGC	New Mexico Gas Company, Inc.
NMGI	New Mexico Gas Intermediate, Inc.
NMPRC	New Mexico Public Regulation Commission
NOL	net operating loss
Note	Note to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
OPC	Office of Public Counsel
OPEB	other postretirement benefits
OTC	over-the-counter
Parent	TECO Energy (the holding company, excluding subsidiaries)
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PGA	purchased gas adjustment
PGAC	purchased gas adjustment clause
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
R&D	research and development
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.

3

Term	Meaning
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

4

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Sept. 30,			Dec. 31,
(millions)	2016			2015
Current assets
Cash and cash equivalents	$	24.4		$	23.8
Receivables, less allowance for uncollectibles of $2.9 and $2.1    at Sept. 30, 2016 and Dec. 31, 2015, respectively		268.2			280.7
Inventories, at average cost
Fuel	85.2			113.4
Materials and supplies		83.7			76.8
Regulatory assets		21.8			44.8
Prepayments and other current assets		24.0			30.8
Total current assets		507.3			570.3
Property, plant and equipment
Utility plant in service
Electric		7,473.9			7,270.3
Gas		2,216.6			2,113.8
Construction work in progress		916.8			794.7
Other property		16.8			15.9
Property, plant and equipment, at original costs		10,624.1			10,194.7
Accumulated depreciation		(2,862.2	)		(2,712.9	)
Total property, plant and equipment, net		7,761.9			7,481.8
Other assets
Regulatory assets		458.7			395.2
Goodwill		408.4			408.4
Deferred charges and other assets		87.4			77.8
Total other assets		954.5			881.4
Total assets	$	9,223.7		$	8,933.5

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

6

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	Sept. 30,			Dec. 31,
(millions, except share amounts)	2016			2015
Current liabilities
Long-term debt due within one year	$	0.0		$	333.3
Notes payable		610.5			247.0
Accounts payable		264.0			255.4
Customer deposits		160.6			182.1
Regulatory liabilities		148.2			84.8
Derivative liabilities		1.6			24.1
Interest accrued		53.1			36.2
Taxes accrued		65.0			13.2
Other		44.5			22.6
Total current liabilities		1,347.5			1,198.7
Other liabilities
Deferred income taxes		650.1			570.7
Investment tax credits		10.2			10.5
Regulatory liabilities		718.8			715.8
Deferred credits and other liabilities		412.6			389.6
Long-term debt, less amount due within one year		3,490.3			3,489.2
Total other liabilities		5,282.0			5,175.8
Commitments and contingencies (see Note 8)
Capital
Common equity (10.0 million shares authorized, par value $0.01 and 1,000 shares outstanding at Sept. 30, 2016; 400.0 million shares authorized, par value $1 and 235.3 million shares outstanding at Dec. 31, 2015)		0.0			235.3
Additional paid in capital		2,154.7			1,894.5
Retained earnings		457.1			441.4
Accumulated other comprehensive loss		(17.6	)		(12.2	)
Total capital		2,594.2			2,559.0
Total liabilities and capital	$	9,223.7		$	8,933.5

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended Sept. 30,
(millions, except per share amounts)	2016			2015
Revenues
Regulated electric	$	585.2		$	559.3
Regulated gas		138.6			131.5
Unregulated		2.9			3.0
Total revenues		726.7			693.8
Expenses
Regulated operations and maintenance
Fuel		173.5			176.6
Purchased power		38.3			23.8
Cost of natural gas sold		53.2			42.0
Other		153.6			150.1
Merger transaction-related costs		37.9			15.4
Depreciation and amortization		92.0			87.8
Taxes, other than income		56.3			51.5
Total expenses		604.8			547.2
Income from operations		121.9			146.6
Other income
Allowance for other funds used during construction		6.5			4.7
Other income, net		2.1			1.4
Total other income		8.6			6.1
Interest charges
Interest expense		47.1			48.4
Allowance for borrowed funds used during construction		(3.2	)		(2.3	)
Total interest charges		43.9			46.1
Income from continuing operations before provision for    income taxes		86.6			106.6
Provision for income taxes		17.2			41.7
Net income from continuing operations		69.4			64.9
Discontinued operations
Loss from discontinued operations		(0.2	)		(17.8	)
Benefit for income taxes		0.2			6.1
Loss from discontinued operations, net		0.0			(11.7	)
Net income	$	69.4		$	53.2

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Nine months ended Sept. 30,
(millions, except per share amounts)	2016			2015
Revenues
Regulated electric	$	1,506.6		$	1,540.8
Regulated gas		522.9			518.1
Unregulated		9.0			8.5
Total revenues		2,038.5			2,067.4
Expenses
Regulated operations and maintenance
Fuel		426.1			492.5
Purchased power		80.5			60.5
Cost of natural gas sold		200.8			194.1
Other		452.2			451.9
Merger transaction-related costs		109.4			15.4
Depreciation and amortization		272.0			260.3
Taxes, other than income		160.8			156.6
Total expenses		1,701.8			1,631.3
Income from operations		336.7			436.1
Other income
Allowance for other funds used during construction		18.1			12.2
Other income, net		4.6			4.4
Total other income		22.7			16.6
Interest charges
Interest expense		142.7			146.4
Allowance for borrowed funds used during construction		(9.1	)		(6.0	)
Total interest charges		133.6			140.4
Income from continuing operations before provision for    income taxes		225.8			312.3
Provision for income taxes		77.2			122.1
Net income from continuing operations		148.6			190.2
Discontinued operations
Loss from discontinued operations		(0.4	)		(105.5	)
Benefit for income taxes		0.3			38.3
Loss from discontinued operations, net		(0.1	)		(67.2	)
Net income	$	148.5		$	123.0

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

9

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2016			2015			2016			2015
Net income	$	69.4		$	53.2		$	148.5		$	123.0
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			0.2			0.6			3.3
Amortization of unrecognized benefit costs and other		0.5			0.2			0.8			1.8
Recognized cost due to curtailment		0.0			0.0			0.1			0.0
Change in benefit obligation due to remeasurement/ valuation		(6.9	)		(5.7	)		(6.9	)		(5.7	)
Recognized cost due to settlement		0.0			7.7			0.0			7.7
Other comprehensive income (loss), net of tax		(6.2	)		2.4			(5.4	)		7.1
Comprehensive income	$	63.2		$	55.6		$	143.1		$	130.1

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

10

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sept. 30,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	148.5		$	123.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		272.0			261.5
Deferred income taxes and investment tax credits		76.5			84.6
Allowance for other funds used during construction		(18.1	)		(12.2	)
Non-cash stock compensation		6.4			10.1
Loss on disposals of business/assets, pretax		(0.3	)		10.0
Deferred recovery clauses		54.5			13.1
Asset impairment, pretax		0.0			78.6
Receivables, less allowance for uncollectibles		12.5			46.1
Inventories		21.3			(45.7	)
Prepayments and other current assets		6.8			(14.2	)
Taxes accrued		54.0			31.6
Interest accrued		16.9			14.7
Accounts payable		27.7			(85.7	)
Other		(27.6	)		(34.6	)
Cash flows from operating activities		651.1			480.9
Cash flows from investing activities
Capital expenditures		(573.3	)		(511.0	)
Other investing activities		8.5			(0.2	)
Cash flows used in investing activities		(564.8	)		(511.2	)
Cash flows from financing activities
Dividends and dividend equivalents		(135.4	)		(158.8	)
Proceeds from the sale of common stock and equity contributions		26.2			6.4
Proceeds from long-term debt issuance		0.0			499.7
Repayment of long-term debt		(333.3	)		(274.5	)
Net decrease in short-term debt (maturities of 90 days or less)		(36.5	)		(11.0	)
Proceeds from other short-term debt (maturities over 90 days)		400.0			0.0
Other financing activities		(6.7	)		(1.5	)
Cash flows from (used in) financing activities		(85.7	)		60.3
Net increase in cash and cash equivalents		0.6			30.0
Cash and cash equivalents at beginning of the period		23.8			25.4
Cash and cash equivalents at end of the period	$	24.4		$	55.4
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(20.6	)	$	(8.1	)

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

11

TECO ENERGY, INC.

Consolidated Condensed Statements of Capital

Unaudited

													Accumulated
							Additional						Other
				Common			Paid in			Retained			Comprehensive			Total
(millions)	Shares			Stock			Capital			Earnings			Income (Loss)			Capital
Balance, Dec. 31, 2015		235.3		$	235.3		$	1,894.5		$	441.4		$	(12.2	)	$	2,559.0
Net income											148.5						148.5
Other comprehensive loss, after tax														(5.4	)		(5.4	)
Common stock issued		0.2			0.2			(1.8	)								(1.6	)
Impact of Merger		(235.5	)		(235.5	)		235.5									0.0
Dividends and dividend equivalents											(135.4	)					(135.4	)
Stock compensation expense								6.4									6.4
Restricted stock—dividends								(1.6	)								(1.6	)
Cumulative effect of change in accounting											2.6						2.6
Equity contribution								22.1									22.1
Other								(0.4	)								(0.4	)
Balance, Sept. 30, 2016		0.0		$	0.0		$	2,154.7		$	457.1		$	(17.6	)	$	2,594.2

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

12

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 transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14 for further information.

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 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

The new U.S. GAAP accounting policies that are applicable to and were adopted by the company are described as follows:

Interest – Imputation of Interest

In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The company adopted this standard in the first quarter of 2016, and Dec. 31, 2015 balances have been retrospectively restated. This change resulted in $27.7 million of debt issuance costs as of Dec. 31, 2015, previously presented as “Deferred charges and other assets”, being reclassified as a deduction from the carrying amount of the related “Long-term debt, less amount due within one year” line item on its Consolidated Condensed Balance Sheet. In accordance with ASU 2015-15 Interest: Imputation of Interest, the company continues to present debt issuance costs related to its letter of credit arrangements and related instruments in “Prepayments and other current assets” on its Consolidated Condensed Balance Sheets.

13

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.  The standard clarifies 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 company early adopted in the third quarter of 2016 as permitted.

Compensation – Stock Compensation

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation to simplify 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 liabilities, and presentation on the statement of cash flows.  The company early adopted as permitted in the first quarter of 2016. Each aspect has an accounting impact and was implemented as follows:

• Income tax consequences – 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. 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.

• 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 Sept. 30, 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. Therefore, the company reclassified $1.5 million from operating activities to financing activities for the nine months ended Sept. 30, 2015.

Future Accounting Pronouncements

The company considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB but have not yet been adopted by TECO Energy. Any ASUs not included below were assessed and determined to be either not applicable to the company or are not expected to have a material impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new principle-based revenue recognition framework. 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 to. 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 beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company will adopt this guidance effective Jan. 1, 2018. The company has developed an implementation plan and is continuing to evaluate the available adoption methods. While the company does not expect the impact to be significant, it is continuing to evaluate the impact of adoption of this standard on its consolidated financial statements and disclosures.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. 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.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Dec. 15, 2017.  

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Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods including interim reporting within those periods, beginning after Dec. 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides 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. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance will be effective for the company beginning in 2018, with early adoption permitted, and is required to be applied on a retrospective approach.  The company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities 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 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.

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

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.4	$	74.7
Cost-recovery clauses - deferred balances (2)		4.5		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		2.1		26.5
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.4		240.6
Deferred bond refinancing costs (5)		7.1		6.5
Debt basis adjustment (6)		14.9		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		14.8		12.1
Total regulatory assets		480.5		440.0
Less: Current portion		21.8		44.8
Long-term regulatory assets	$	458.7	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.2	$	7.9
Cost-recovery clauses (2)		111.5		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		670.6		679.9
Bill reduction credit (8)		8.0		0.3
Other		13.6		0.5
Total regulatory liabilities		867.0		800.6
Less: Current portion		148.2		84.8
Long-term regulatory liabilities	$	718.8	$	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 the 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 the 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.

(8) See Note 14 for information regarding NMGC’s stipulation agreement including a commitment to provide an annual bill reduction credit to customers. A minor portion of this balance is attributable to timing of bill reduction credits related to TECO Energy’s acquisition of NMGC in September 2014.

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4. Income Taxes

The effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 19.86% and 39.12%, respectively. The effective tax rate decreased to 34.19% for the nine months ended Sept. 30, 2016 from 39.10% for the same period in 2015.

The decrease in the three-month effective tax rate of 19.26% in 2016 versus the same period in 2015 is primarily due to tax benefits recorded in the third quarter of 2016 for federal R&D credits, lower non-deductible Merger transaction costs and other permanent book-to-tax differences.

The effective tax rate for year-to-date 2016 differed from the U.S. statutory rate of 35% primarily due to the effects of federal R&D credits and the tax benefit related to long-term incentive compensation offset by non-deductible Merger transaction costs (see Notes 2 and 14 for further description). The effective tax rate for year-to-date 2015 differed from the U.S. statutory rate primarily due to tax expense related to long-term incentive compensation shares that vested below target levels.

Effective July 1, 2016 and due to the Merger with Emera, TECO Energy and its subsidiaries are included in a consolidated U.S federal income tax return with EUSHI and its subsidiaries. TECO Energy’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TECO Energy’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.  

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 2013 and forward. Years 2015 and the short tax year ending June 30, 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.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.  As of Sept. 30, 2016 and Dec. 31, 2015, TECO Energy’s uncertain tax positions were $7.7 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for net operating losses and tax credit carryforwards. The increase was primarily due to an uncertain tax position related to federal R&D tax credits. TECO Energy believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s federal income tax return for the short tax year ending June 30, 2016.  As of Sept. 30, 2016, if recognized, $7.7 million of the unrecognized tax benefits would reduce TECO Energy’s effective tax rate.

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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 Sept. 30,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.9		$	6.7		$	0.5		$	0.6
Interest cost		7.2			6.5			2.0			2.0
Expected return on assets		(11.5	)		(9.1	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		4.8			3.2			0.1			0.0
Regulatory asset		0.0			0.0			0.3			0.3
Curtailment cost		0.0			0.0			0.0			0.0
Settlement cost		0.0			0.0			0.0			0.0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	2.0		$	2.0
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.9		$	17.6		$	1.4		$	1.7
Interest cost		23.6			22.6			6.4			6.1
Expected return on assets		(34.2	)		(32.4	)		(0.9	)		(0.8	)
Amortization of:
Prior service (benefit) cost		0.2			(0.2	)		(1.9	)		(1.8	)
Actuarial loss		11.7			11.4			0.1			0.0
Regulatory asset		0.0			0.0			0.8			0.8
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	$	17.1		$	19.0		$	5.9		$	6.0

For the Jan. 1, 2016 measurement, TECO Energy used 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.

As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%.

As a result of the remeasurement, TECO Energy’s net periodic benefit expense increased by $0.6 million for pension benefits and zero for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TECO Energy’s liability for pension benefits increased by $61.7 million and $17.6 million for other postretirement benefits. The associated regulatory asset increased $54.0 million for pension benefits and $14.1 million for other postretirement benefits. Accumulated other comprehensive income decreased $7.7 million for pension benefits and $3.5 million for other postretirement benefits.

TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan for the nine months ended Sept. 30, 2016 and 2015, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2016 and 2015.

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For the three and nine months ended Sept. 30, 2016, TECO Energy and its subsidiaries reclassified $0.8 million and $1.8 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $0.2 million and $2.4 million for the three and nine months ended Sept. 30, 2015, respectively. In addition, during the three and nine months ended Sept. 30, 2016, the regulated companies reclassified $3.8 million and $9.1 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2015, respectively.

The settlement cost recognized relates to the settlement of the SERP liability for the TECO Coal participants. 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 as a result of the Merger, which expected retirements occurred in the third quarter of 2016.

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 have occurred as a result of the Merger.

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		150.0		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		11.5		1.4		125.0		23.0		1.7
Total	$	1,300.0	$	610.5	$	1.9	$	900.0	$	247.0	$	2.2
(1)     Borrowings outstanding are reported as notes payable.
(2)     This 5-year facility matures Dec. 17, 2018.
(3)     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 Sept. 30, 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 Sept. 30, 2016 and Dec. 31, 2015 was 1.71% 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 Sept. 30, 2016, total long-term debt had a carrying amount of $3,490.3 million and an estimated fair market value of $3,911.2 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

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obtained from the Municipal Securities Rulemaking Board orby applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 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.

As of Sept. 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.

8. 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.

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, 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 against PGS remains pending, with a trial currently expected in February 2017. 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.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies

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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, a settlement was reached with all the named plaintiffs in the subrogation lawsuits.A motion to dismiss the appeal was granted by the court on Aug. 2, 2016.

The settlements were not material to the company.

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.  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 were consolidated per court order.  Since the consolidation, two of the complaints were amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

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

In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.

In September 2016, a hearing was held to gain preliminary approval of a negotiated stipulation of settlement. After that hearing, the judge entered an order granting preliminary approval of the class action settlement and scheduling a final approval hearing for December 2016.

There can be no assurance that the court will grant final approval of the settlement. However, while the outcome of such proceeding remains 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 had 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.

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On Sept. 23, 2016, TGH filed a request for resubmission to arbitration. On Oct. 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission, officially commencing the new arbitration and starting the time periods for constitution of the new tribunal.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

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

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

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

Merger Commitments

In connection with the Merger with Emera, TECO Energy made certain commitments approved by the NMPRC. See Note 14 for additional information.

Guarantees

A summary of the face amount or maximum theoretical obligation and the year of expiration under guarantees as of Sept. 30, 2016 is as follows:

(millions)												Maximum
										After (1)			Theoretical			Liabilities Recognized
Guarantees for the Benefit of:	2016		2017			2018-2020			2020			Obligation			at Sept. 30, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0		$	0.0		$	0.0		$	93.9		$	93.9		$	0.0
Letters of indemnity - coal mining permits (3)		0.0			84.5			0.0			0.0			84.5			0.0
	$	0.0		$	84.5		$	0.0		$	93.9		$	178.4		$	0.0
(1)    These 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 of 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 Sept. 30, 2016. See Note 10 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. 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.

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Financial Covenants

TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

9. 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.  

Segment Information (1)
(millions)	Tampa		Peoples		New Mexico				TECO										TECO
Three months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations			Energy
2016
Revenues - external	$	585.1	$	103.3	$	35.7			$	0.0		$	2.6			$	0.0		$	726.7
Sales to affiliates		0.8		0.4		0.0				0.0			0.1				(1.3	)		0.0
Total revenues		585.9		103.7		35.7				0.0			2.7				(1.3	)		726.7
Total interest charges		22.4		3.7		2.8				0.0			15.2				(0.2	)		43.9
Net income (loss) from continuing operations		94.1		6.5		(19.8	)	(5)		0.0			(11.4	)	(5)		0.0			69.4
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			0.0				0.0			0.0
Net income (loss)	$	94.1	$	6.5	$	(19.8	)		$	0.0		$	(11.4	)		$	0.0		$	69.4
2015
Revenues - external	$	559.4	$	88.1	$	43.7			$	0.0		$	2.6			$	0.0		$	693.8
Sales to affiliates		0.8		2.0		0.0				0.0			0.0				(2.8	)		0.0
Total revenues		560.2		90.1		43.7				0.0			2.6				(2.8	)		693.8
Total interest charges		24.1		3.7		3.2				0.0			15.4				(0.3	)		46.1
Net income (loss) from continuing operations		82.1		6.2		(2.8	)			0.0			(20.6	)			0.0			64.9
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(12.1	)		0.4				0.0			(11.7	)
Net income (loss)	$	82.1	$	6.2	$	(2.8	)		$	(12.1	)	$	(20.2	)		$	0.0		$	53.2

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(millions)	Tampa		Peoples		New Mexico				TECO											TECO
Nine months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations				Energy
2016
Revenues - external	$	1,506.6	$	330.0	$	194.0			$	0.0		$	7.9			$	0.0			$	2,038.5
Sales to affiliates		3.0		6.8		0.0				0.0			0.1				(9.9	)			0.0
Total revenues		1,509.6		336.8		194.0				0.0			8.0				(9.9	)			2,038.5
Total interest charges		68.8		11.1		9.1				0.0			45.3				(0.7	)			133.6
Net income (loss) from continuing operations		212.9		26.7		(4.8	)	(5)		0.0			(86.2	)	(5)		0.0				148.6
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			(0.1	)			0.0				(0.1	)
Net income (loss)	$	212.9	$	26.7	$	(4.8	)		$	0.0		$	(86.3	)		$	0.0			$	148.5
2015
Revenues - external	$	1,540.8	$	302.0	$	216.7			$	0.0		$	7.9			$	0.0			$	2,067.4
Sales to affiliates		2.4		4.5		0.0				0.0			0.1				(7.0	)			0.0
Total revenues		1,543.2		306.5		216.7				0.0			8.0				(7.0	)			2,067.4
Total interest charges		71.2		10.8		9.8				0.0			49.6				(1.0	)			140.4
Net income (loss) from continuing operations		198.0		28.4		11.0				0.0			(47.2	)			0.0				190.2
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(69.6	)		2.4				0.0				(67.2	)
Net income (loss)	$	198.0	$	28.4	$	11.0			$	(69.6	)	$	(44.8	)		$	0.0			$	123.0
At Sept. 30, 2016
Total assets	$	7,244.9	$	1,161.5	$	1,230.4			$	0.0		$	2,031.8			$	(2,444.9	)	(4)	$	9,223.7
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 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 consolidated tax reclassifications.
(5)    Includes transaction costs associated with the Merger with Emera. See Note 14.

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10. 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 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.

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 Sept. 30, 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 Sept. 30, 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 $2.2 million and $0.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.7 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in 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 Sept. 30, 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 Sept. 30, 2016, net pretax gains of $0.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

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

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earnings for the threeand ninemonths ended Sept. 30, 2016 and 2015 is presented in Note 12. 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 Sept. 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 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		14.2
2017		0.0		32.8
2018		0.0		5.3
Total		0.0		52.3

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 Sept. 30, 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.

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

identical or comparable assets or liabilities;

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

cost); and

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

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

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

The following tables set forth by level within the fair value hierarchy, the company’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. 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 Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	2.2	$	0.0	$	2.2
Liabilities
Natural gas derivatives	$	0.0	$	1.7	$	0.0	$	1.7
	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 10). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 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 Sept. 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.  

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12. Other Comprehensive Income

TECO Energy reported the following OCI related to changes in the fair value of cash flow hedges, recognized cost due to curtailment, change in benefit obligation due to remeasurement and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Sept. 30,									Nine months ended Sept. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
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			1.0			(0.4	)		0.6
Gain on cash flow hedges		0.3			(0.1	)		0.2			1.0			(0.4	)		0.6
Amortization of unrecognized benefit costs and other (2)		0.8			(0.3	)		0.5			1.3			(0.5	)		0.8
Change in benefit obligation due to remeasurement (3)		(11.2	)		4.3			(6.9	)		(11.2	)		4.3			(6.9	)
Recognized cost due to curtailment (4)		0.0			0.0			0.0			0.1			0.0			0.1
Total other comprehensive loss	$	(10.1	)	$	3.9		$	(6.2	)	$	(8.8	)	$	3.4		$	(5.4	)
2015
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	4.3		$	(1.5	)	$	2.8
Reclassification from AOCI to net income (1)		0.3			(0.1	)		0.2			1.0			(0.5	)		0.5
Gain on cash flow hedges		0.3			(0.1	)		0.2			5.3			(2.0	)		3.3
Amortization of unrecognized benefit costs (2)		0.4			(0.2	)		0.2			2.9			(1.1	)		1.8
Change in benefit obligation due to valuation (5)		(8.7	)		3.0			(5.7	)		(8.7	)		3.0			(5.7	)
Recognized cost due to settlement (6)		12.1			(4.4	)		7.7			12.1			(4.4	)		7.7
Total other comprehensive income	$	4.1		$	(1.7	)	$	2.4		$	11.6		$	(4.5	)	$	7.1
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement benefits. See Note 5 for additional information.
(3)  Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 for additional information.
(4)  Related to the estimated curtailment loss for the SERP.  See Note 5 for additional information.
(5)  Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.
(6)  Related to the settlement of the TECO Coal black lung obligation at the closing of the sale.  See Notes 15 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(37.7	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and transition obligations (2)		23.1			25.6
Net unrealized losses from cash flow hedges (3)		(3.0	)		(3.6	)
Total accumulated other comprehensive loss	$	(17.6	)	$	(12.2	)
(1)  Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

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13. Variable Interest Entities

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

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 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.

14. Mergers and Acquisitions

Merger with Emera Inc.

Description of Transaction

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, the Merger Sub Company merged 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, each issued and outstanding share of TECO Energy common stock was 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 $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion.

The 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.

Merger-Related Regulatory 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 then pending proceeding seeking the approval of the Merger by the NMPRC. On May 2, 2016, the Hearing Examiner held a hearing to consider the stipulation agreement. On June 8, 2016, the Hearing Examiner filed a Certificate of Stipulation, recommending approval by the NMPRC of the stipulation with respect to which all intervenors had either consented or filed a notice of non-opposition.  On June 22, 2016, the NMPRC approved the stipulation, and an order was entered on that same day.

As part of the stipulation agreement filed with the NMPRC, upon closing of the Merger, NMGC agreed, among other things, to:

• make commitments to charitable contributions and enterprises engaged in economic and business development in New Mexico of $0.8 million annually for three years,

• continue to provide an annual bill reduction credit of $4 million through June 30, 2018,

• evaluate and construct, at shareholder expense, an enlarged pipeline from its current system to the New Mexico/Mexican border at an estimated cost of approximately $5 million,

• establish, at shareholder expense, a matching fund of $10 million to extend its natural gas infrastructure to currently underserved or unserved areas in New Mexico, and

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

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The company recorded the pretax costs of $30.4 million (or approximately $17.7 million after tax)related to these commitments in the three months ended Sept. 30, 2016. The bill credit of $8.0 million was recognized as a reduction in “Regulated gas revenues” and the remaining items recorded in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income for the three and nine months ended Sept. 30, 2016.As of Sept. 30, 2016, approximately $30 million remains to be paid and is included in “Other” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016.

Transaction-Related Costs

In addition to the Merger-related regulatory matters above, during the three and nine months ended Sept. 30, 2016, TECO Energy also incurred approximately $15.5 million and $87.0 million, respectively, of pretax transaction-related costs ($9.6 million and $68.1 million after tax, respectively), compared with approximately $15.4 million of pretax transaction-related costs during the three and nine months ended Sept. 30, 2015. These costs are presented in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income.

For the three months ended Sept. 30, 2016, the $15.5 million of costs are primarily for accelerated vesting of outstanding stock-based compensation awards in accordance with the Merger Agreement and other employee-related costs. For the nine months ended Sept. 30, 2016, the costs also 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 recorded in the second quarter. During the third quarter of 2016, Emera contributed $22 million to TECO Energy primarily related to funding accelerated stock compensation payments. Transaction-related costs expensed and paid through Sept. 30, 2016 have been reflected in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016. As of Sept. 30, 2016, approximately $20 million remains to be paid. These remaining costs are expected to be paid primarily in the first quarter of 2017 and are included in “Accounts payable” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 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 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 date 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 this dividend 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.

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 (see description of guarantees in Note 8). The SPA contained customary representations, warranties and covenants (see Note 8 for description of a claim filed by Cambrian related to the SPA). The costs shown for 2016 in the table below reflects charges for personnel-related liabilities that remained with TECO Energy and legal costs associated with the claim related to the SPA.

Since the closing of the sale, TECO Energy has not 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 8). The charges shown in the table below are legal costs associated with that claim.  

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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						Nine months ended
	Sept. 30,						Sept. 30,
(millions)	2016			2015			2016			2015
Revenues—TECO Coal	$	0.0		$	51.6		$	0.0		$	200.4
Loss from operations—TECO Coal		(0.1	)		(7.4	)		(0.2	)		(16.4	)
Loss on sale—TECO Coal		0.0			(10.0	)		0.0			(10.0	)
Loss on impairment—TECO Coal		0.0			0.0			0.0			(78.6	)
Loss from operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations—TECO Coal		(0.1	)		(17.4	)		(0.2	)		(105.0	)
Loss from discontinued operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations		(0.2	)		(17.8	)		(0.4	)		(105.5	)
Benefit for income taxes		0.2			6.1			0.3			38.3
Loss from discontinued operations, net	$	0.0		$	(11.7	)	$	(0.1	)	$	(67.2	)

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Sept. 30,			Dec. 31,
(millions)	2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,473.9		$	7,270.3
Gas		1,466.3			1,398.6
Construction work in progress		875.2			771.1
Utility plant in service, at original costs		9,815.4			9,440.0
Accumulated depreciation		(2,808.3	)		(2,676.8	)
Utility plant in service, net		7,007.1			6,763.2
Other property		10.5			9.7
Total property, plant and equipment, net		7,017.6			6,772.9
Current assets
Cash and cash equivalents		15.4			9.1
Receivables, less allowance for uncollectibles of $2.5 and $1.5 at Sept. 30, 2016    and Dec. 31, 2015, respectively		254.9			230.2
Inventories, at average cost
Fuel		80.7			105.6
Materials and supplies		80.2			73.1
Regulatory assets		20.6			44.3
Taxes receivable from affiliate		0.0			61.3
Prepayments and other current assets		16.3			21.5
Total current assets		468.1			545.1
Deferred debits
Regulatory assets		438.2			373.8
Other		29.9			16.8
Total deferred debits		468.1			390.6
Total assets	$	7,953.8		$	7,708.6

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	Sept. 30,			Dec. 31,
(millions)	2016			2015
Capitalization
Common stock	$	2,395.4		$	2,305.4
Accumulated other comprehensive loss		(3.0	)		(3.6	)
Retained earnings		371.2			313.7
Total capital		2,763.6			2,615.5
Long-term debt		2,162.6			2,161.7
Total capitalization		4,926.2			4,777.2
Current liabilities
Long-term debt due within one year		0.0			83.3
Notes payable		49.0			61.0
Accounts payable		222.0			221.6
Customer deposits		155.2			176.3
Regulatory liabilities		140.4			83.2
Derivative liabilities		1.4			24.1
Interest accrued		40.1			16.9
Taxes accrued		74.5			13.2
Other		10.3			10.2
Total current liabilities		692.9			689.8
Deferred credits
Deferred income taxes		1,388.2			1,308.8
Investment tax credits		10.2			10.5
Regulatory liabilities		597.0			603.5
Deferred credits and other liabilities		339.3			318.8
Total deferred credits		2,334.7			2,241.6
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	7,953.8		$	7,708.6

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Sept. 30,
(millions)	2016			2015
Revenues
Electric	$	586.0		$	560.1
Gas		103.1			88.1
Total revenues		689.1			648.2
Expenses
Regulated operations and maintenance
Fuel		173.5			176.6
Purchased power		38.3			23.8
Cost of natural gas sold		40.4			28.5
Other		134.6			128.7
Depreciation and amortization		82.8			79.0
Taxes, other than income		52.6			47.8
Total expenses		522.2			484.4
Income from operations		166.9			163.8
Other income
Allowance for other funds used during construction		6.2			4.6
Other income, net		2.1			1.2
Total other income		8.3			5.8
Interest charges
Interest on long-term debt		27.7			29.0
Other interest		1.5			1.0
Allowance for borrowed funds used during construction		(3.1	)		(2.2	)
Total interest charges		26.1			27.8
Income before provision for income taxes		149.1			141.8
Provision for income taxes		48.5			53.5
Net income		100.6			88.3
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			0.2
Total other comprehensive income, net of tax		0.2			0.2
Comprehensive income	$	100.8		$	88.5

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Nine months ended Sept. 30,
(millions)	2016			2015
Revenues
Electric	$	1,509.0		$	1,542.9
Gas		329.9			302.0
Total revenues		1,838.9			1,844.9
Expenses
Regulated operations and maintenance
Fuel		426.1			492.5
Purchased power		80.5			60.5
Cost of natural gas sold		126.4			101.9
Other		388.2			384.8
Depreciation and amortization		245.1			233.8
Taxes, other than income		148.6			144.9
Total expenses		1,414.9			1,418.4
Income from operations		424.0			426.5
Other income
Allowance for other funds used during construction		17.8			12.1
Other income, net		4.3			3.6
Total other income		22.1			15.7
Interest charges
Interest on long-term debt		84.5			84.5
Interest expense		3.9			3.3
Allowance for borrowed funds used during construction		(8.6	)		(5.8	)
Total interest charges		79.8			82.0
Income before provision for income taxes		366.3			360.2
Provision for income taxes		126.7			133.8
Net income		239.6			226.4
Other comprehensive income, net of tax
Gain on cash flow hedges		0.6			3.3
Total other comprehensive income, net of tax		0.6			3.3
Comprehensive income	$	240.2		$	229.7

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sept. 30,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	239.6		$	226.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		245.1			233.8
Deferred income taxes and investment tax credits		69.8			52.6
Allowance for funds used during construction		(17.8	)		(12.1	)
Deferred recovery clauses		54.3			13.7
Receivables, less allowance for uncollectibles		(24.7	)		(31.4	)
Inventories		17.8			(44.4	)
Prepayments		6.4			(7.9	)
Taxes accrued		122.6			93.6
Interest accrued		23.2			24.5
Accounts payable		18.6			(39.8	)
Other		(52.3	)		(34.4	)
Cash flows from operating activities		702.6			474.6
Cash flows from investing activities
Capital expenditures		(517.6	)		(473.8	)
Net proceeds from sale of assets		8.7			0.0
Cash flows used in investing activities		(508.9	)		(473.8	)
Cash flows from financing activities
Common stock		90.0			88.0
Proceeds from long-term debt issuance		0.0			251.2
Repayment of long-term debt		(83.3	)		(83.3	)
Net decrease in short-term debt		(12.0	)		(58.0	)
Dividends		(182.1	)		(175.9	)
Cash flows from (used in) financing activities		(187.4	)		22.0
Net increase in cash and cash equivalents		6.3			22.8
Cash and cash equivalents at beginning of period		9.1			10.4
Cash and cash equivalents at end of period	$	15.4		$	33.2
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(19.6	)	$	(10.1	)

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.See Note 14 for further information.

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $63.7 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 rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, and $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to and were adopted by TEC are described as follows:

Interest – Imputation of Interest

In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. TEC adopted this standard in the first quarter of 2016, and Dec. 31, 2015 balances have been retrospectively restated. This change resulted in $18.1 million of debt issuance costs as of Dec. 31, 2015, previously presented as “Deferred charges and other assets”, being reclassified as a deduction from the carrying amount of the related “Long-term debt, less amount due within one year” line item on its Consolidated Condensed Balance Sheet. In accordance with ASU

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2015-15 Interest: Imputation of Interest, TEC continues to present debt issuance costs related to its letter of credit arrangements and related instruments in “Prepayments and other current assets” on its Consolidated Condensed Balance Sheets.

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.  The standard clarifies 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. TEC early adopted in the third quarter of 2016 as permitted.

Future Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or are not expected to have a material impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new principle-based revenue recognition framework. 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 to. 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 beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective Jan. 1, 2018. TEC has developed an implementation plan and is continuing to evaluate the available adoption methods. While TEC does not expect the impact to be significant, it is continuing to evaluate the impact of adoption of this standard on its consolidated financial statements and disclosures.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. 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.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Dec. 15, 2017.  

Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods including interim reporting within those periods, beginning after Dec. 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides 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. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

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Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance will be effective for TEC beginning in 2018, with early adoption permitted, and is required to be applied on a retrospective approach.  TEC is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities 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 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.1	$	74.6
Cost-recovery clauses - deferred balances (2)		4.4		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		1.5		26.2
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.5		238.3
Deferred bond refinancing costs (5)		5.9		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.1		10.7
Total regulatory assets		458.8		418.1
Less: Current portion		20.6		44.3
Long-term regulatory assets	$	438.2	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.3	$	5.7
Cost-recovery clauses (2)		107.8		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		554.8		570.0
Other		13.4		0.7
Total regulatory liabilities		737.4		686.7
Less: Current portion		140.4		83.2
Long-term regulatory liabilities	$	597.0	$	603.5

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

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

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

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(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. 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 the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

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

Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. Taxes accrued to affiliates was $14.2 million as of Sept. 30 2016.

TEC’s effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 32.53% and 37.73%, respectively. The effective tax rates for the nine months ended Sept. 30, 2016 and 2015 were 34.59% and 37.15%, respectively. The decrease in the three-month effective tax rate of 5.2% in 2016 versus the same period in 2015 is primarily due to a tax benefit recorded in the third quarter of 2016 for federal R&D credits. TEC’s effective tax rates for the nine months ended Sept. 30, 2016 and 2015 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity and federal R&D credits.

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 2013 and forward. Years 2015 and the short tax year ending June 30, 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able 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 beingutilized.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes require an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.  As of Sept. 30, 2016 and Dec. 31, 2015, TEC’s uncertain tax positions were $6.5 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. The increase was due to an uncertain tax position related to federal R&D tax credits. TEC believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016.  As of Sept. 30, 2016, if recognized, $6.5 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

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 Sept. 30, 2016 and 2015, respectively, was $3.5 million and $3.3 million for pension benefits, and $1.7 million and $1.4 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2016 and 2015, respectively, was $9.6 million and $10.1 million for pension benefits, and $4.7 million and $4.3 million for other postretirement benefits.  

For the Jan. 1, 2016 measurement, TECO Energy assumed a 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 used a discount rate of 4.667%.

As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each

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year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%.

As a result of the remeasurement, TEC’s net periodic benefit expense increased by $0.8 million for pension benefits and $0.3 million for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TEC’s liability and associated regulatory asset for pension benefits increased $53.3 million and $12.4 million for other postretirement benefits.

TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan in the nine months ended Sept. 30, 2016 and 2015, respectively. TEC’s portion of the contributions was $30.9 million and $43.9 million, respectively.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2016, TEC reclassified $2.8 million and $7.6 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.3 million and $7.0 million for the three and nine months ended Sept. 30, 2015, respectively.

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	49.0	$	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) This 3-year facility matures Mar. 23, 2018.

At Sept. 30, 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 Sept. 30, 2016 and Dec. 31, 2015 was 1.32% and 0.89%, respectively.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2016, TEC’s total long-term debt had a carrying amount of $2,162.6 million and an estimated fair market value of $2,505.6 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 or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 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

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Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

As of Sept. 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.

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.

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, 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 against PGS remains pending, with a trial currently expected in February 2017. 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.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

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

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

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

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TEC was in compliance with all applicable financial covenants.

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9. Segment Information

(millions)	Tampa									Tampa Electric
Three months ended Sept. 30,	Electric		PGS		Eliminations					Company
2016
Revenues - external	$	585.9	$	103.2	$	0.0				$	689.1
Intracompany sales		0.0		0.5		(0.5	)				0.0
Total revenues		585.9		103.7		(0.5	)				689.1
Total interest charges		22.4		3.7		0.0					26.1
Net income	$	94.1	$	6.5	$	0.0				$	100.6
2015
Revenues - external	$	560.1	$	88.1	$	0.0				$	648.2
Intracompany sales		0.1		2.0		(2.1	)				0.0
Total revenues		560.2		90.1		(2.1	)				648.2
Total interest charges		24.1		3.7		0.0					27.8
Net income	$	82.1	$	6.2	$	0.0				$	88.3
Nine months ended Sept. 30,
2016
Revenues - external	$	1,508.9	$	330.0	$	0.0				$	1,838.9
Intracompany sales		0.7		6.8		(7.5	)				0.0
Total revenues		1,509.6		336.8		(7.5	)				1,838.9
Total interest charges		68.8		11.1		(0.1	)				79.8
Net income	$	212.9	$	26.7	$	0.0				$	239.6
2015
Revenues - external	$	1,542.9	$	302.0	$	0.0				$	1,844.9
Intracompany sales		0.3		4.5		(4.8	)				0.0
Total revenues		1,543.2		306.5		(4.8	)				1,844.9
Total interest charges		71.2		10.8		0.0					82.0
Net income	$	198.0	$	28.4	$	0.0				$	226.4
Total assets at Sept. 30, 2016	$	7,244.9	$	1,161.5	$	(452.6	)	(2	)	$	7,953.8
Total assets at Dec. 31, 2015 (1)	$	7,003.8	$	1,136.1	$	(431.3	)	(2	)	$	7,708.6

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

(2) Amounts relate to consolidated tax reclassifications.

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

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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 Sept. 30, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Sept. 30, 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. Derivative assets totaled $1.5 million and $0.0 as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.5 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in 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 Sept. 30, 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 Sept. 30, 2016, net pretax losses of $0.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2016 and 2015 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassification to income was reflected in “Interest expense”.

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

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		7.7
2017		0.0		23.2
2018		0.0		5.3
Total		0.0		36.2

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 Sept. 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.

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

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

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

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

identical or comparable assets or liabilities;

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

cost); and

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

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

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

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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 Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
	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 Sept. 30, 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 Sept. 30,							Nine months ended Sept. 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		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	1.0	$	(0.4	)	$	0.6
2015
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		1.0		(0.5	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		5.3		(2.0	)		3.3
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	5.3	$	(2.0	)	$	3.3

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.0	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.0	)	$	(3.6	)

(1) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

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13. Variable Interest Entities

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

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 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

Merger with Emera Inc.

As disclosed in Note 1, TEC is a wholly owned subsidiary of TECO Energy. 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, the Merger Sub Company merged with and into TECO Energy with 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.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was 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 $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion).

The 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 and TEC’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.

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company's current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Managements Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: the ability to retain and motivate the workforce during the period of integration with Emera; regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices  affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under "Risk Factors" in TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 and the update in TECO Energy’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016.

Merger with Emera

On July 1, 2016, TECO Energy’s Merger with 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 14 to the TECO Energy Consolidated Financial Statements). The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries.

Earnings Summary - Unaudited

	Three Months Ended Sept. 30,					Nine months ended Sept. 30,
(millions) Except per-share amounts	2016		2015			2016			2015
Consolidated revenues	$	726.7	$	693.8		$	2,038.5		$	2,067.4
Net income from continuing operations		69.4		64.9			148.6			190.2
Loss on discontinued operations, net		0.0		(11.7	)		(0.1	)		(67.2	)
Net income		69.4		53.2			148.5			123.0

Operating Results

Three Months Ended Sept. 30, 2016

Third quarter 2016 net income was $69.4 million, compared with $53.2 million in the third quarter of 2015.  Net income from continuing operations was $69.4 million in the 2016 third quarter, compared with $64.9 million for the same period in 2015. Third quarter 2016 results include $27.3 million of costs related to the Merger with Emera ($45.9 million pretax), compared with $12.2 million in the third quarter of 2015 ($15.4 million pretax) (see Note 14 to the TECO Energy Consolidated Financial Statements). The third quarter loss in discontinued operations of $11.7 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).

Nine Months Ended Sept. 30, 2016

Year-to-date net income through the third quarter of 2016 was $148.5 million, compared with $123.0 million in the 2015 year-to-date period.  Net income from continuing operations was $148.6 million in the 2016 year-to-date period, compared with $190.2 million for the same period in 2015. Year-to-date 2016 net income reflects $85.8 million of Emera transaction-related costs ($117.4 million pretax), compared to $12.2 million of Emera transaction-related costs ($15.4 million pretax) and $1.2 million of NMGC integration costs in the year-to-date 2015 results. The $67.2 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.

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Tampa Electric Company – Electric Division

Tampa Electric’s net income for the third quarter of 2016 was $94.1 million, compared with $82.1 million for the same period in 2015.  Third-quarter net income in 2016 included $6.2 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, and $6.2 million of federal R&D tax credits, compared with $4.6 million of AFUDC-equity in the 2015 quarter. Results for the quarter reflected a 1.6% higher average number of customers. Energy sales were higher due to above normal summer weather compared to the third quarter of 2015 when weather was only slightly above normal. Third quarter results also reflected higher operations and maintenance expense and higher depreciation expense than in 2015, as further discussed below.

Total degree days in Tampa Electric's service area in the third quarter of 2016 were 8% above normal and 6% above the 2015 period. Pretax base revenues were $16.5 million higher than in 2015 due to higher energy sales from above normal weather, customer growth and a $1.5 million increase 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 in the third quarter of 2016 primarily due to above-normal summer temperatures compared to the 2015 quarter when summer temperatures were slightly above normal.  Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy.  Sales to lower-margin industrial-phosphate customers increased as self-generation by those customers decreased.

In the third quarter of 2016, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, increased $4.0 million driven by higher employee-related accruals in 2016 compared to 2015.  Depreciation and amortization expense increased $1.8 million in 2016 as a result of normal additions to facilities to reliably serve customers. 

Tampa Electric’s year-to-date net income was $212.9 million, compared with $198.0 million in the 2015 period, driven by higher base revenue from 1.6% higher average number of customers partially offset by higher operations and maintenance and depreciation expense.  Year-to-date net income in 2016 included $17.8 million of AFUDC-equity and $6.2 million of federal R&D tax credits, compared with $12.1 million of AFUDC-equity in the 2015 period. Energy sales were higher compared to 2015 due to the above-normal third quarter temperatures and customer growth.

Year-to-date total degree days in Tampa Electric's service area were 6% above normal but 2% below the 2015 period, when degree days where 7% above normal. Total net energy for load increased 1.8% 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 $20.2 million higher than in 2015, including approximately $4 million of higher pretax base revenue resulting 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 and commercial customers increased primarily from customer growth.  Sales to non-phosphate industrial customers and to lower-margin industrial-phosphate customers increased as a result of the same factors as the third quarter.  

In the 2016 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was approximately $5.0 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; and higher employee-related costs, including higher short-term incentive accruals in 2016 compared to 2015.  Depreciation and amortization expense increased $5.3 million in 2016, as a result of normal additions to facilities to reliably serve customers.

Tampa Electric’s regulated operating statistics for the three and nine months ended Sept. 30, 2016 and 2015 are as follows:

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(millions, except average customers and total degree days)	Operating Revenues									Kilowatt-hour sales
Three months ended Sept. 30,	2016			2015			% Change			2016		2015		% Change
By Customer Type
Residential	$	331.0		$	311.8			6.2			2,960.1		2,728.8		8.5
Commercial		167.3			167.1			0.1			1,814.0		1,753.6		3.4
Industrial – Phosphate		12.9			11.0			17.3			159.4		130.8		21.9
Industrial – Other		28.8			27.7			4.0			339.4		313.7		8.2
Other sales of electricity		47.6			46.2			3.0			502.9		473.8		6.1
Deferred and other revenues (1)		(17.5	)		(18.2	)		3.8
Total energy sales		570.1			545.6			4.5			5,775.8		5,400.7		6.9
Sales for resale		2.0			0.2			900.0			56.6		5.0		1,032.0
Other operating revenue		13.8			14.4			(4.2	)
Total revenues	$	585.9		$	560.2			4.6			5,832.4		5,405.7		7.9
Average customers (thousands)		731.8			720.1			1.6
Retail net energy for load (kilowatt hours)											6,045.2		5,700.1		6.1
Total degree days											1,768		1,666		6.1
Nine months ended Sept. 30,
By Customer Type
Residential	$	801.0		$	792.6			1.1			7,115.4		6,898.8		3.1
Commercial		447.7			454.9			(1.6	)		4,767.2		4,713.6		1.1
Industrial – Phosphate		38.7			38.3			1.0			480.9		471.8		1.9
Industrial – Other		81.6			80.3			1.6			957.3		912.6		4.9
Other sales of electricity		130.4			131.7			(1.0	)		1,351.0		1,329.9		1.6
Deferred and other revenues (1)		(35.0	)		(1.4	)		(2,400.0	)
Total energy sales		1,464.4			1,496.4			(2.1	)		14,671.8		14,326.7		2.4
Sales for resale		4.1			3.0			36.7			130.2		89.7		45.2
Other operating revenue		41.1			43.8			(6.2	)
Total revenues	$	1,509.6		$	1,543.2			(2.2	)		14,802.0		14,416.4		2.7
Average customers (thousands)		729.1			717.3			1.6
Retail net energy for load (kilowatt hours)											15,623.7		15,345.0		1.8
Total degree days											3,625		3,700		(2.0	)
(1)     Primarily reflects the timing of environmental and fuel clause recoveries.

Tampa Electric Company – Natural Gas Division

PGS reported net income of $6.5 million for the third quarter, compared with $6.2 million in the 2015 quarter. Results reflect a 2.7% higher average number of customers in the quarter and increased therm sales to commercial customers as a result of customer growth and a stronger economy. Off system sales increased due to power generation demand resulting from warmer weather and coal-to-gas switching. Third-quarter results in 2016 reflected operations and maintenance expense $0.6 million higher than in the 2015 period driven by higher employee-related costs in 2016 compared to 2015. Depreciation and amortization increased $0.6 million due to normal additions to facilities to serve customers. 

PGS reported net income of $26.7 million for the year-to-date period, compared with $28.4 million in the 2015 year-to-date period. Results reflect a 2.4% higher average number of customers and increased residential and commercial therm sales due to strong economic conditions in Florida. Off system sales increased due to the same reasons as in the third quarter. Operations and maintenance expense increased $2.8 million compared to the 2015 period, driven by higher general operating costs around pipeline safety compliance and customer growth. Depreciation and amortization increased $1.6 million due to normal additions to facilities to serve customers. 

PGS’s regulated operating statistics for the three and nine months ended Sept. 30, 2016 and 2015 are as follows:

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(millions, except average customers)	Operating Revenues							Therms
Three months ended Sept. 30,	2016		2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	25.8	$	26.8		(3.7	)		10.8		10.9		(0.9	)
Commercial		31.0		30.8		0.6			108.2		106.0		2.1
Industrial		3.5		3.3		6.1			79.9		68.8		16.1
Off system sales		27.7		13.5		105.2			79.5		43.0		84.9
Power generation		1.8		1.7		5.9			204.8		192.2		6.6
Other revenues		11.1		11.2		(0.9	)
Total	$	100.9	$	87.3		15.6			483.2		420.9		14.8
By Sales Type
System supply	$	61.0	$	48.5		25.8			96.1		60.1		59.9
Transportation		28.8		27.6		4.3			387.1		360.8		7.3
Other revenues		11.1		11.2		(0.9	)
Total	$	100.9	$	87.3		15.6			483.2		420.9		14.8
Average customers (thousands)		370.9		361.0		2.7
Nine months ended Sept. 30,
By Customer Type
Residential	$	106.8	$	104.1		2.6			58.3		57.9		0.7
Commercial		108.3		104.9		3.2			367.1		354.1		3.7
Industrial		10.2		9.8		4.1			241.3		215.1		12.2
Off system sales		59.0		35.7		65.3			205.5		112.7		82.3
Power generation		3.9		5.6		(30.4	)		584.5		567.6		3.0
Other revenues		40.0		38.4		4.2
Total	$	328.2	$	298.5		9.9			1,456.7		1,307.4		11.4
By Sales Type
System supply	$	194.0	$	169.6		14.4			282.7		192.0		47.2
Transportation		94.2		90.5		4.1			1,174.0		1,115.4		5.3
Other revenues		40.0		38.4		4.2
Total	$	328.2	$	298.5		9.9			1,456.7		1,307.4		11.4
Average customers (thousands)		369.4		360.6		2.4

New Mexico Gas Company

NMGC reported a third-quarter 2016 loss of $19.8 million, compared with a $2.8 million loss in the 2015 period. In the third quarter of 2016, NMGC recorded approximately $18 million of costs ($30.4 million pretax) related to the conditions contained in the Emera acquisition stipulation agreement approved by the NMPRC, of which the bill credit was recognized as a reduction in revenues and the remaining items recorded as expenses (see Note 14 to the TECO Energy Consolidated Financial Statements). Excluding the impact of the stipulation agreement, NMGC’s loss for the quarter was $1.3 million compared to the prior year quarter loss of $2.8 million.

Growth in the average number of customers in the 2016 third quarter and year-to-date periods were 0.6%. In the third quarter, heating degree days were above the 2015 quarter but 16% below normal. Excluding the costs related to the stipulation mentioned above, non-fuel operating and maintenance expense was slightly lower than in the 2015 quarter due to cost efficiency initiatives.

NMGC reported a year-to-date loss of $4.8 million compared with net income of $11.0 million in the 2015 period, due to the recording of costs in the third quarter related to the conditions contained in the Emera acquisition stipulation agreement. Excluding the impact of the stipulation agreement, year-to-date net income was $13.7 million compared to $11.0 million in 2015. Year-to-date results reflected customer growth and the benefit of heating degree days that were slightly higher than in 2015, but more than 4% below normal. Excluding the costs related to the stipulation mentioned above, operating and maintenance expense was slightly lower due to cost efficiency initiatives. 

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NMGC’s regulated operating statistics for the three and ninemonths ended Sept. 30, 2016 and 2015are as follows:

(millions, except average customers and total degree days)	Operating Revenues								Therms
Three months ended Sept. 30,	2016			2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	30.4		$	30.3		0.3			23.4		22.5		4.0
Commercial		8.0			8.3		(3.6	)		11.3		11.7		(3.4	)
Industrial		0.1			0.2		(50.0	)		0.2		0.4		(50.0	)
On system transportation		3.3			3.1		6.5			73.4		70.0		4.9
Off system transportation		0.2			0.2		-			12.4		12.1		2.5
Other revenues (1)		(6.3	)		1.6		(493.8	)
Total	$	35.7		$	43.7		(18.3	)		120.7		116.7		3.4
By Sales Type
System supply	$	38.5		$	38.8		(0.8	)		34.9		34.6		0.9
Transportation		3.5			3.3		6.1			85.8		82.1		4.5
Other revenues (1)		(6.3	)		1.6		(493.8	)
Total	$	35.7		$	43.7		(18.3	)		120.7		116.7		3.4
Average customers (thousands)		517.5			514.5		0.6
Total degree days										30		4		650.0
Nine months ended Sept. 30,
By Customer Type
Residential	$	145.2		$	156.0		(6.9	)		188.8		182.7		3.3
Commercial		36.5			41.8		(12.7	)		69.4		69.5		(0.1	)
Industrial		0.4			0.5		(20.0	)		0.8		1.0		(20.0	)
Off system sales		0.6			0.3		100.0			3.9		1.2		225.0
On system transportation		13.9			12.8		8.6			245.3		228.1		7.5
Off system transportation		0.7			0.7		-			35.8		34.7		3.2
Other revenues (1)		(3.3	)		4.6		(171.7	)
Total	$	194.0		$	216.7		(10.5	)		544.0		517.2		5.2
By Sales Type
System supply	$	182.7		$	198.6		(8.0	)		262.9		254.4		3.3
Transportation		14.6			13.5		8.1			281.1		262.8		7.0
Other revenues (1)		(3.3	)		4.6		(171.7	)
Total	$	194.0		$	216.7		(10.5	)		544.0		517.2		5.2
Average customers (thousands)		518.7			515.7		0.6
Total degree days										2,457		2,397		2.5
(1)     Includes a bill reduction credit of $8.0 million. See Note 14 to the TECO Energy Consolidated Financial Statements.

Other (net)

The segment data in Note 9 to the TECO Energy Consolidated Condensed Financial Statements presents Other and Eliminations as separate segments. The discussion below nets the two segments.

The third quarter 2016 net loss for Other – net was $11.4 million, compared with $20.2 million in the third quarter 2015, which included $0.4 million income from discontinued operations. The third quarter 2016 net loss from continuing operations for Other – net was $11.4 million, which included $9.6 million of costs associated with the Emera transaction primarily for accelerated vesting of outstanding stock-based compensation awards, a $3.5 million tax benefit related to stock-based compensation awards paid in the third quarter, and a $3.2 million tax benefit related to recharacterizing certain prior year lobbying expenses as deductible for tax purposes. The third quarter 2015 net loss from continuing operations for Other-net was $20.6 million, which included $12.2 million of transaction costs related to the Emera transaction.

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Year-to-date 2016 net loss for Other – net was $86.3 million, which included a $0.1 million loss from discontinued operations, compared with a net loss of $44.8million for Other - net in the 2015 period, which included $2.4 million of income from discontinued operations related to TECO Coal. Year-to-date 2016 net loss from continuing operations for Other – net was $86.2 million, which included $68.1 of costs related to the Emera transaction primarily for employee-related and consultant fees, a $5.8 million tax benefit due to an accounting rule change related to stock-based incentive compensation recorded in the first quarter of 2016, lower interest expense as a result of refinancing debt maturities, and tax benefits recorded in the third quarter. In comparison, the year-to-date 2015 net loss from continuing operations was $47.2 million, which included $12.2 million of costs related to the Emera transaction and$1.2 million of NMGC integration-related costs.

Discontinued Operations – TECO Coal

The third quarter 2016 loss from discontinued operations was zero, compared with a $11.7 million loss in the 2015 period, which reflected TECO Coal’s operating results prior to its sale in September 2015 and a $7.7 million charge related to black lung liabilities. The year-to-date 2016 loss from discontinued operations was $0.1 million, compared with a loss of $67.2 million in the 2015 period, which reflected TECO Coal’s operating loss, net of impairment charges of $50.8 million and the black-lung related charge (see Note 15 to the TECO Energy Consolidated Financial Statements).

Income Taxes

The provisions for income taxes from continuing operations for the nine month periods ended Sept. 30, 2016 and 2015 were $77.2 million and $122.1 million, respectively. The provision for income taxes for the nine months ended Sept. 30, 2016 was impacted by lower pre-tax income, tax benefits related to federal R&D tax credits and long-term incentive compensation, offset by the tax impact of the nondeductible Merger transaction costs (see Notes 2 and 14 to the TECO Energy Consolidated Financial Statements).

Liquidity and Capital Resources

The table below sets forth the Sept. 30, 2016 consolidated liquidity and cash balances, the cash balances at the operating companies and Parent, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

							TECO Finance
(millions)	Consolidated		TEC		NMGC		Parent/other
Credit facilities (1)	$	1,300.0	$	475.0	$	125.0	$	700.0
Drawn amounts/letters of credit (1)		612.4		49.5		12.9		550.0
Available credit facilities		687.6		425.5		112.1		150.0
Cash and short-term investments		24.4		15.4		1.7		7.3
Total liquidity	$	712.0	$	440.9	$	113.8	$	157.3

(1) Includes amounts under the TECO Energy/TECO Finance $400 million one-year term loan facility which was fully funded on Sept. 30, 2016.

We are evaluating refinancing alternatives for the March 2017 maturity of the one-year term loan facility at TECO Finance and expect capital market conditions will continue to allow for a variety of financing options.

Cash Impacts of the Merger with Emera

In 2016, TECO Energy had net cash outflows associated with the Merger of approximately $55 million. In 2017, TECO Energy expects to pay approximately $20 million, primarily representing transaction costs accrued at June 30, 2016.  In connection with the stipulation agreement approved by the NMPRC, pre-tax costs of approximately $30 million were recorded in the third quarter of 2016, with associated cash outflows over a 5-year period. In addition, a $27 million pro-rated dividend was paid to TECO Energy shareholders in July 2016. During the third quarter of 2016, Emera contributed $22 million to TECO Energy primarily related to funding accelerated stock compensation payments. 

Cash Impacts Related to Operating Activities

Cash flows from operating activities for the nine months ended Sept. 30, 2016 increased compared to the same period in 2015. The change is primarily due to a higher deferred recovery clause balance due to over-recovery in 2016 as fuel prices were lower than projected, higher accounts payable primarily due to Merger-related transaction costs in 2016 and higher fuel and purchased power accruals, and lower fuel inventory due to increased use of coal units.

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Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TECO Energy and its subsidiaries were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Sept. 30, 2016. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	Sept. 30, 2016
TEC
Credit facility (2)	Debt/capital	Cannot exceed 65%		44.4%
Accounts receivable credit facility (2)	Debt/capital	Cannot exceed 65%		44.4%
NMGC
Credit facility (2)	Debt/capital	Cannot exceed 65%		30.4%
3.54% and 4.87% senior unsecured notes	Debt/capital	Cannot exceed 65%		30.4%
NMGI
2.71% and 3.64% senior unsecured notes	Debt/capital	Cannot exceed 65%		47.6%
TECO Energy/TECO Finance
Credit facility - 2013 $300 million (2)	Debt/capital	Cannot exceed 65%		61.5%
Credit facility - 2016 $400 million (2)	Debt/capital	Cannot exceed 65%		61.5%

(1) As defined in each applicable instrument.

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

Credit Ratings of Senior Unsecured Debt at Sept. 30, 2016

	Standard & Poor’s (S&P)	Moody’s	Fitch
Tampa Electric Company	BBB+	A3	A-
New Mexico Gas Company	BBB+	-	-
TECO Energy/TECO Finance	BBB	Baa2	BBB

On July 6, 2016, following the Merger with Emera, Moody’s downgraded the senior unsecured credit ratings of TECO Energy/TECO Finance to Baa2 from Baa1 and the issuer rating and senior unsecured ratings of Tampa Electric Company to A3 from A2. This concluded the ratings review commenced by Moody’s on June 2, 2016. Moody’s described the ratings outlook for the companies as “Stable”.

On July 1, 2016, following the Merger with Emera, S&P affirmed the issuer credit ratings of TECO Energy and the senior unsecured debt ratings of its subsidiaries, TECO Finance, Tampa Electric Company and NMGC, and maintained the ratings outlook at negative.

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

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

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 10 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors in Item 1A of Part II of this quarterly report). These credit

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ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Commitments and Contingencies

See Note 8 to the TECO Energy Consolidated Financial Statements for information regarding the company’s commitments and contingencies as of Sept. 30, 2016.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, the changes in value of natural gas derivatives of Tampa Electric, PGS and NMGC are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

The valuation methods used to determine fair value are described in Notes 7 and 11 to the TECO Energy Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 2016, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to settlements of natural gas swaps and the increase in the average market price component of the company’s outstanding natural gas swaps of approximately 7% from Dec. 31, 2015 to Sept. 30, 2016. For natural gas, the company increased the volume hedged as of Sept. 30, 2016 as compared to Dec. 31, 2015 by approximately 18%.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine-month period ended Sept. 30, 2016:

Change in Fair Value of Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2015	$	(26.0	)
Additions and net changes in unrealized fair value of derivatives		2.2
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		24.3
Net fair value of derivatives as of Sept. 30, 2016	$	0.5

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

Total derivative net assets (liabilities) as of Dec. 31, 2015	$	(26.0	)
Change in fair value of derivative net assets (liabilities):
Recorded as regulatory assets and liabilities or other comprehensive income		1.6
Recorded in earnings		0.0
Realized net settlement of derivatives		24.3
Option premium payments		0.6
Net fair value of derivatives as of Sept. 30, 2016	$	0.5

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sept. 30, 2016:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)	Current		Non-current		Total Fair Value
Source of fair value
Actively quoted prices	$	0.0	$	0.0	$	0.0
Other external price sources (1)		0.4		0.1		0.5
Model prices (2)		0.0		0.0		0.0
Total	$	0.4	$	0.1	$	0.5

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

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

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

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Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

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

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

Tampa Electric Company

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

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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

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

Item 1A.RISK FACTORS

For a discussion of TECO Energy’s risk factors, see TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 and the update in TECO Energy’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016.

Item 5.OTHER INFORMATION

As a result of the consummation of the Merger contemplated in the Merger Agreement on July 1, 2016 and as more fully described in Note 14 of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, TECO Energy became a wholly-owned indirect subsidiary of Emera. As the sole shareholder, EUSHI has the ability to appoint the members of TECO Energy’s board of directors.

Item 6. EXHIBITS

Exhibits - See index on page 60.

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SIGNATURES

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

	TECO ENERGY, INC.
	(Registrant)
Date: Nov. 7, 2016	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: Nov. 7, 2016	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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INDEX TO EXHIBITS

Exhibit
No.	Description
3.1	Amended and Restated Articles of Incorporation of TECO Energy, Inc., as filed on July 1, 2016 (Exhibit 3.1, Form 8-K dated July 1, 2016 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended and restated effective Aug. 17, 2016.
3.3	Restated Articles of Incorporation of Tampa Electric Company, as amended on Nov. 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.1	Amendment No. 1 to Loan and Servicing Agreement dated as of Aug. 10, 2016, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent.
31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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

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

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EX-3.2

Exhibit 3.2

Adopted:                   July 1, 2016

As Amended:     August 17, 2016

AMENDED AND RESTATED BYLAWS

OF

tECO ENERGY, INC.

A Florida For Profit Corporation

Table of Contents

		Page
ARTICLE 1	MEETINGS OF SHAREHOLDERS	1
1.1	Annual Meeting	1
1.2	Special Meetings	1
1.3	Notice	1
1.4	Notice of Adjourned Meetings	1
1.5	Waiver of Notice of Shareholders’ Meetings	1
1.6	Fixing Record Date	2
1.7	Voting Record	2
1.8	Shareholder Quorum and Voting	3
1.9	Votes Per Share	3
1.10	Manner of Action	3
1.11	Voting for Directors	3
1.12	Voting of Shares	3
1.13	Proxies	4
1.14	Voting Trusts	5
1.15	Shareholders’ Agreements	5
1.16	Action by Shareholders Without a Meeting	5
1.17	Inspectors of Election	6
ARTICLE 2	DIRECTORS	6
2.1	Functions	6
2.2	Number	6
2.3	Qualifications	6
2.4	Term	6
2.5	Removal of Directors	6
2.6	Resignation	6
2.7	Vacancies	7
2.8	Chair of the Board	7
2.9	Regular Meetings	7
2.10	Special Meetings	7

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Table of Contents

(continued)

		Page
2.11	Waiver of Notice of Meeting	8
2.12	Quorum and Voting	8
2.13	Presumption of Assent	8
2.14	Meetings of the Board of Directors by Means of Telephone Conference or Similar Communications	8
2.15	Action Without a Meeting	8
2.16	Compensation	9
2.17	Director Conflicts of Interests	9
ARTICLE 3	COMMITTEES OF THE BOARD OF DIRECTORS	9
ARTICLE 4	OFFICERS	10
4.1	Officers	10
4.2	Appointment and Term of Office	10
4.3	Removal of Officers	10
4.4	Resignation	10
4.5	Duties	10
4.6	Other Officers, Employees, and Agents	11
ARTICLE 5	STOCK CERTIFICATES	11
5.1	Certificates for Shares	11
5.2	Transfer of Shares; Ownership of Shares	11
5.3	Lost, Stolen or Destroyed Certificates	11
ARTICLE 6	ACTIONS WITH RESPECT TO SECURITIES OF OTHER CORPORATIONS	12
ARTICLE 7	BOOKS AND RECORDS	12
7.1	Books and Records	12
7.2	Financial Information	13
ARTICLE 8	CORPORATE SEAL	13
ARTICLE 9	AMENDMENTS	13

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AMENDED AND RESTATED BYLAWS

OF

TECO ENERGY, INC.

The Bylaws of TECO Energy, Inc. are hereby amended and restated in their entirety to read as follows:

ARTICLE 1

MEETINGS OF SHAREHOLDERS

1.1 Annual Meeting. The annual meeting of the shareholders of this corporation shall be held at the time and place designated by the Board of Directors of this corporation. Business transacted at the annual meeting shall include the election of directors of this corporation.

1.2 Special Meetings. Special meetings of the shareholders shall be held when directed by the President or the Board of Directors, or when requested in writing by the holders of not less than ten percent (10%) of all the shares entitled to vote at the meeting. The call for the meeting shall be issued by the Secretary, unless the President, Board of Directors or shareholders requesting the meeting shall designate another person to do so. Meetings of shareholders may be held within or outside of the State of Florida. If no place is designated in the notice for a meeting of shareholders, the place of meeting shall be the principal office of this corporation.

1.3 Notice. Except as provided in the Florida Business Corporation Act (the “Act”), written notice stating the place, day and hour of the meeting and, in the case of a special meeting or as otherwise provided by law, the purpose or purposes for which the meeting is called, shall be delivered to each shareholder of record entitled to vote at such meeting not less than ten (10) nor more than sixty (60) days before the date of the meeting, either personally or by first class mail, by or at the direction of the President, the Secretary, or the officer or other persons calling the meeting. If the notice is mailed at least thirty (30) days before the date of the meeting, it may be done by a class of United States mail other than first class. If mailed, such notice shall be deemed to be delivered when deposited in the United States mail addressed to the shareholder at the shareholder’s address as it appears in the current records of shareholders of this corporation, with postage thereon prepaid.

1.4 Notice of Adjourned Meetings. When a meeting is adjourned to another time or place, it shall not be necessary to give any notice of the adjourned meeting if the time and place to which the meeting is adjourned are announced at the meeting at which the adjournment is taken, and at the adjourned meeting any business may be transacted that might have been transacted on the original date of the meeting. If, however, after the adjournment the Board of Directors fixes a new record date for the adjourned meeting, a notice of the adjourned meeting shall be given as provided in Section 1.4 to each shareholder of record on the new record date entitled to vote at such meeting.

1.5 Waiver of Notice of Shareholders’ Meetings. Whenever any notice is required to be given to any shareholder, a waiver thereof in writing signed by the shareholder or shareholders entitled to such notice, whether before, during or after the time of the meeting stated therein and

1

delivered to this corporation for inclusion in the minutes or filing with the corporate records, shall be equivalent to the giving of such notice. Attendance by a shareholder at a meeting shall constitute a waiver of:  (a) lack of notice or defective notice of such meeting, unless at the beginning of the meeting, the shareholder objects to holding the meeting; or (b) asserting defective notice of a particular matter at a meeting that is not within the purpose or purposes described in the meeting notice, unless the person objects to considering that particular matter when it is presented. Unless otherwise required by the Articles of Incorporation, neither the business to be transacted at, nor the purpose of, any regular or special meeting of the shareholders need be specified in any written waiver of notice.

1.6 Fixing Record Date. For the purpose of determining shareholders entitled to notice of, or to vote at, any meeting of shareholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or to demand a special meeting, or to receive payment of any distribution, or in order to make a determination of shareholders for any other purpose,  the Board of Directors may fix in advance a date as the record date for any determination of shareholders, such date in any case to be not more than seventy (70) days prior to the date on which the particular action requiring such determination of shareholders is to be taken. A determination of shareholders entitled to notice of, or to vote at, any meeting of shareholders shall apply to any adjournment thereof, unless the Board of Directors fixes a new record date for the adjourned meeting, which it must do if the meeting is adjourned to a date more than one hundred twenty (120) days after the date fixed for the original meeting.

If no prior action is required by the Board of Directors pursuant to the Act, the record date for determining shareholders entitled to take action without a meeting is the date the first signed written consent is delivered to this corporation under Section 1.16.

1.7 Voting Record. After fixing a record date for a meeting of shareholders, this corporation shall prepare an alphabetical list of the names of all shareholders who are entitled to notice of such meeting, arranged by voting group, with the address of, and the number and class and series, if any, of the shares held by, each shareholder. The shareholders’ list must be available for inspection by any shareholder for a period of ten (10) days prior to the meeting or such shorter time as exists between the record date and the meeting and continuing through the meeting at this corporation’s principal office, at a place identified in the meeting notice in the city where the meeting will be held, or at the office of this corporation’s transfer agent or registrar. Any shareholder of this corporation or his agent or attorney is entitled on written demand to inspect the shareholders’ list (subject to the requirements of the Act), during regular business hours and at his or her expense, during the period it is available for inspection. This corporation shall make the shareholders’ list available at the meeting of shareholders, and any shareholder or his or her agent or attorney is entitled to inspect the list at any time during the meeting or any adjournment.

August 17, 2016

If the requirements of this Section have not been substantially complied with, the meeting shall be adjourned until such time as this corporation complies with such requirements on demand of any shareholder in person or by proxy who failed to get such access. If no such demand is made, failure to comply with the requirements of this Section 1.7 shall not affect the validity of any action taken at such meeting.

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1.8 Shareholder Quorum and Voting. Shares entitled to vote as a separate voting group may take action on a matter at a meeting only if a quorum of those shares exists with respect to that matter. Except as otherwise provided in the Articles of Incorporation or by the Act, a majority of the shares entitled to vote on the matter by each voting group, represented in person or by proxy, shall constitute a quorum at any meeting of shareholders, but in no event shall a quorum consist of less than one third of the shares of each voting group entitled to vote. If less than a majority of outstanding shares entitled to vote are represented at a meeting, a majority of the shares so represented may adjourn the meeting from time to time without further notice. After a quorum has been established at any shareholders’ meeting, the subsequent withdrawal of shareholders, so as to reduce the number of shares entitled to vote at the meeting below the number required for a quorum, shall not affect the validity of any action taken at the meeting or any adjournment thereof.

Once a share is represented for any purpose at a meeting, it is deemed present for quorum purposes for the remainder of the meeting and for any adjournment of that meeting, unless a new record date is or must be set for that adjourned meeting. When a specified item of business is required to be voted on by a class or series of stock, a majority of the shares of such class or series shall constitute a quorum for the transaction of such item of business by that class or series.

1.9 Votes Per Share. Except as otherwise provided in the Articles of Incorporation or by the Act, each outstanding share, regardless of class, shall be entitled to one vote on each matter submitted to a vote at a meeting of shareholders.

1.10 Manner of Action. If a quorum is present, action on a matter (other than the election of directors) by a voting group is approved if the votes cast within the voting group favoring the action exceed the votes cast opposing the action, unless a greater or lesser number of affirmative votes is required by the Articles of Incorporation or by law.

1.11 Voting for Directors. At each election for directors, every shareholder entitled to vote at such election shall have the right to vote, in person or by proxy, the number of shares owned by him or her for as many persons as there are directors to be elected at that time and for whose election he or she has a right to vote. Unless otherwise provided in the Articles of Incorporation, cumulative voting is not authorized and the directors shall be elected by a plurality of the votes cast by the shares entitled to vote in the election at a meeting at which a quorum is present.

1.12 Voting of Shares. A shareholder may vote at any meeting of shareholders of this corporation, either in person or by proxy.

Shares standing in the name of another corporation, domestic or foreign, may be voted by the officer, agent or proxy designated by the bylaws of the corporate shareholder or, in the absence of any applicable bylaw, by such person as the board of directors of the corporate shareholder may designate. Proof of such designation may be made by presentation of a certified copy of the bylaws or other instrument of the corporate shareholder. In the absence of any such designation or, in the case of conflicting designation by the corporate shareholder, the Chair of

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the Board, the President, any Vice President, the Secretary and the Treasurer of the corporate shareholder shall be presumed to possess, in that order, authority to vote such shares.

Shares held by an administrator, executor, guardian, personal representative or conservator may be voted by him or her, either in person or by proxy, without a transfer of such shares into his or her name. Shares standing in the name of a trustee may be voted by him or her, either in person or by proxy, but no trustee shall be entitled to vote shares held by him or her without a transfer of such shares into his or her name or the name of his or her nominee.

Shares held by or under the control of a receiver, a trustee in a bankruptcy proceeding or an assignee for the benefit of creditors may be voted by such person without the transfer thereof into his or her name.

If shares stand of record in the names of two or more persons, whether fiduciaries, members of a partnership, joint tenants, tenants in common, tenants by the entirety or otherwise, or if two or more persons have the same fiduciary relationship with respect to the same shares, unless the Secretary of this corporation is given notice to the contrary and is furnished with a copy of the instrument or order appointing them or creating the relationship wherein it is so provided, then acts with respect to voting shall have the following effect: (a) if only one votes, in person or by proxy, that act binds all; (b) if more than one votes, in person or by proxy, the act of the majority so voting binds all; (c) if more than one votes, in person or by proxy, but the vote is evenly split on any particular matter, each faction is entitled to vote the share or shares in question proportionally; or (d) if the instrument or order so filed shows that any such tenancy is held in unequal interest, a majority or a vote evenly split for purposes hereof shall be a majority or a vote evenly split in interest. The principles of this paragraph shall apply, insofar as possible, to execution of proxies, waivers, consents, or objections and for the purpose of ascertaining the presence of a quorum.

1.13 Proxies. Any shareholder of this corporation, other person entitled to vote on behalf of a shareholder pursuant to the Act, or attorney‑in‑fact for such persons, may vote the shareholder’s shares in person or by proxy. Any shareholder of this corporation may appoint a proxy to vote or otherwise act for him or her by signing an appointment form, either personally or by an attorney‑in‑fact. An executed telegram or cablegram appearing to have been transmitted by such person, or a photographic, photostatic, or equivalent reproduction of an appointment form, shall be deemed a sufficient appointment form.

An appointment of a proxy is effective when received by the Secretary of this corporation or such other officer or agent which is authorized to tabulate votes, and shall be valid for up to eleven (11) months, unless a longer period is expressly provided in the appointment form.

The death or incapacity of the shareholder appointing a proxy does not affect the right of this corporation to accept the proxy’s authority unless notice of the death or incapacity is received by the Secretary or other officer or agent authorized to tabulate votes before the proxy exercises his or her authority under the appointment.

An appointment of a proxy is revocable by the shareholder unless the appointment form conspicuously states that it is irrevocable and the appointment is coupled with an interest.

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1.14 Voting Trusts. One or more shareholders may create a voting trust, conferring on a trustee the right to vote or otherwise act for them, by signing an agreement setting out the provisions of the trust and transferring their shares to the trustee. When a voting trust agreement is signed, the trustee shall prepare a list of the names and addresses of all owners of beneficial interest in the trust, together with the number and class of shares each transferred to the trust, and deliver copies of the list and agreement to this corporation’s principal office.

1.15 Shareholders’ Agreements. Two or more shareholders may provide for the manner in which they will vote their shares, and providing for such other matters as are permitted by the Act, by signing an agreement for that purpose. When a shareholders’ agreement is signed, the shareholders who are parties thereto shall deliver copies of the agreement to this corporation’s principal office. After filing a copy of the agreement in this corporation’s principal office, such copies shall be open to inspection by any shareholder of this corporation, subject to the requirements of the Act, or any party to the agreement during business hours.

1.16 Action by Shareholders Without a Meeting. Unless otherwise provided in the Articles of Incorporation, action required or permitted to be taken at any meeting of the shareholders may be taken without a meeting, without prior notice and without a vote if the action is taken by the holders of outstanding shares of each  voting group entitled to vote thereon having not less than the minimum number of votes with respect to each voting group that would be necessary to authorize or take such action at a meeting at which all voting groups and shares entitled to vote thereon were present and voted. In order to be effective, the action must be evidenced by one or more written consents describing the action taken, dated and signed by approving shareholders having the requisite number of votes of each voting group entitled to vote thereon, and delivered to this corporation by delivery to its principal office in Florida, its principal place of business, the Secretary of this corporation, or any other officer or agent of this corporation having custody of the book in which proceedings of meetings of shareholders are recorded. No written consent shall be effective to take such corporate action unless, within sixty (60) days of the date of the earliest dated consent delivered in the manner required by this Section, written consents signed by the number of holders required to take such action are delivered to this corporation as set forth in this Section.

Any written consent may be revoked prior to the date that this corporation receives the required number of consents to authorize the proposed action. No revocation is effective unless in writing and until received by this corporation at its principal office in Florida or its principal place of business, or received by the Secretary or other officer or agent of this corporation having custody of the book in which proceedings of meetings of shareholders are recorded.

Within ten (10) days after obtaining such authorization by written consent, notice shall be given to those shareholders who have not consented in writing or who are not entitled to vote on the action. The notice shall fairly summarize the material features of the authorized action and, if the action is one for which dissenters’ rights are provided under the Articles of Incorporation or by law, the notice shall contain a clear statement of the right of shareholders dissenting therefrom to be paid the fair value of their shares upon compliance with applicable law.

A consent signed as required by this Section 1.16 has the effect of a meeting vote and may be described as such in any document.

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Whenever action is taken as set forth in this Section 1.16, the written consent of the shareholders consenting thereto or the written reports of Inspectors of Election appointed to tabulate such consents shall be filed with the minutes of proceedings of shareholders.

1.17 Inspectors of Election. Prior to each meeting of shareholders, the Board of Directors or the President may appoint one or more Inspectors of Election. Upon his or her appointment, each such Inspector of Election shall take and sign an oath to faithfully execute the duties of Inspector of Election at such meeting with strict impartiality and to the best of his or her ability. Such Inspectors of Election shall determine the number of shares outstanding, the number of shares present at the meeting and whether a quorum is present at such meeting. The Inspectors of Election shall receive votes and ballots and shall determine all challenges and questions as to the right to vote and shall thereafter count and tabulate all votes and ballots and determine the result. Such Inspectors of Election shall do such further acts as are proper to conduct the elections of directors and the vote on other matters with fairness to all shareholders. The Inspectors of Election shall make a certificate of the results of the elections of directors and the vote on other matters. No Inspector of Election shall be a candidate for election as a director of this corporation.

ARTICLE 2

DIRECTORS

2.1 Functions. Except as provided in the Articles of Incorporation or by law, all corporate powers shall be exercised by or under the authority of, and the business and affairs of this corporation shall be managed under the direction of, the Board of Directors.

2.2 Number. The current Board of Directors of this corporation consists of three (3) persons. The number of directors may at any time and from time to time be increased or decreased by action of either the shareholders or the Board of Directors, but no decrease in the number of directors shall have the effect of shortening the term of any incumbent director.

2.3 Qualifications. A director must be a natural person who is 18 years of age or older but need not be a citizen of the United States, a resident of the State of Florida or a shareholder of this corporation.

2.4 Term. Each director shall hold office until a successor has been elected and qualified or until an earlier resignation, removal from office or death.

2.5 Removal of Directors. Any director, or the entire Board of Directors, may be removed, with or without cause, by action of the shareholders, unless the Articles of Incorporation provide that the directors may be removed only for cause. If a director was elected by a voting group of shareholders, only the shareholders of that voting group may participate in the vote to remove that director. The notice of the meeting at which a vote is taken to remove a director must state that the purpose or one of the purposes of the meeting is the removal of the director or directors.

2.6 Resignation. Any director may resign at any time by delivering written notice to this corporation, the Board of Directors or the Chair of the Board. Such resignation is effective when

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the notice is delivered unless the notice specifies a later effective date, in which event the Board of Directors may fill the pending vacancy before the effective date if the Board of Directors provides that the successor does not take office until the effective date.

2.7 Vacancies. Any vacancy occurring in the Board of Directors, including any vacancy created by reason of an increase in the number of directors, may be filled by the affirmative vote of a majority of the remaining directors though less than a quorum of the Board of Directors, or by the shareholders. A director elected to fill a vacancy shall hold office only until the next shareholders’ meeting at which directors are elected.

August 17, 2016

2.8 Chair of the Board. If the Board of Directors appoints a chair of the board, he or she shall, when present, preside at all meetings of the shareholders and the Board of Directors. He or she shall perform such duties and possess such powers as are customarily vested in the office of the chair of the board or as may be vested in him or her by the Board of Directors.

August 17, 2016

2.9 Regular Meetings. An annual regular meeting of the Board of Directors shall be held without notice immediately after, and at the same place as, the annual meeting of shareholders for the purpose of the election of officers and the transaction of such other business as may come before the meeting, or at such other time and place as may be determined by the Board of Directors. The Board of Directors may, at any time and from time to time, provide by resolution, the time and place, either within or outside of the State of Florida, for the holding of the annual regular meeting or additional regular meetings of the Board of Directors without other notice than such resolution.

2.10 Special Meetings. Special meetings of the Board of Directors may be called by the Chair of the Board, the President or any one (1) director.

The person or persons authorized to call special meetings of the Board of Directors may designate any place, either within or outside of the State of Florida, as the place for holding any special meeting of the Board of Directors called by them. If no designation is made, the place of meeting shall be the principal office of this corporation in the State of Florida.

Notice of any special meeting of the Board of Directors may be given by any reasonable means, whether oral or written, and at any reasonable time prior to such meeting. The reasonableness of any notice given in connection with any special meeting of the Board of Directors shall be determined in light of all of the pertinent circumstances. It shall be presumed that notice of any special meeting given at least two (2) days prior to such special meeting, either orally (by telephone or in person), or by written notice delivered personally or mailed to each director at his or her business or residence address, is reasonable. If mailed, such notice of any special meeting shall be deemed to be delivered on the second day after it is deposited in the United States mail, so addressed, with postage thereon prepaid. If notice is given by telegram, such notice shall be deemed to be delivered when the telegram is delivered to the telegraph company. Neither the business to be transacted at, nor the purpose or purposes of, any special meetings of the Board of Directors need be specified in the notice or in any written waiver of notice of such meeting.

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2.11 Waiver of Notice of Meeting. Notice of a meeting of the Board of Directors need not be given to any director who signs a written waiver of notice either before, during or after the meeting. Attendance of a director at a meeting shall constitute a waiver of notice of such meeting and waiver of any and all objections to the place of the meeting, the time of the meeting and the manner in which it has been called or convened, except when a director states, at the beginning of the meeting or promptly upon arrival at the meeting, any objection to the transaction of business because the meeting is not lawfully called or convened.

2.12 Quorum and Voting. A majority of the number of directors fixed in the manner provided by these bylaws shall constitute a quorum for the transaction of business; provided however, that whenever, for any reason, a vacancy occurs in the Board of Directors, a quorum shall consist of a majority of the remaining directors until the vacancy has been filled. The act of the majority of the directors present at a meeting at which a quorum is present when the vote is taken shall be the act of the Board of Directors.

A majority of the directors present, whether or not a quorum exists, may adjourn any meeting of the Board of Directors to another time and place. Notice of any such adjourned meeting shall be given to the directors who were not present at the time of the adjournment and, unless the time and place of the adjourned meeting are announced at the time of the adjournment, to the other directors.

2.13 Presumption of Assent. A director of this corporation who is present at a meeting of its Board of Directors, or a committee of the Board of Directors, at which action on any corporate matter is taken shall be presumed to have assented to the action taken, unless he or she (i) objects at the beginning of the meeting (or promptly upon his or her arrival) to holding the meeting or transacting specified business at the meeting, or (ii) votes against such action or abstains from the action taken.

2.14 Meetings of the Board of Directors by Means of Telephone Conference or Similar Communications. Members of the Board of Directors may participate in a meeting of such Board by means of a telephone conference or similar communications equipment if all persons participating in the meeting can hear each other at the same time. Participation by such means shall constitute presence in person at a meeting.

2.15 Action Without a Meeting. Any action required or permitted to be taken at a meeting of the Board of Directors or a committee thereof may be taken without a meeting if a consent in writing, setting forth the action so taken, is signed by all of the directors of this corporation, or all the members of the committee, as the case may be. Action taken under this Section is effective when the last director or member of the committee signs the consent, unless the consent specifies a different effective date. Such consent shall have the effect as a meeting vote and may be described as such in any document.

2.16 Compensation. Each director may be paid his or her expenses, if any, of attendance at each meeting of the Board of Directors and a committee thereof, and may be paid a stated salary as a director or a fixed sum for attendance at each meeting of the Board of Directors (or a committee thereof) or both, as may from time to time be determined by action of the Board of

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Directors. No such payment shall preclude any director from serving this corporation in any other capacity and receiving compensation therefor.

2.17 Director Conflicts of Interests. No contract or other transaction between this corporation and one or more of its directors or any other corporation, firm, association or entity in which one or more of the directors of this corporation are directors or officers or are financially interested shall be either void or voidable because of such relationship or interest, or because such director or directors of this corporation are present at the meeting of the Board of Directors or a committee thereof which authorizes, approves or ratifies such contract or transaction, or because his or her or their vote(s) are counted for such purpose, if:

2.17.1 The fact of such relationship or interest is disclosed or known to the Board of Directors or committee which authorizes, approves or ratifies the contract or transaction by a vote or consent sufficient for the purpose without counting the vote(s) or written consent(s) of such interested director(s); or

2.17.2 The fact of such relationship or interest is disclosed or known to the shareholders entitled to vote and they authorize, approve or ratify such contract or transaction by vote or written consent; or

2.17.3 The contract or transaction is fair and reasonable as to this corporation at the time it is authorized by the Board of Directors, a committee thereof or the shareholders.

Common or interested directors may be counted in determining the presence of a quorum at a meeting of the Board of Directors or a committee thereof which authorizes, approves or ratifies such contract or transaction.

ARTICLE 3

COMMITTEES OF THE BOARD OF DIRECTORS

The Board of Directors, by resolution adopted by a majority of the full Board of Directors, may designate from among its members an executive committee and one or more other committees each of which, to the extent provided in such resolution, shall have and may exercise all the authority of the Board of Directors, except as prohibited by the Act.

August 17, 2016

Each committee must have two (2) or more members who serve at the pleasure of the Board of Directors. The Board of Directors, by resolution adopted in accordance with this Article 3, may designate one (1) or more directors as alternate members of any such committee who may act in the place and stead of any absent member or members at any meeting of such committee.

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ARTICLE 4

OFFICERS

August 17, 2016

4.1 Officers. If so appointed by the Board of Directors, the officers of this corporation shall consist of a President and/or Chief Executive Officer, one or more Vice Presidents, a Secretary, a Treasurer and such other officers as appointed by the Board of Directors. Any two (2) or more offices may be held by the same person.  Assistant officers may be appointed by the President from time-to-time.

August 17, 2016

4.2 Appointment and Term of Office. The officers of this corporation shall be appointed annually by the Board of Directors. Each officer shall hold office until a successor has been duly appointed and qualified, or until an earlier resignation, removal from office, or death.

August 17, 2016

4.3 Removal of Officers. Any officer of this corporation may be removed from his or her office or position at any time, with or without cause, by the Board of Directors. Any officer or assistant officer, if appointed by another officer pursuant to authority, if any, received from the Board of Directors, may likewise be removed by such appointing officer.

4.4 Resignation. Any officer of this corporation may resign at any time from his or her office or position by delivering notice to this corporation, the Board of Directors or the Chair of the Board. Such resignation is effective when the notice is delivered unless the notice specifies a later effective date. If a resignation is made effective at a later date and this corporation accepts the future effective date, the Board of Directors may fill the pending vacancy before the effective date if the Board provides that the successor does not take office until the effective date.

4.5 Duties. If so appointed by the Board of Directors, the officers of this corporation shall have the following duties:

The President shall be the chief executive officer of this corporation and shall, subject to the control of the Board of Directors, in general, supervise and control all of the business and affairs of this corporation. In addition, the President shall possess, and may exercise, such power and authority, and shall perform such duties, as may from time to time be assigned to him or her by the Board of Directors, and as are incident to the office of President.

Each Vice President shall possess, and may exercise, such power and authority, and shall perform such duties, as may from time to time be assigned to him or her by the Board of Directors or the President.

The Secretary shall have custody of, and maintain, all of the corporate records except the financial records, shall record the minutes of all meetings of the shareholders and Board of Directors, see that all notices of meetings are duly given, keep a register of the mailing address of each shareholder of this corporation, be responsible for authenticating records of this corporation and perform such other duties as may be prescribed by the Board of Directors or the President.

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The Treasurer shall have custody of all corporate funds and financial records, shall keep full and accurate accounts of receipts and disbursements and shall perform such other duties as may be prescribed by the Board of Directors or the President.

4.6 Other Officers, Employees, and Agents. Each and every other officer, employee, and agent of this corporation shall possess, and may exercise, such power and authority, and shall perform such duties, as may from time to time be assigned to him or her by the Board of Directors, the officer appointing him or her, and such officer or officers who may from time to time be designated by the Board to exercise supervisory authority.

ARTICLE 5

STOCK CERTIFICATES

5.1 Certificates for Shares. The Board of Directors shall determine whether shares of this corporation shall be uncertificated or certificated. If certificated shares are issued, certificates representing shares in this corporation shall be signed (either manually or by facsimile) by the President or Vice President and the Secretary or an Assistant Secretary and may be sealed with the seal of this corporation or a facsimile thereof. A certificate which has been signed by an officer or officers who later shall have ceased to be such officer when the certificate is issued shall nevertheless be valid. No certificate shall be issued for any share until such share is fully paid. Upon receipt of the consideration for which the Board of Directors has authorized for the issuance of the shares, such shares so issued shall be fully paid and nonassessable.

Each share certificate representing shares shall state upon the face thereof: (a) the name of this corporation; (b) that this corporation is organized under the laws of the State of Florida; (c) the name of the person or persons to whom issued; (d) the number and class of shares, and the designation of the series, if any, which such certificate represents; and (e) if different classes of shares or different series within a class are authorized, a summary of the designation, relative rights, preferences, and limitations applicable to each class and the variations in rights, preferences, and limitations determined for each series (and the authority of the Board of Directors to determine variations for future series), or in the alternative, that this corporation will provide the shareholder with a full statement of this information on request and without charge. If the share is uncertificated, this corporation shall, within a reasonable time after the issue or transfer of such share, send the shareholder a written statement of the information required to be placed on a certificate as above set forth.

5.2 Transfer of Shares; Ownership of Shares. Transfers of shares of stock of this corporation shall be made only on the stock transfer books of this corporation, and only after the surrender to this corporation of the certificates representing such shares, if any. Except as provided by the Act, the person in whose name the shares stand on the books of this corporation shall be deemed by this corporation to be the owner thereof for all purposes and this corporation shall not be bound to recognize any equitable or other claim to, or interest in, such shares on the part of any other person, whether or not it shall have express or other notice thereof.

5.3 Lost, Stolen or Destroyed Certificates. This corporation shall issue a new stock certificate in the place of any certificate previously issued if the holder of record of the

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certificate: (a) makes proof in affidavit form that it has been lost, destroyed or wrongfully taken; (b) requests the issuance of a new certificate before this corporation has notice that the certificate has been acquired by a purchaser for value in good faith and without notice of any adverse claim; (c) at the discretion of the Board of Directors, gives bond in such form and amount as this corporation may require, to indemnify this corporation, the transfer agent and registrar against any claim that may be made on account of the alleged loss, destruction or theft of such certificate; and (d) satisfies any other reasonable requirements imposed by this corporation.

ARTICLE 6

ACTIONS WITH RESPECT TO SECURITIES OF OTHER CORPORATIONS

Unless otherwise directed by the Board of Directors, the President or a designee of the President shall have the power to vote and to otherwise act on behalf of this corporation, in person or by proxy, at any meeting of shareholders on, or with respect to, any action of shareholders of any other corporation in which this corporation may hold securities and to otherwise exercise any and all rights and powers which this corporation may possess by reason of its ownership of securities in other corporations.

ARTICLE 7

BOOKS AND RECORDS

7.1 Books and Records. This corporation shall maintain accurate accounting records and shall keep records of minutes of all meetings of its shareholders and Board of Directors, a record of all actions taken by the shareholders or Board of Directors without a meeting, and a record of all actions taken by a committee of the Board of Directors in place of the Board of Directors on behalf of this corporation.

This corporation or its agent shall also maintain a record of its shareholders in a form that permits preparation of a list of names and addresses of all shareholders in alphabetical order by classes  of shares showing the number and series of shares held by each.

This corporation shall keep a copy of the following records:  (a) its Articles or Restated Articles of Incorporation and all amendments thereto currently in effect; (b) its bylaws or restated bylaws and all amendments thereto currently in effect; (c) written communications to all shareholders generally or all shareholders of a class or series within the past three years, including the financial statements furnished for the past three years; (d) a list of the names and business street addresses of its current directors and officers; and (e) its most recent annual report delivered to the Department of State.

Any books, records and minutes may be in written form or in any other form capable of being converted into written form within a reasonable time.

7.2 Financial Information. Unless modified by resolution of the shareholders, not later than four months after the close of each fiscal year this corporation shall prepare a balance sheet showing in reasonable detail the financial condition of the corporation as of the close of its fiscal

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year, and a profit and loss statement showing the results of the operations of the corporation during its fiscal year.

Upon the written request of any shareholder or holder of voting trust certificates for shares of the corporation, the corporation shall mail to such shareholder or holder of voting trust certificates a copy of the most recent such balance sheet and profit and loss statement.

ARTICLE 8

CORPORATE SEAL

The Board of Directors shall provide for a corporate seal which may be facsimile, engraved, printed or an impression seal which shall be circular in form and shall have inscribed thereon the name of this corporation, the words “seal” and “Florida” and the year of incorporation.

ARTICLE 9

AMENDMENTS

These bylaws may be altered, amended or repealed and new bylaws may be adopted, by either the Board of Directors or the shareholders, but the Board of Directors may not alter, amend or repeal any bylaw adopted by shareholders if the shareholders specifically provide that such bylaw is not subject to amendment or repeal by the directors.

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EX-10.1

Exhibit 10.1

EXECUTION COPY

AMENDMENT NO. 1

TO

LOAN AND SERVICING AGREEMENT

This AMENDMENT NO. 1 TO LOAN AND SERVICING AGREEMENT (this “Amendment”) dated as of August 10, 2016 is by and among Tampa Electric Company, in its capacity as “Servicer” under the Loan Agreement (as defined below); TEC Receivables Corp., in its capacity as “Borrower”, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, in its capacities as “Program Agent” and a “Managing Agent,” The Bank of Tokyo-Mitsubishi UFJ, Ltd., in its capacity as a “Committed Lender;” and Royal Bank of Canada, in its capacities as a “Managing Agent” and a “Committed Lender.” Capitalized terms used herein but not specifically defined herein shall have the meanings given to such terms in the Loan Agreement (as defined below).

PRELIMINARY STATEMENTS:

(1) The Servicer, the Borrower, the Committed Lenders, the Managing Agents, the Program Agent and certain Conduit Lenders are parties to that certain Loan and Servicing Agreement dated as of March 24, 2015 (the “Loan Agreement”).

(2) The parties hereto wish to amend the Loan Agreement, in accordance with Section 10.01(b) thereof, upon the terms and subject to the conditions set forth herein.

NOW, THEREFORE, the parties hereto agree as follows:

SECTION 1. Amendments to the Loan Agreement. Effective as of the date hereof and subject to the satisfaction of the condition precedent set forth in Section 2 hereof, the Loan Agreement is hereby amended as follows:

A. Section 1.01 of the Loan Agreement is hereby amended to add the following sentence at the end of the definition of “LIBO Rate”:

“Notwithstanding the foregoing, at no time shall the LIBO Rate be less than 0%.”

B. Section 7.01 of the Loan Agreement is hereby amended to delete subsection 7.01(g)(i) and replace it with the following:

“(i) (A) the average of the Dilution Ratios for any three (3) consecutive Monthly Periods ending during the period from July 31, 2016 through December 31, 2016 shall exceed 5.00% or (B) the average of the Dilution Ratios for any three (3) consecutive Monthly Periods ending January 31, 2017 or thereafter shall exceed 3.00%.”

ACTIVE 216431687v.3

SECTION 2.Conditions of Effectiveness.This Amendment shall become effective as of the date hereof upon the receipt by the Program Agent of this Amendment duly executed by all of the parties hereto.

SECTION 3. Representations and Warranties.

A. Upon the effectiveness of this Amendment, each of the Borrower and the Servicer hereby reaffirms all covenants, representations and warranties made by it in the Loan Agreement and agrees that all such covenants, representations and warranties shall be deemed to have been re-made as of the effective date of this Amendment, unless such representations and warranties by their terms refer to an earlier date than the Effective Date, in which case they shall be correct on and as of such earlier date.

B. Each of the Borrower and the Servicer hereby represents and warrants as to itself (i) that this Amendment constitutes the legal, valid and binding obligation of such party enforceable against such party in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally and general principles of equity which may limit the availability of equitable remedies and (ii) upon the effectiveness of this Amendment, that no event shall have occurred and be continuing which constitutes an Event of Termination or an Incipient Event of Termination.

SECTION 4. Reference to and Effect on the Loan Agreement.

A. On and after the effective date of this Amendment, each reference in the Loan Agreement to “this Agreement”, “hereunder”, “hereof”, “herein” or words of like import referring to the Loan Agreement and each reference to the Loan Agreement in any certificate delivered in connection therewith, shall mean and be a reference to the Loan Agreement as amended hereby.

B. Each of the parties hereto hereby agrees that, except as specifically amended above, the Loan Agreement is hereby ratified and confirmed and shall continue to be in full force and effect and enforceable, except as such enforcement may be limited by applicable bankruptcy, insolvency, reorganization or other similar laws relating to or limiting creditors’ rights generally and general equitable principles.

C. The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender, any Managing Agent or the Program Agent under the Loan Agreement or any of the other Facility Documents, nor constitute a waiver of any provision contained therein.

SECTION 5. Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement.

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ACTIVE 216431687v.3

SECTION 6.Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[Signature pages follow.]

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ACTIVE 216431687v.3

IN WITNESS WHEREOF, the parties have executed this Amendment as ofthe day and year first above written.

TAMPAELECTRICCOMPANY,
asServicer
By:	/s/ K. M. Caruso
Name:	K. M. Caruso
Title:	Treasurer

TEC RECEIVABLES CORP., as Borrower
By:	/s/ K. M. Caruso
Name:	K. M. Caruso
Title:	Treasurer

4

ACTIVE 216431687v.3

THEBANKOFTOKYO-MITSUBISHIUFJ,
LTD.,NEWYORKBRANCH,asProgramAgent
and as a Managing Agent
By:	/s/ Christopher Pohl
Name:	Christopher Pohl
Title:	Managing Director

THEBANKOFTOKYO-MITSUBISHIUFJ,
LTD., as a Committed Lender
By:	/s/ Christopher Pohl
Name:	Christopher Pohl
Title:	Managing Director

5

ACTIVE 216431687v.3

ROYAL BANK OF CANADA, as a Managing
Agent and as a Committed Lender
By:	/s/ Veronica L. Gallagher
Name:	Veronica L. Gallagher
Title:	Authorized Signatory

6

ACTIVE 216431687v.3

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert R. Bennett, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	Nov. 7, 2016	/s/  ROBERT R. BENNETT
		ROBERT R. BENNETT
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	Nov. 7, 2016	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, Gordon L. Gillette, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	Nov. 7, 2016	/s/  GORDON L. GILLETTE
		GORDON L. GILLETTE
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	Nov. 7, 2016	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

TECO ENERGY, INC

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of TECO Energy, Inc. (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended Sept. 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	Nov. 7, 2016	/s/  ROBERT R. BENNETT
		ROBERT R. BENNETT
		President, Chief Executive Officer and Director
		(Principal Executive Officer)
Date:	Nov. 7, 2016	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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

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

EX-32.2

Exhibit 32.2

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended Sept. 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	Nov. 7, 2016	/s/  GORDON L. GILLETTE
		GORDON L. GILLETTE
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	Nov. 7, 2016	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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

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

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 04, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 24.4	$ 23.8
Receivables, less allowance for uncollectibles	268.2	280.7
Inventories, at average cost
Regulatory assets	21.8	44.8
Prepayments and other current assets	24.0	30.8
Total current assets	507.3	570.3
Property, plant and equipment
Construction work in progress	916.8	794.7
Other property	16.8	15.9
Property, plant and equipment, at original costs	10,624.1	10,194.7
Accumulated depreciation	(2,862.2)	(2,712.9)
Total property, plant and equipment, net	7,761.9	7,481.8
Other assets
Regulatory assets	458.7	395.2
Goodwill	408.4	408.4
Deferred charges and other assets	87.4	77.8
Total other assets	954.5	881.4
Total assets	9,223.7	8,933.5
Current liabilities
Long-term debt due within one year	0.0	333.3
Notes payable	610.5	247.0
Accounts payable	264.0	255.4
Customer deposits	160.6	182.1
Regulatory liabilities	148.2	84.8
Derivative liabilities	1.6	24.1
Interest accrued	53.1	36.2
Taxes accrued	65.0	13.2
Other	44.5	22.6
Total current liabilities	1,347.5	1,198.7
Other liabilities
Deferred income taxes	650.1	570.7
Investment tax credits	10.2	10.5
Regulatory liabilities	718.8	715.8
Deferred credits and other liabilities	412.6	389.6
Long-term debt, less amount due within one year	3,490.3	3,489.2
Total other liabilities	5,282.0	5,175.8
Commitments and contingencies
Capital
Common equity	0.0	235.3
Additional paid in capital	2,154.7	1,894.5
Retained earnings	457.1	441.4
Accumulated other comprehensive loss	(17.6)	(12.2)
Total capital	2,594.2	2,559.0
Long-term debt	3,490.3	3,489.2
Total liabilities and capital	9,223.7	8,933.5
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	15.4	9.1
Receivables, less allowance for uncollectibles	254.9	230.2
Inventories, at average cost
Taxes receivable from affiliate	0.0	61.3
Regulatory assets	20.6	44.3
Prepayments and other current assets	16.3	21.5
Total current assets	468.1	545.1
Property, plant and equipment
Construction work in progress	875.2	771.1
Utility plant in service, at original costs	9,815.4	9,440.0
Accumulated depreciation	(2,808.3)	(2,676.8)
Utility plant in service, net	7,007.1	6,763.2
Other property	10.5	9.7
Total property, plant and equipment, net	7,017.6	6,772.9
Other assets
Regulatory assets	438.2	373.8
Deferred charges and other assets	468.1	390.6
Other	29.9	16.8
Total assets	7,953.8	7,708.6
Current liabilities
Long-term debt due within one year	0.0	83.3
Notes payable	49.0	61.0
Accounts payable	222.0	221.6
Customer deposits	155.2	176.3
Regulatory liabilities	140.4	83.2
Derivative liabilities	1.4	24.1
Interest accrued	40.1	16.9
Taxes accrued	74.5	13.2
Other	10.3	10.2
Total current liabilities	692.9	689.8
Other liabilities
Deferred income taxes	1,388.2	1,308.8
Investment tax credits	10.2	10.5
Regulatory liabilities	597.0	603.5
Deferred credits and other liabilities	339.3	318.8
Long-term debt, less amount due within one year	2,162.6	2,161.7
Total deferred credits	2,334.7	2,241.6
Commitments and contingencies
Capital
Common equity	2,395.4	2,305.4
Retained earnings	371.2	313.7
Accumulated other comprehensive loss	(3.0)	(3.6)
Total capital	2,763.6	2,615.5
Long-term debt	2,162.6	2,161.7
Total capitalization	4,926.2	4,777.2
Total liabilities and capital	7,953.8	7,708.6
Fuel [Member]
Inventories, at average cost
Utility inventories	85.2	113.4
Fuel [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	80.7	105.6
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	83.7	76.8
Materials and Supplies [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	80.2	73.1
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,473.9	7,270.3
Electric [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,473.9	7,270.3
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	2,216.6	2,113.8
Gas [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,466.3	$ 1,398.6

XML

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Allowance for uncollectibles	$ 2.9	$ 2.1
Common equity, shares authorized	10,000,000	400,000,000
Common equity, par value	$ 0.01	$ 1
Common equity, shares outstanding	1,000	235,300,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 2.5	$ 1.5

XML

Consolidated Condensed Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Regulated electric	$ 585.2	$ 559.3	$ 1,506.6	$ 1,540.8
Regulated gas	138.6	131.5	522.9	518.1
Unregulated	2.9	3.0	9.0	8.5
Total revenues	726.7	693.8	2,038.5	2,067.4
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	53.2	42.0	200.8	194.1
Other	153.6	150.1	452.2	451.9
Merger transaction-related costs	37.9	15.4	109.4	15.4
Depreciation and amortization	92.0	87.8	272.0	260.3
Taxes, other than income	56.3	51.5	160.8	156.6
Total expenses	604.8	547.2	1,701.8	1,631.3
Income from operations	121.9	146.6	336.7	436.1
Other income
Allowance for other funds used during construction	6.5	4.7	18.1	12.2
Other income, net	2.1	1.4	4.6	4.4
Total other income	8.6	6.1	22.7	16.6
Interest charges
Interest expense	47.1	48.4	142.7	146.4
Allowance for borrowed funds used during construction	(3.2)	(2.3)	(9.1)	(6.0)
Total interest charges	43.9	46.1	133.6	140.4
Income from continuing operations before provision for income taxes	86.6	106.6	225.8	312.3
Provision for income taxes	17.2	41.7	77.2	122.1
Net income from continuing operations	69.4	64.9	148.6	190.2
Discontinued operations
Loss from discontinued operations	(0.2)	(17.8)	(0.4)	(105.5)
Benefit for income taxes	0.2	6.1	0.3	38.3
Loss from discontinued operations, net	0.0	(11.7)	(0.1)	(67.2)
Net income	$ 69.4	$ 53.2	$ 148.5	$ 123.0

XML

Consolidated Condensed Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net income		$ 69.4		$ 53.2		$ 148.5		$ 123.0
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2		0.2		0.6		3.3
Amortization of unrecognized benefit costs and other	[1]	0.5		0.2		0.8		1.8
Recognized cost due to curtailment		0.0	[2]	0.0		0.1	[2]	0.0
Change in benefit obligation due to remeasurement/ valuation		(6.9)		(5.7)		(6.9)		(5.7)
Recognized cost due to settlement		0.0		7.7	[3]	0.0		7.7	[3]
Other comprehensive income (loss), net of tax		(6.2)		2.4		(5.4)		7.1
Comprehensive income		$ 63.2		$ 55.6		$ 143.1		$ 130.1

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

[2] Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.

[3] Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15 for additional information.

XML

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities
Net income	$ 148.5	$ 123.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	272.0	261.5
Depreciation and amortization	272.0	260.3
Deferred income taxes and investment tax credits	76.5	84.6
Allowance for other funds used during construction	(18.1)	(12.2)
Non-cash stock compensation	6.4	10.1
Loss on disposals of business/assets, pretax	(0.3)	10.0
Deferred recovery clauses	54.5	13.1
Asset impairment, pretax	0.0	78.6
Receivables, less allowance for uncollectibles	12.5	46.1
Inventories	21.3	(45.7)
Prepayments and other current assets	6.8	(14.2)
Taxes accrued	54.0	31.6
Interest accrued	16.9	14.7
Accounts payable	27.7	(85.7)
Other	(27.6)	(34.6)
Cash flows from operating activities	651.1	480.9
Cash flows from investing activities
Capital expenditures	(573.3)	(511.0)
Other investing activities	8.5	(0.2)
Cash flows used in investing activities	(564.8)	(511.2)
Cash flows from financing activities
Dividends and dividend equivalents	(135.4)	(158.8)
Proceeds from the sale of common stock and equity contributions	26.2	6.4
Proceeds from long-term debt issuance	0.0	499.7
Repayment of long-term debt	(333.3)	(274.5)
Net decrease in short-term debt (maturities of 90 days or less)	(36.5)	(11.0)
Proceeds from other short-term debt (maturities over 90 days)	400.0	0.0
Other financing activities	(6.7)	(1.5)
Cash flows from (used in) financing activities	(85.7)	60.3
Net increase in cash and cash equivalents	0.6	30.0
Cash and cash equivalents at beginning of the period	23.8	25.4
Cash and cash equivalents at end of the period	24.4	55.4
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	(20.6)	(8.1)
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	239.6	226.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	245.1	233.8
Deferred income taxes and investment tax credits	69.8	52.6
Allowance for other funds used during construction	(17.8)	(12.1)
Deferred recovery clauses	54.3	13.7
Receivables, less allowance for uncollectibles	(24.7)	(31.4)
Inventories	17.8	(44.4)
Prepayments and other current assets	6.4	(7.9)
Taxes accrued	122.6	93.6
Interest accrued	23.2	24.5
Accounts payable	18.6	(39.8)
Other	(52.3)	(34.4)
Cash flows from operating activities	702.6	474.6
Cash flows from investing activities
Capital expenditures	(517.6)	(473.8)
Net proceeds from sale of assets	8.7	0.0
Cash flows used in investing activities	(508.9)	(473.8)
Cash flows from financing activities
Dividends and dividend equivalents	(182.1)	(175.9)
Common stock	90.0	88.0
Proceeds from long-term debt issuance	0.0	251.2
Repayment of long-term debt	(83.3)	(83.3)
Net decrease in short-term debt (maturities of 90 days or less)	(12.0)	(58.0)
Cash flows from (used in) financing activities	(187.4)	22.0
Net increase in cash and cash equivalents	6.3	22.8
Cash and cash equivalents at beginning of the period	9.1	10.4
Cash and cash equivalents at end of the period	15.4	33.2
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (19.6)	$ (10.1)

XML

Consolidated Condensed Statements of Capital (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Balance, Dec. 31, 2015		$ 2,559.0
Net income	$ 69.4	148.5
Other comprehensive loss, after tax	(6.2)	(5.4)
Common stock issued		(1.6)
Impact of Merger		0.0
Dividends and dividend equivalents		(135.4)
Stock compensation expense		6.4
Restricted stock—dividends		(1.6)
Cumulative effect of change in accounting		2.6
Equity contribution		22.1
Other		(0.4)
Balance, Sept. 30, 2016	2,594.2	2,594.2
Common Stock [Member]
Balance, Dec. 31, 2015		$ 235.3
Balance, Dec. 31, 2015, shares		235.3
Common stock issued		$ 0.2
Common stock issued, shares		0.2
Impact of Merger		$ (235.5)
Impact of Merger, shares		(235.3)
Balance, Sept. 30, 2016	$ 0.0	$ 0.0
Balance, Sept. 30, 2016, shares	0.0	0.0
Additional Paid-in Capital [Member]
Balance, Dec. 31, 2015		$ 1,894.5
Common stock issued		(1.8)
Impact of Merger		235.5
Stock compensation expense		6.4
Restricted stock—dividends		(1.6)
Equity contribution		22.1
Other		(0.4)
Balance, Sept. 30, 2016	$ 2,154.7	2,154.7
Retained Earnings [Member]
Balance, Dec. 31, 2015		441.4
Net income		148.5
Dividends and dividend equivalents		(135.4)
Cumulative effect of change in accounting		2.6
Balance, Sept. 30, 2016	457.1	457.1
Accumulated Other Comprehensive Income (Loss) [Member]
Balance, Dec. 31, 2015		(12.2)
Other comprehensive loss, after tax		(5.4)
Balance, Sept. 30, 2016	$ (17.6)	$ (17.6)

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Total revenues	$ 726.7	$ 693.8	$ 2,038.5	$ 2,067.4
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	53.2	42.0	200.8	194.1
Other	153.6	150.1	452.2	451.9
Depreciation and amortization	92.0	87.8	272.0	260.3
Taxes, other than income	56.3	51.5	160.8	156.6
Total expenses	604.8	547.2	1,701.8	1,631.3
Income from operations	121.9	146.6	336.7	436.1
Other income
Allowance for other funds used during construction	6.5	4.7	18.1	12.2
Other income, net	2.1	1.4	4.6	4.4
Total other income	8.6	6.1	22.7	16.6
Interest charges
Interest expense	47.1	48.4	142.7	146.4
Allowance for borrowed funds used during construction	(3.2)	(2.3)	(9.1)	(6.0)
Total interest charges	43.9	46.1	133.6	140.4
Income before provision for income taxes	86.6	106.6	225.8	312.3
Provision for income taxes	17.2	41.7	77.2	122.1
Net income	69.4	53.2	148.5	123.0
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.2	0.6	3.3
Other comprehensive income (loss), net of tax	(6.2)	2.4	(5.4)	7.1
Comprehensive income	63.2	55.6	143.1	130.1
Tampa Electric Company [Member]
Revenues
Electric	586.0	560.1	1,509.0	1,542.9
Gas	103.1	88.1	329.9	302.0
Total revenues	689.1	648.2	1,838.9	1,844.9
Expenses
Fuel	173.5	176.6	426.1	492.5
Purchased power	38.3	23.8	80.5	60.5
Cost of natural gas sold	40.4	28.5	126.4	101.9
Other	134.6	128.7	388.2	384.8
Depreciation and amortization	82.8	79.0	245.1	233.8
Taxes, other than income	52.6	47.8	148.6	144.9
Total expenses	522.2	484.4	1,414.9	1,418.4
Income from operations	166.9	163.8	424.0	426.5
Other income
Allowance for other funds used during construction	6.2	4.6	17.8	12.1
Other income, net	2.1	1.2	4.3	3.6
Total other income	8.3	5.8	22.1	15.7
Interest charges
Interest on long-term debt	27.7	29.0	84.5	84.5
Other interest	1.5	1.0
Interest expense			3.9	3.3
Allowance for borrowed funds used during construction	(3.1)	(2.2)	(8.6)	(5.8)
Total interest charges	26.1	27.8	79.8	82.0
Income before provision for income taxes	149.1	141.8	366.3	360.2
Provision for income taxes	48.5	53.5	126.7	133.8
Net income	100.6	88.3	239.6	226.4
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.2	0.6	3.3
Other comprehensive income (loss), net of tax	0.2	0.2	0.6	3.3
Comprehensive income	$ 100.8	$ 88.5	$ 240.2	$ 229.7

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14 for further information.

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 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.

Tampa Electric Company [Member]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.See Note 14 for further information.

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $63.7 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 rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, and $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2016

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to and were adopted by the company are described as follows:

Interest – Imputation of Interest

In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The company adopted this standard in the first quarter of 2016, and Dec. 31, 2015 balances have been retrospectively restated. This change resulted in $27.7 million of debt issuance costs as of Dec. 31, 2015, previously presented as “Deferred charges and other assets”, being reclassified as a deduction from the carrying amount of the related “Long-term debt, less amount due within one year” line item on its Consolidated Condensed Balance Sheet. In accordance with ASU 2015-15 Interest: Imputation of Interest, the company continues to present debt issuance costs related to its letter of credit arrangements and related instruments in “Prepayments and other current assets” on its Consolidated Condensed Balance Sheets.

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.  The standard clarifies 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 company early adopted in the third quarter of 2016 as permitted.

Compensation – Stock Compensation

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation to simplify 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 liabilities, and presentation on the statement of cash flows.  The company early adopted as permitted in the first quarter of 2016. Each aspect has an accounting impact and was implemented as follows:

• Income tax consequences – 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. 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.

• 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 Sept. 30, 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. Therefore, the company reclassified $1.5 million from operating activities to financing activities for the nine months ended Sept. 30, 2015.

Future Accounting Pronouncements

The company considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB but have not yet been adopted by TECO Energy. Any ASUs not included below were assessed and determined to be either not applicable to the company or are not expected to have a material impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new principle-based revenue recognition framework. 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 to. 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 beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company will adopt this guidance effective Jan. 1, 2018. The company has developed an implementation plan and is continuing to evaluate the available adoption methods. While the company does not expect the impact to be significant, it is continuing to evaluate the impact of adoption of this standard on its consolidated financial statements and disclosures.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. 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.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Dec. 15, 2017.  

Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods including interim reporting within those periods, beginning after Dec. 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides 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. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance will be effective for the company beginning in 2018, with early adoption permitted, and is required to be applied on a retrospective approach.  The company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to and were adopted by TEC are described as follows:

Interest – Imputation of Interest

In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. TEC adopted this standard in the first quarter of 2016, and Dec. 31, 2015 balances have been retrospectively restated. This change resulted in $18.1 million of debt issuance costs as of Dec. 31, 2015, previously presented as “Deferred charges and other assets”, being reclassified as a deduction from the carrying amount of the related “Long-term debt, less amount due within one year” line item on its Consolidated Condensed Balance Sheet. In accordance with ASU 2015-15 Interest: Imputation of Interest, TEC continues to present debt issuance costs related to its letter of credit arrangements and related instruments in “Prepayments and other current assets” on its Consolidated Condensed Balance Sheets.

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.  The standard clarifies 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. TEC early adopted in the third quarter of 2016 as permitted.

Future Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or are not expected to have a material impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new principle-based revenue recognition framework. 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 to. 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 beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective Jan. 1, 2018. TEC has developed an implementation plan and is continuing to evaluate the available adoption methods. While TEC does not expect the impact to be significant, it is continuing to evaluate the impact of adoption of this standard on its consolidated financial statements and disclosures.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. 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.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Dec. 15, 2017.  

Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods including interim reporting within those periods, beginning after Dec. 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides 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. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance will be effective for TEC beginning in 2018, with early adoption permitted, and is required to be applied on a retrospective approach.  TEC is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

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Regulatory

9 Months Ended

Sep. 30, 2016

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities 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 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 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.4	$	74.7
Cost-recovery clauses - deferred balances (2)		4.5		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		2.1		26.5
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.4		240.6
Deferred bond refinancing costs (5)		7.1		6.5
Debt basis adjustment (6)		14.9		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		14.8		12.1
Total regulatory assets		480.5		440.0
Less: Current portion		21.8		44.8
Long-term regulatory assets	$	458.7	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.2	$	7.9
Cost-recovery clauses (2)		111.5		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		670.6		679.9
Bill reduction credit (8)		8.0		0.3
Other		13.6		0.5
Total regulatory liabilities		867.0		800.6
Less: Current portion		148.2		84.8
Long-term regulatory liabilities	$	718.8	$	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 the 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 the 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.

(8) See Note 14 for information regarding NMGC’s stipulation agreement including a commitment to provide an annual bill reduction credit to customers. A minor portion of this balance is attributable to timing of bill reduction credits related to TECO Energy’s acquisition of NMGC in September 2014.

Tampa Electric Company [Member]

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities 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 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.1	$	74.6
Cost-recovery clauses - deferred balances (2)		4.4		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		1.5		26.2
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.5		238.3
Deferred bond refinancing costs (5)		5.9		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.1		10.7
Total regulatory assets		458.8		418.1
Less: Current portion		20.6		44.3
Long-term regulatory assets	$	438.2	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.3	$	5.7
Cost-recovery clauses (2)		107.8		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		554.8		570.0
Other		13.4		0.7
Total regulatory liabilities		737.4		686.7
Less: Current portion		140.4		83.2
Long-term regulatory liabilities	$	597.0	$	603.5

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

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

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

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

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

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

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Taxes

4. Income Taxes

The effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 19.86% and 39.12%, respectively. The effective tax rate decreased to 34.19% for the nine months ended Sept. 30, 2016 from 39.10% for the same period in 2015.

The decrease in the three-month effective tax rate of 19.26% in 2016 versus the same period in 2015 is primarily due to tax benefits recorded in the third quarter of 2016 for federal R&D credits, lower non-deductible Merger transaction costs and other permanent book-to-tax differences.

The effective tax rate for year-to-date 2016 differed from the U.S. statutory rate of 35% primarily due to the effects of federal R&D credits and the tax benefit related to long-term incentive compensation offset by non-deductible Merger transaction costs (see Notes 2 and 14 for further description). The effective tax rate for year-to-date 2015 differed from the U.S. statutory rate primarily due to tax expense related to long-term incentive compensation shares that vested below target levels.

Effective July 1, 2016 and due to the Merger with Emera, TECO Energy and its subsidiaries are included in a consolidated U.S federal income tax return with EUSHI and its subsidiaries. TECO Energy’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TECO Energy’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.  

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 2013 and forward. Years 2015 and the short tax year ending June 30, 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.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.  As of Sept. 30, 2016 and Dec. 31, 2015, TECO Energy’s uncertain tax positions were $7.7 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for net operating losses and tax credit carryforwards. The increase was primarily due to an uncertain tax position related to federal R&D tax credits. TECO Energy believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s federal income tax return for the short tax year ending June 30, 2016.  As of Sept. 30, 2016, if recognized, $7.7 million of the unrecognized tax benefits would reduce TECO Energy’s effective tax rate.

Tampa Electric Company [Member]

Income Taxes

4. Income Taxes

Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. Taxes accrued to affiliates was $14.2 million as of Sept. 30 2016.

TEC’s effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 32.53% and 37.73%, respectively. The effective tax rates for the nine months ended Sept. 30, 2016 and 2015 were 34.59% and 37.15%, respectively. The decrease in the three-month effective tax rate of 5.2% in 2016 versus the same period in 2015 is primarily due to a tax benefit recorded in the third quarter of 2016 for federal R&D credits. TEC’s effective tax rates for the nine months ended Sept. 30, 2016 and 2015 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity and federal R&D credits.

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 2013 and forward. Years 2015 and the short tax year ending June 30, 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able 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 beingutilized.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes require an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.  As of Sept. 30, 2016 and Dec. 31, 2015, TEC’s uncertain tax positions were $6.5 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. The increase was due to an uncertain tax position related to federal R&D tax credits. TEC believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016.  As of Sept. 30, 2016, if recognized, $6.5 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

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Employee Postretirement Benefits

9 Months Ended

Sep. 30, 2016

Employee Postretirement Benefits

5. Employee Postretirement Benefits

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sept. 30,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.9		$	6.7		$	0.5		$	0.6
Interest cost		7.2			6.5			2.0			2.0
Expected return on assets		(11.5	)		(9.1	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		4.8			3.2			0.1			0.0
Regulatory asset		0.0			0.0			0.3			0.3
Curtailment cost		0.0			0.0			0.0			0.0
Settlement cost		0.0			0.0			0.0			0.0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	2.0		$	2.0
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.9		$	17.6		$	1.4		$	1.7
Interest cost		23.6			22.6			6.4			6.1
Expected return on assets		(34.2	)		(32.4	)		(0.9	)		(0.8	)
Amortization of:
Prior service (benefit) cost		0.2			(0.2	)		(1.9	)		(1.8	)
Actuarial loss		11.7			11.4			0.1			0.0
Regulatory asset		0.0			0.0			0.8			0.8
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	$	17.1		$	19.0		$	5.9		$	6.0

For the Jan. 1, 2016 measurement, TECO Energy used 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.

As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%.

As a result of the remeasurement, TECO Energy’s net periodic benefit expense increased by $0.6 million for pension benefits and zero for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TECO Energy’s liability for pension benefits increased by $61.7 million and $17.6 million for other postretirement benefits. The associated regulatory asset increased $54.0 million for pension benefits and $14.1 million for other postretirement benefits. Accumulated other comprehensive income decreased $7.7 million for pension benefits and $3.5 million for other postretirement benefits.

TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan for the nine months ended Sept. 30, 2016 and 2015, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2016 and 2015.

For the three and nine months ended Sept. 30, 2016, TECO Energy and its subsidiaries reclassified $0.8 million and $1.8 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $0.2 million and $2.4 million for the three and nine months ended Sept. 30, 2015, respectively. In addition, during the three and nine months ended Sept. 30, 2016, the regulated companies reclassified $3.8 million and $9.1 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2015, respectively.

The settlement cost recognized relates to the settlement of the SERP liability for the TECO Coal participants. 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 as a result of the Merger, which expected retirements occurred in the third quarter of 2016.

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 have occurred as a result of the Merger.

Tampa Electric Company [Member]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Sept. 30, 2016 and 2015, respectively, was $3.5 million and $3.3 million for pension benefits, and $1.7 million and $1.4 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2016 and 2015, respectively, was $9.6 million and $10.1 million for pension benefits, and $4.7 million and $4.3 million for other postretirement benefits.  

For the Jan. 1, 2016 measurement, TECO Energy assumed a 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 used a discount rate of 4.667%.

As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%.

As a result of the remeasurement, TEC’s net periodic benefit expense increased by $0.8 million for pension benefits and $0.3 million for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TEC’s liability and associated regulatory asset for pension benefits increased $53.3 million and $12.4 million for other postretirement benefits.

TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan in the nine months ended Sept. 30, 2016 and 2015, respectively. TEC’s portion of the contributions was $30.9 million and $43.9 million, respectively.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2016, TEC reclassified $2.8 million and $7.6 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.3 million and $7.0 million for the three and nine months ended Sept. 30, 2015, respectively.

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Short-Term Debt

9 Months Ended

Sep. 30, 2016

Short-Term Debt

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		150.0		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		11.5		1.4		125.0		23.0		1.7
Total	$	1,300.0	$	610.5	$	1.9	$	900.0	$	247.0	$	2.2
(1)     Borrowings outstanding are reported as notes payable.
(2)     This 5-year facility matures Dec. 17, 2018.
(3)     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 Sept. 30, 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 Sept. 30, 2016 and Dec. 31, 2015 was 1.71% and 1.29%, respectively.  

TECO Energy/TECO Finance Credit Facility

On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the one-month London interbank deposit rate plus 1.00%.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	49.0	$	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) This 3-year facility matures Mar. 23, 2018.

At Sept. 30, 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 Sept. 30, 2016 and Dec. 31, 2015 was 1.32% and 0.89%, respectively.

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Long-Term Debt

9 Months Ended

Sep. 30, 2016

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2016, total long-term debt had a carrying amount of $3,490.3 million and an estimated fair market value of $3,911.2 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 or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 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.

As of Sept. 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.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2016, TEC’s total long-term debt had a carrying amount of $2,162.6 million and an estimated fair market value of $2,505.6 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 or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.3 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 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.

As of Sept. 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.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies

8. 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.

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, 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 against PGS remains pending, with a trial currently expected in February 2017. 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.

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, a settlement was reached with all the named plaintiffs in the subrogation lawsuits. A motion to dismiss the appeal was granted by the court on Aug. 2, 2016.

The settlements were not material to the company.

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.  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 were consolidated per court order.  Since the consolidation, two of the complaints were amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

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

In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.

In September 2016, a hearing was held to gain preliminary approval of a negotiated stipulation of settlement. After that hearing, the judge entered an order granting preliminary approval of the class action settlement and scheduling a final approval hearing for December 2016.

There can be no assurance that the court will grant final approval of the settlement. However, while the outcome of such proceeding remains 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 had 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.

On Sept. 23, 2016, TGH filed a request for resubmission to arbitration. On Oct. 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission, officially commencing the new arbitration and starting the time periods for constitution of the new tribunal.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

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

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

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

Merger Commitments

In connection with the Merger with Emera, TECO Energy made certain commitments approved by the NMPRC. See Note 14 for additional information.

Guarantees

A summary of the face amount or maximum theoretical obligation and the year of expiration under guarantees as of Sept. 30, 2016 is as follows:

(millions)												Maximum
										After (1)			Theoretical			Liabilities Recognized
Guarantees for the Benefit of:	2016		2017			2018-2020			2020			Obligation			at Sept. 30, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0		$	0.0		$	0.0		$	93.9		$	93.9		$	0.0
Letters of indemnity - coal mining permits (3)		0.0			84.5			0.0			0.0			84.5			0.0
	$	0.0		$	84.5		$	0.0		$	93.9		$	178.4		$	0.0
(1)    These 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 of 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 Sept. 30, 2016. See Note 10 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. 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.

Financial Covenants

TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

Tampa Electric Company [Member]

Commitments and Contingencies

8. Commitments and Contingencies

Legal Contingencies

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

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, 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 against PGS remains pending, with a trial currently expected in February 2017. 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.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

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

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

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

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2016, TEC was in compliance with all applicable financial covenants.

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Segment Information

9 Months Ended

Sep. 30, 2016

Segment Information

9. 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.  

Segment Information (1)
(millions)	Tampa		Peoples		New Mexico				TECO										TECO
Three months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations			Energy
2016
Revenues - external	$	585.1	$	103.3	$	35.7			$	0.0		$	2.6			$	0.0		$	726.7
Sales to affiliates		0.8		0.4		0.0				0.0			0.1				(1.3	)		0.0
Total revenues		585.9		103.7		35.7				0.0			2.7				(1.3	)		726.7
Total interest charges		22.4		3.7		2.8				0.0			15.2				(0.2	)		43.9
Net income (loss) from continuing operations		94.1		6.5		(19.8	)	(5)		0.0			(11.4	)	(5)		0.0			69.4
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			0.0				0.0			0.0
Net income (loss)	$	94.1	$	6.5	$	(19.8	)		$	0.0		$	(11.4	)		$	0.0		$	69.4
2015
Revenues - external	$	559.4	$	88.1	$	43.7			$	0.0		$	2.6			$	0.0		$	693.8
Sales to affiliates		0.8		2.0		0.0				0.0			0.0				(2.8	)		0.0
Total revenues		560.2		90.1		43.7				0.0			2.6				(2.8	)		693.8
Total interest charges		24.1		3.7		3.2				0.0			15.4				(0.3	)		46.1
Net income (loss) from continuing operations		82.1		6.2		(2.8	)			0.0			(20.6	)			0.0			64.9
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(12.1	)		0.4				0.0			(11.7	)
Net income (loss)	$	82.1	$	6.2	$	(2.8	)		$	(12.1	)	$	(20.2	)		$	0.0		$	53.2

(millions)	Tampa		Peoples		New Mexico				TECO											TECO
Nine months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations				Energy
2016
Revenues - external	$	1,506.6	$	330.0	$	194.0			$	0.0		$	7.9			$	0.0			$	2,038.5
Sales to affiliates		3.0		6.8		0.0				0.0			0.1				(9.9	)			0.0
Total revenues		1,509.6		336.8		194.0				0.0			8.0				(9.9	)			2,038.5
Total interest charges		68.8		11.1		9.1				0.0			45.3				(0.7	)			133.6
Net income (loss) from continuing operations		212.9		26.7		(4.8	)	(5)		0.0			(86.2	)	(5)		0.0				148.6
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			(0.1	)			0.0				(0.1	)
Net income (loss)	$	212.9	$	26.7	$	(4.8	)		$	0.0		$	(86.3	)		$	0.0			$	148.5
2015
Revenues - external	$	1,540.8	$	302.0	$	216.7			$	0.0		$	7.9			$	0.0			$	2,067.4
Sales to affiliates		2.4		4.5		0.0				0.0			0.1				(7.0	)			0.0
Total revenues		1,543.2		306.5		216.7				0.0			8.0				(7.0	)			2,067.4
Total interest charges		71.2		10.8		9.8				0.0			49.6				(1.0	)			140.4
Net income (loss) from continuing operations		198.0		28.4		11.0				0.0			(47.2	)			0.0				190.2
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(69.6	)		2.4				0.0				(67.2	)
Net income (loss)	$	198.0	$	28.4	$	11.0			$	(69.6	)	$	(44.8	)		$	0.0			$	123.0
At Sept. 30, 2016
Total assets	$	7,244.9	$	1,161.5	$	1,230.4			$	0.0		$	2,031.8			$	(2,444.9	)	(4)	$	9,223.7
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 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 consolidated tax reclassifications.
(5)    Includes transaction costs associated with the Merger with Emera. See Note 14.

Tampa Electric Company [Member]

Segment Information

9. Segment Information

(millions)	Tampa									Tampa Electric
Three months ended Sept. 30,	Electric		PGS		Eliminations					Company
2016
Revenues - external	$	585.9	$	103.2	$	0.0				$	689.1
Intracompany sales		0.0		0.5		(0.5	)				0.0
Total revenues		585.9		103.7		(0.5	)				689.1
Total interest charges		22.4		3.7		0.0					26.1
Net income	$	94.1	$	6.5	$	0.0				$	100.6
2015
Revenues - external	$	560.1	$	88.1	$	0.0				$	648.2
Intracompany sales		0.1		2.0		(2.1	)				0.0
Total revenues		560.2		90.1		(2.1	)				648.2
Total interest charges		24.1		3.7		0.0					27.8
Net income	$	82.1	$	6.2	$	0.0				$	88.3
Nine months ended Sept. 30,
2016
Revenues - external	$	1,508.9	$	330.0	$	0.0				$	1,838.9
Intracompany sales		0.7		6.8		(7.5	)				0.0
Total revenues		1,509.6		336.8		(7.5	)				1,838.9
Total interest charges		68.8		11.1		(0.1	)				79.8
Net income	$	212.9	$	26.7	$	0.0				$	239.6
2015
Revenues - external	$	1,542.9	$	302.0	$	0.0				$	1,844.9
Intracompany sales		0.3		4.5		(4.8	)				0.0
Total revenues		1,543.2		306.5		(4.8	)				1,844.9
Total interest charges		71.2		10.8		0.0					82.0
Net income	$	198.0	$	28.4	$	0.0				$	226.4
Total assets at Sept. 30, 2016	$	7,244.9	$	1,161.5	$	(452.6	)	(2	)	$	7,953.8
Total assets at Dec. 31, 2015 (1)	$	7,003.8	$	1,136.1	$	(431.3	)	(2	)	$	7,708.6

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

(2) Amounts relate to consolidated tax reclassifications.

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Accounting for Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2016

Accounting for Derivative Instruments and Hedging Activities

10. 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 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.

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 Sept. 30, 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 Sept. 30, 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 $2.2 million and $0.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.7 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in 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 Sept. 30, 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 Sept. 30, 2016, net pretax gains of $0.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2016 and 2015 is presented in Note 12. 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 Sept. 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 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		14.2
2017		0.0		32.8
2018		0.0		5.3
Total		0.0		52.3

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 Sept. 30, 2016, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

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

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 11). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Sept. 30, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Sept. 30, 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. Derivative assets totaled $1.5 million and $0.0 as of Sept. 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.5 million and $26.2 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in 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 Sept. 30, 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 Sept. 30, 2016, net pretax losses of $0.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Sept. 30, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2016 and 2015 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassification to income was reflected in “Interest expense”.

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

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		7.7
2017		0.0		23.2
2018		0.0		5.3
Total		0.0		36.2

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 Sept. 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.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

identical or comparable assets or liabilities;

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

cost); and

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

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

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

The following tables set forth by level within the fair value hierarchy, the company’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. 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 Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	2.2	$	0.0	$	2.2
Liabilities
Natural gas derivatives	$	0.0	$	1.7	$	0.0	$	1.7
	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 10). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 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 Sept. 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.

Tampa Electric Company [Member]

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

identical or comparable assets or liabilities;

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

cost); and

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

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

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

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis. As 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 Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
	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 Sept. 30, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2016

Other Comprehensive Income

12. Other Comprehensive Income

TECO Energy reported the following OCI related to changes in the fair value of cash flow hedges, recognized cost due to curtailment, change in benefit obligation due to remeasurement and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Sept. 30,									Nine months ended Sept. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
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			1.0			(0.4	)		0.6
Gain on cash flow hedges		0.3			(0.1	)		0.2			1.0			(0.4	)		0.6
Amortization of unrecognized benefit costs and other (2)		0.8			(0.3	)		0.5			1.3			(0.5	)		0.8
Change in benefit obligation due to remeasurement (3)		(11.2	)		4.3			(6.9	)		(11.2	)		4.3			(6.9	)
Recognized cost due to curtailment (4)		0.0			0.0			0.0			0.1			0.0			0.1
Total other comprehensive loss	$	(10.1	)	$	3.9		$	(6.2	)	$	(8.8	)	$	3.4		$	(5.4	)
2015
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	4.3		$	(1.5	)	$	2.8
Reclassification from AOCI to net income (1)		0.3			(0.1	)		0.2			1.0			(0.5	)		0.5
Gain on cash flow hedges		0.3			(0.1	)		0.2			5.3			(2.0	)		3.3
Amortization of unrecognized benefit costs (2)		0.4			(0.2	)		0.2			2.9			(1.1	)		1.8
Change in benefit obligation due to valuation (5)		(8.7	)		3.0			(5.7	)		(8.7	)		3.0			(5.7	)
Recognized cost due to settlement (6)		12.1			(4.4	)		7.7			12.1			(4.4	)		7.7
Total other comprehensive income	$	4.1		$	(1.7	)	$	2.4		$	11.6		$	(4.5	)	$	7.1
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement benefits. See Note 5 for additional information.
(3)  Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 for additional information.
(4)  Related to the estimated curtailment loss for the SERP.  See Note 5 for additional information.
(5)  Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.
(6)  Related to the settlement of the TECO Coal black lung obligation at the closing of the sale.  See Notes 15 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(37.7	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and transition obligations (2)		23.1			25.6
Net unrealized losses from cash flow hedges (3)		(3.0	)		(3.6	)
Total accumulated other comprehensive loss	$	(17.6	)	$	(12.2	)
(1)  Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sept. 30,							Nine months ended Sept. 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		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	1.0	$	(0.4	)	$	0.6
2015
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		1.0		(0.5	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		5.3		(2.0	)		3.3
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	5.3	$	(2.0	)	$	3.3

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.0	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.0	)	$	(3.6	)

(1) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2016

Variable Interest Entities

13. Variable Interest Entities

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

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 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.

Tampa Electric Company [Member]

Variable Interest Entities

13. Variable Interest Entities

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

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $19.1 million and $48.1 million under these PPAs for the three and nine months ended Sept. 30, 2016, respectively, and $10.7 million and $26.0 million for the three and nine months ended Sept. 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.

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Mergers and Acquisitions

9 Months Ended

Sep. 30, 2016

Mergers and Acquisitions

14. Mergers and Acquisitions

Merger with Emera Inc.

Description of Transaction

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, the Merger Sub Company merged 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, each issued and outstanding share of TECO Energy common stock was 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 $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion.

The 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.

Merger-Related Regulatory 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 then pending proceeding seeking the approval of the Merger by the NMPRC. On May 2, 2016, the Hearing Examiner held a hearing to consider the stipulation agreement. On June 8, 2016, the Hearing Examiner filed a Certificate of Stipulation, recommending approval by the NMPRC of the stipulation with respect to which all intervenors had either consented or filed a notice of non-opposition.  On June 22, 2016, the NMPRC approved the stipulation, and an order was entered on that same day.

As part of the stipulation agreement filed with the NMPRC, upon closing of the Merger, NMGC agreed, among other things, to:

• make commitments to charitable contributions and enterprises engaged in economic and business development in New Mexico of $0.8 million annually for three years,

• continue to provide an annual bill reduction credit of $4 million through June 30, 2018,

• evaluate and construct, at shareholder expense, an enlarged pipeline from its current system to the New Mexico/Mexican border at an estimated cost of approximately $5 million,

• establish, at shareholder expense, a matching fund of $10 million to extend its natural gas infrastructure to currently underserved or unserved areas in New Mexico, and

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

The company recorded the pretax costs of $30.4 million (or approximately $17.7 million after tax) related to these commitments in the three months ended Sept. 30, 2016. The bill credit of $8.0 million was recognized as a reduction in “Regulated gas revenues” and the remaining items recorded in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income for the three and nine months ended Sept. 30, 2016. As of Sept. 30, 2016, approximately $30 million remains to be paid and is included in “Other” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016.

Transaction-Related Costs

In addition to the Merger-related regulatory matters above, during the three and nine months ended Sept. 30, 2016, TECO Energy also incurred approximately $15.5 million and $87.0 million, respectively, of pretax transaction-related costs ($9.6 million and $68.1 million after tax, respectively), compared with approximately $15.4 million of pretax transaction-related costs during the three and nine months ended Sept. 30, 2015. These costs are presented in “Merger transaction-related costs” on the Consolidated Condensed Statements of Income.

For the three months ended Sept. 30, 2016, the $15.5 million of costs are primarily for accelerated vesting of outstanding stock-based compensation awards in accordance with the Merger Agreement and other employee-related costs. For the nine months ended Sept. 30, 2016, the costs also 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 recorded in the second quarter. During the third quarter of 2016, Emera contributed $22 million to TECO Energy primarily related to funding accelerated stock compensation payments. Transaction-related costs expensed and paid through Sept. 30, 2016 have been reflected in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 2016. As of Sept. 30, 2016, approximately $20 million remains to be paid. These remaining costs are expected to be paid primarily in the first quarter of 2017 and are included in “Accounts payable” in cash flows from operating activities in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sept. 30, 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 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 date 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 this dividend 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.

Tampa Electric Company [Member]

Mergers and Acquisitions

14. Mergers and Acquisitions

Merger with Emera Inc.

As disclosed in Note 1, TEC is a wholly owned subsidiary of TECO Energy. 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, the Merger Sub Company merged with and into TECO Energy with 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.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was 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 $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion).

The 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 and TEC’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.

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Discontinued Operations and Asset Impairments

9 Months Ended

Sep. 30, 2016

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations and Asset Impairments

15. Discontinued Operations and Asset Impairments

TECO Coal

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian (see description of guarantees in Note 8). The SPA contained customary representations, warranties and covenants (see Note 8 for description of a claim filed by Cambrian related to the SPA). The costs shown for 2016 in the table below reflects charges for personnel-related liabilities that remained with TECO Energy and legal costs associated with the claim related to the SPA.

Since the closing of the sale, TECO Energy has not 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 8). 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						Nine months ended
	Sept. 30,						Sept. 30,
(millions)	2016			2015			2016			2015
Revenues—TECO Coal	$	0.0		$	51.6		$	0.0		$	200.4
Loss from operations—TECO Coal		(0.1	)		(7.4	)		(0.2	)		(16.4	)
Loss on sale—TECO Coal		0.0			(10.0	)		0.0			(10.0	)
Loss on impairment—TECO Coal		0.0			0.0			0.0			(78.6	)
Loss from operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations—TECO Coal		(0.1	)		(17.4	)		(0.2	)		(105.0	)
Loss from discontinued operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations		(0.2	)		(17.8	)		(0.4	)		(105.5	)
Benefit for income taxes		0.2			6.1			0.3			38.3
Loss from discontinued operations, net	$	0.0		$	(11.7	)	$	(0.1	)	$	(67.2	)

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2016

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14 for further information.

Revenues

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 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.

Tampa Electric Company [Member]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 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 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, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.See Note 14 for further information.

Revenues

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $63.7 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates 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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, and $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

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Regulatory (Tables)

9 Months Ended

Sep. 30, 2016

Schedule of Regulatory Assets and Regulatory Liabilities

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

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.4	$	74.7
Cost-recovery clauses - deferred balances (2)		4.5		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		2.1		26.5
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.4		240.6
Deferred bond refinancing costs (5)		7.1		6.5
Debt basis adjustment (6)		14.9		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		14.8		12.1
Total regulatory assets		480.5		440.0
Less: Current portion		21.8		44.8
Long-term regulatory assets	$	458.7	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.2	$	7.9
Cost-recovery clauses (2)		111.5		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		670.6		679.9
Bill reduction credit (8)		8.0		0.3
Other		13.6		0.5
Total regulatory liabilities		867.0		800.6
Less: Current portion		148.2		84.8
Long-term regulatory liabilities	$	718.8	$	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 the 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 the 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.

(8) See Note 14 for information regarding NMGC’s stipulation agreement including a commitment to provide an annual bill reduction credit to customers. A minor portion of this balance is attributable to timing of bill reduction credits related to TECO Energy’s acquisition of NMGC in September 2014.

Tampa Electric Company [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

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

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	83.1	$	74.6
Cost-recovery clauses - deferred balances (2)		4.4		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		1.5		26.2
Environmental remediation (3)		54.8		54.0
Postretirement benefits (4)		296.5		238.3
Deferred bond refinancing costs (5)		5.9		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.1		10.7
Total regulatory assets		458.8		418.1
Less: Current portion		20.6		44.3
Long-term regulatory assets	$	438.2	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.3	$	5.7
Cost-recovery clauses (2)		107.8		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		554.8		570.0
Other		13.4		0.7
Total regulatory liabilities		737.4		686.7
Less: Current portion		140.4		83.2
Long-term regulatory liabilities	$	597.0	$	603.5

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

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

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

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

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

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

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Employee Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2016

Compensation And Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sept. 30,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.9		$	6.7		$	0.5		$	0.6
Interest cost		7.2			6.5			2.0			2.0
Expected return on assets		(11.5	)		(9.1	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		4.8			3.2			0.1			0.0
Regulatory asset		0.0			0.0			0.3			0.3
Curtailment cost		0.0			0.0			0.0			0.0
Settlement cost		0.0			0.0			0.0			0.0
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	2.0		$	2.0
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.9		$	17.6		$	1.4		$	1.7
Interest cost		23.6			22.6			6.4			6.1
Expected return on assets		(34.2	)		(32.4	)		(0.9	)		(0.8	)
Amortization of:
Prior service (benefit) cost		0.2			(0.2	)		(1.9	)		(1.8	)
Actuarial loss		11.7			11.4			0.1			0.0
Regulatory asset		0.0			0.0			0.8			0.8
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	$	17.1		$	19.0		$	5.9		$	6.0

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Short-Term Debt (Tables)

9 Months Ended

Sep. 30, 2016

Short-Term Debt Credit Facilities

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		150.0		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		11.5		1.4		125.0		23.0		1.7
Total	$	1,300.0	$	610.5	$	1.9	$	900.0	$	247.0	$	2.2
(1)     Borrowings outstanding are reported as notes payable.
(2)     This 5-year facility matures Dec. 17, 2018.
(3)     This 3-year facility matures Mar. 23, 2018.
(4)     TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5)     This 1-year facility matures Mar. 14, 2017.

Tampa Electric Company [Member]

Short-Term Debt Credit Facilities

Details of the credit facilities and related borrowings are presented in the following table:

Credit Facilities
	Sept. 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		49.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	49.0	$	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) This 3-year facility matures Mar. 23, 2018.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2016

Commitments And Contingencies Disclosure [Abstract]

Guarantees

A summary of the face amount or maximum theoretical obligation and the year of expiration under guarantees as of Sept. 30, 2016 is as follows:

(millions)												Maximum
										After (1)			Theoretical			Liabilities Recognized
Guarantees for the Benefit of:	2016		2017			2018-2020			2020			Obligation			at Sept. 30, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0		$	0.0		$	0.0		$	93.9		$	93.9		$	0.0
Letters of indemnity - coal mining permits (3)		0.0			84.5			0.0			0.0			84.5			0.0
	$	0.0		$	84.5		$	0.0		$	93.9		$	178.4		$	0.0
(1)    These 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 of 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 Sept. 30, 2016. See Note 10 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. 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.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Schedule of Segment Information

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

Segment Information (1)
(millions)	Tampa		Peoples		New Mexico				TECO										TECO
Three months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations			Energy
2016
Revenues - external	$	585.1	$	103.3	$	35.7			$	0.0		$	2.6			$	0.0		$	726.7
Sales to affiliates		0.8		0.4		0.0				0.0			0.1				(1.3	)		0.0
Total revenues		585.9		103.7		35.7				0.0			2.7				(1.3	)		726.7
Total interest charges		22.4		3.7		2.8				0.0			15.2				(0.2	)		43.9
Net income (loss) from continuing operations		94.1		6.5		(19.8	)	(5)		0.0			(11.4	)	(5)		0.0			69.4
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			0.0				0.0			0.0
Net income (loss)	$	94.1	$	6.5	$	(19.8	)		$	0.0		$	(11.4	)		$	0.0		$	69.4
2015
Revenues - external	$	559.4	$	88.1	$	43.7			$	0.0		$	2.6			$	0.0		$	693.8
Sales to affiliates		0.8		2.0		0.0				0.0			0.0				(2.8	)		0.0
Total revenues		560.2		90.1		43.7				0.0			2.6				(2.8	)		693.8
Total interest charges		24.1		3.7		3.2				0.0			15.4				(0.3	)		46.1
Net income (loss) from continuing operations		82.1		6.2		(2.8	)			0.0			(20.6	)			0.0			64.9
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(12.1	)		0.4				0.0			(11.7	)
Net income (loss)	$	82.1	$	6.2	$	(2.8	)		$	(12.1	)	$	(20.2	)		$	0.0		$	53.2

(millions)	Tampa		Peoples		New Mexico				TECO											TECO
Nine months ended Sept. 30,	Electric		Gas		Gas Co. (2)				Coal (1)			Other (2)				Eliminations				Energy
2016
Revenues - external	$	1,506.6	$	330.0	$	194.0			$	0.0		$	7.9			$	0.0			$	2,038.5
Sales to affiliates		3.0		6.8		0.0				0.0			0.1				(9.9	)			0.0
Total revenues		1,509.6		336.8		194.0				0.0			8.0				(9.9	)			2,038.5
Total interest charges		68.8		11.1		9.1				0.0			45.3				(0.7	)			133.6
Net income (loss) from continuing operations		212.9		26.7		(4.8	)	(5)		0.0			(86.2	)	(5)		0.0				148.6
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				0.0			(0.1	)			0.0				(0.1	)
Net income (loss)	$	212.9	$	26.7	$	(4.8	)		$	0.0		$	(86.3	)		$	0.0			$	148.5
2015
Revenues - external	$	1,540.8	$	302.0	$	216.7			$	0.0		$	7.9			$	0.0			$	2,067.4
Sales to affiliates		2.4		4.5		0.0				0.0			0.1				(7.0	)			0.0
Total revenues		1,543.2		306.5		216.7				0.0			8.0				(7.0	)			2,067.4
Total interest charges		71.2		10.8		9.8				0.0			49.6				(1.0	)			140.4
Net income (loss) from continuing operations		198.0		28.4		11.0				0.0			(47.2	)			0.0				190.2
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0				(69.6	)		2.4				0.0				(67.2	)
Net income (loss)	$	198.0	$	28.4	$	11.0			$	(69.6	)	$	(44.8	)		$	0.0			$	123.0
At Sept. 30, 2016
Total assets	$	7,244.9	$	1,161.5	$	1,230.4			$	0.0		$	2,031.8			$	(2,444.9	)	(4)	$	9,223.7
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 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 consolidated tax reclassifications.
(5)    Includes transaction costs associated with the Merger with Emera. See Note 14.

Tampa Electric Company [Member]

Schedule of Segment Information

(millions)	Tampa									Tampa Electric
Three months ended Sept. 30,	Electric		PGS		Eliminations					Company
2016
Revenues - external	$	585.9	$	103.2	$	0.0				$	689.1
Intracompany sales		0.0		0.5		(0.5	)				0.0
Total revenues		585.9		103.7		(0.5	)				689.1
Total interest charges		22.4		3.7		0.0					26.1
Net income	$	94.1	$	6.5	$	0.0				$	100.6
2015
Revenues - external	$	560.1	$	88.1	$	0.0				$	648.2
Intracompany sales		0.1		2.0		(2.1	)				0.0
Total revenues		560.2		90.1		(2.1	)				648.2
Total interest charges		24.1		3.7		0.0					27.8
Net income	$	82.1	$	6.2	$	0.0				$	88.3
Nine months ended Sept. 30,
2016
Revenues - external	$	1,508.9	$	330.0	$	0.0				$	1,838.9
Intracompany sales		0.7		6.8		(7.5	)				0.0
Total revenues		1,509.6		336.8		(7.5	)				1,838.9
Total interest charges		68.8		11.1		(0.1	)				79.8
Net income	$	212.9	$	26.7	$	0.0				$	239.6
2015
Revenues - external	$	1,542.9	$	302.0	$	0.0				$	1,844.9
Intracompany sales		0.3		4.5		(4.8	)				0.0
Total revenues		1,543.2		306.5		(4.8	)				1,844.9
Total interest charges		71.2		10.8		0.0					82.0
Net income	$	198.0	$	28.4	$	0.0				$	226.4
Total assets at Sept. 30, 2016	$	7,244.9	$	1,161.5	$	(452.6	)	(2	)	$	7,953.8
Total assets at Dec. 31, 2015 (1)	$	7,003.8	$	1,136.1	$	(431.3	)	(2	)	$	7,708.6

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

(2) Amounts relate to consolidated tax reclassifications.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Volumes Expected to Settle

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 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		14.2
2017		0.0		32.8
2018		0.0		5.3
Total		0.0		52.3

Tampa Electric Company [Member]

Derivative Volumes Expected to Settle

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

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		7.7
2017		0.0		23.2
2018		0.0		5.3
Total		0.0		36.2

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Schedule of Recurring Fair Value Measurements

Recurring Fair Value Measures
	As of Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	2.2	$	0.0	$	2.2
Liabilities
Natural gas derivatives	$	0.0	$	1.7	$	0.0	$	1.7
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

Tampa Electric Company [Member]

Schedule of Recurring Fair Value Measurements

Recurring Derivative Fair Value Measures
	As of Sept. 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	1.5	$	0.0	$	1.5
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2016

Other Comprehensive Income

TECO Energy reported the following OCI related to changes in the fair value of cash flow hedges, recognized cost due to curtailment, change in benefit obligation due to remeasurement and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Sept. 30,									Nine months ended Sept. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
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			1.0			(0.4	)		0.6
Gain on cash flow hedges		0.3			(0.1	)		0.2			1.0			(0.4	)		0.6
Amortization of unrecognized benefit costs and other (2)		0.8			(0.3	)		0.5			1.3			(0.5	)		0.8
Change in benefit obligation due to remeasurement (3)		(11.2	)		4.3			(6.9	)		(11.2	)		4.3			(6.9	)
Recognized cost due to curtailment (4)		0.0			0.0			0.0			0.1			0.0			0.1
Total other comprehensive loss	$	(10.1	)	$	3.9		$	(6.2	)	$	(8.8	)	$	3.4		$	(5.4	)
2015
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	4.3		$	(1.5	)	$	2.8
Reclassification from AOCI to net income (1)		0.3			(0.1	)		0.2			1.0			(0.5	)		0.5
Gain on cash flow hedges		0.3			(0.1	)		0.2			5.3			(2.0	)		3.3
Amortization of unrecognized benefit costs (2)		0.4			(0.2	)		0.2			2.9			(1.1	)		1.8
Change in benefit obligation due to valuation (5)		(8.7	)		3.0			(5.7	)		(8.7	)		3.0			(5.7	)
Recognized cost due to settlement (6)		12.1			(4.4	)		7.7			12.1			(4.4	)		7.7
Total other comprehensive income	$	4.1		$	(1.7	)	$	2.4		$	11.6		$	(4.5	)	$	7.1
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement benefits. See Note 5 for additional information.
(3)  Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 for additional information.
(4)  Related to the estimated curtailment loss for the SERP.  See Note 5 for additional information.
(5)  Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.
(6)  Related to the settlement of the TECO Coal black lung obligation at the closing of the sale.  See Notes 15 for additional information.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(37.7	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and transition obligations (2)		23.1			25.6
Net unrealized losses from cash flow hedges (3)		(3.0	)		(3.6	)
Total accumulated other comprehensive loss	$	(17.6	)	$	(12.2	)
(1)  Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
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		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		1.0		(0.4	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	1.0	$	(0.4	)	$	0.6
2015
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		1.0		(0.5	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		5.3		(2.0	)		3.3
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	5.3	$	(2.0	)	$	3.3

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.0	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.0	)	$	(3.6	)

(1) Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

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Discontinued Operations and Asset Impairments (Tables)

9 Months Ended

Sep. 30, 2016

TECO Coal and TECO Guatemala [Member]

Components of Discontinued Operations

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

Components of income from discontinued operations	Three months ended						Nine months ended
	Sept. 30,						Sept. 30,
(millions)	2016			2015			2016			2015
Revenues—TECO Coal	$	0.0		$	51.6		$	0.0		$	200.4
Loss from operations—TECO Coal		(0.1	)		(7.4	)		(0.2	)		(16.4	)
Loss on sale—TECO Coal		0.0			(10.0	)		0.0			(10.0	)
Loss on impairment—TECO Coal		0.0			0.0			0.0			(78.6	)
Loss from operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations—TECO Coal		(0.1	)		(17.4	)		(0.2	)		(105.0	)
Loss from discontinued operations—TECO Guatemala		(0.1	)		(0.4	)		(0.2	)		(0.5	)
Loss from discontinued operations		(0.2	)		(17.8	)		(0.4	)		(105.5	)
Benefit for income taxes		0.2			6.1			0.3			38.3
Loss from discontinued operations, net	$	0.0		$	(11.7	)	$	(0.1	)	$	(67.2	)

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Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	$ 71.3		$ 71.3		$ 81.1
Franchise fees and gross receipts taxes	32.6	$ 31.7	89.2	$ 88.3
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	63.7		63.7		$ 53.7
Franchise fees and gross receipts taxes	$ 32.6	$ 31.7	$ 89.2	$ 88.3

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New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions		9 Months Ended
	Jan. 01, 2016	Sep. 30, 2015	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative adjustment to retained earnings	$ 2.6
Excess tax benefit reclassified from operating activities to financing activities		$ 1.5
Long-term Debt, Less Amount Due Within One Year [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost			$ 27.7
Long-term Debt, Less Amount Due Within One Year [Member] | Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost			$ 18.1

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Regulatory assets:
Regulatory assets	$ 480.5	$ 440.0
Less: Current portion	21.8	44.8
Long-term regulatory assets	458.7	395.2
Regulatory liabilities:
Regulatory liabilities	867.0	800.6
Less: Current portion	148.2	84.8
Long-term regulatory liabilities	718.8	715.8
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	458.8	418.1
Less: Current portion	20.6	44.3
Long-term regulatory assets	438.2	373.8
Regulatory liabilities:
Regulatory liabilities	737.4	686.7
Less: Current portion	140.4	83.2
Long-term regulatory liabilities	597.0	603.5
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	83.4	74.7
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	83.1	74.6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	4.5	5.5
Cost-Recovery Clauses - Deferred Balances [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	4.4	5.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	2.1	26.5
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	1.5	26.2
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	54.8	54.0
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	54.8	54.0
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	296.4	240.6
Postretirement Benefit Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	296.5	238.3
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	7.1	6.5
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	5.9	6.5
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	14.9	17.5
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.5	2.6
Other [Member]
Regulatory assets:
Regulatory assets	14.8	12.1
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	10.1	10.7
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	7.2	7.9
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.3	5.7
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	111.5	55.9
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	107.8	54.2
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	670.6	679.9
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	554.8	570.0
Bill Reduction Credit [Member]
Regulatory liabilities:
Regulatory liabilities	8.0	0.3
Other [Member]
Regulatory liabilities:
Regulatory liabilities	13.6	0.5
Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$ 13.4	$ 0.7

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Taxes [Line Items]
Effective tax rate	19.86%	39.12%	34.19%	39.10%
Statutory tax rate			35.00%
Effective tax rate decrease due to federal research and development credits	19.26%	19.26%
Income tax examination period			1 year
Uncertain tax positions	$ 7.7		$ 7.7		$ 0.0
Taxes accrued	$ 65.0		$ 65.0		13.2
Tampa Electric Company [Member]
Income Taxes [Line Items]
Effective tax rate	32.53%	37.73%	34.59%	37.15%
Effective tax rate decrease due to federal research and development credits	5.20%	5.20%
Statutes of limitations			3 years
Income tax examination period			1 year
Uncertain tax positions	$ 6.5		$ 6.5		0.0
Taxes accrued	74.5		74.5		$ 13.2
Tampa Electric Company [Member] | Emera Inc. [Member]
Income Taxes [Line Items]
Taxes accrued	$ 14.2		$ 14.2
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations			3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations			4 years

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.9		$ 6.7	$ 13.9	$ 17.6
Interest cost	7.2		6.5	23.6	22.6
Expected return on assets	(11.5)		(9.1)	(34.2)	(32.4)
Amortization of:
Prior service (benefit) cost	0.0		(0.1)	0.2	(0.2)
Actuarial loss	4.8		3.2	11.7	11.4
Regulatory asset	0.0		0.0	0.0	0.0
Curtailment cost	0.0	$ 1.3	0.0	1.3	0.0
Settlement cost	0.0		0.0	0.6	0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	5.4		7.2	17.1	19.0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.5		0.6	1.4	1.7
Interest cost	2.0		2.0	6.4	6.1
Expected return on assets	(0.3)		(0.3)	(0.9)	(0.8)
Amortization of:
Prior service (benefit) cost	(0.6)		(0.6)	(1.9)	(1.8)
Actuarial loss	0.1		0.0	0.1	0.0
Regulatory asset	0.3		0.3	0.8	0.8
Curtailment cost	0.0		0.0	0.0	0.0
Settlement cost	0.0		0.0	0.0	0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 2.0		$ 2.0	$ 5.9	$ 6.0

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Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions			3 Months Ended				9 Months Ended
	Jul. 02, 2016	Jan. 01, 2016	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Reclassification of AOCI to net income as part of periodic benefit expense				$ 0.8		$ 0.2	$ 1.8	$ 2.4
Reclassification of regulatory assets to net income as part of periodic benefit expense				3.8		2.6	9.1	7.8
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.00%	7.00%
Reclassification of regulatory assets to net income as part of periodic benefit expense				2.8		2.3	7.6	7.0
Scenario Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Settlement charge related to the SERP			$ 8.0
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.00%	7.00%
Discount rate	3.72%	4.685%
Increase in net periodic benefit expense				0.6			0.6
Increase in liability for pension benefits				61.7			61.7
Increase in regulatory asset				54.0			54.0
Decrease in accumulated other comprehensive income				7.7			7.7
Employer contributions							37.4	55.0
Curtailment cost				0.0	$ 1.3	0.0	1.3	0.0
Settlement charge related to the SERP				0.0		0.0	0.6	0.0
Net pension expense				5.4		7.2	17.1	19.0
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.72%	4.685%
Increase in net periodic benefit expense				0.8			0.8
Increase in liability for pension benefits				53.3			53.3
Increase in regulatory asset				53.3			53.3
Employer contributions							30.9	43.9
Net pension expense				3.5		3.3	9.6	10.1
Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.667%
Other Postretirement Benefits, NMGC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.687%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%
Increase in net periodic benefit expense				0.0			0.0
Increase in liability for pension benefits				17.6			17.6
Increase in regulatory asset				14.1			14.1
Decrease in accumulated other comprehensive income				3.5			3.5
Employer contributions							2.7	2.7
Curtailment cost				0.0		0.0	0.0	0.0
Settlement charge related to the SERP				0.0		0.0	0.0	0.0
Net pension expense				2.0		2.0	5.9	6.0
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%	4.667%
Increase in net periodic benefit expense				0.3			0.3
Increase in liability for pension benefits				12.4			12.4
Increase in regulatory asset				12.4			12.4
Net pension expense				$ 1.7		$ 1.4	$ 4.7	$ 4.3

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Short-Term Debt - Credit Facilities (Detail) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Credit Facilities	$ 1,300,000,000	$ 900,000,000
Borrowings Outstanding	610,500,000	247,000,000
Letters of Credit Outstanding	1,900,000	2,200,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475,000,000	475,000,000
Borrowings Outstanding	49,000,000	61,000,000
Letters of Credit Outstanding	500,000	500,000
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000	325,000,000
Borrowings Outstanding	0	0
Letters of Credit Outstanding	500,000	500,000
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000	150,000,000
Borrowings Outstanding	49,000,000	61,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000	300,000,000
Borrowings Outstanding	150,000,000	163,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] | 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	400,000,000	0
Borrowings Outstanding	400,000,000	0
Letters of Credit Outstanding	0	0
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125,000,000	125,000,000
Borrowings Outstanding	11,500,000	23,000,000
Letters of Credit Outstanding	$ 1,400,000	$ 1,700,000

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Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
TECO Energy [Member] | 1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 14, 2017	Mar. 14, 2017
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

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Short-Term Debt - Additional Information (Detail) - USD ($)		9 Months Ended
	Mar. 14, 2016	Sep. 30, 2016	Dec. 31, 2015
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity		$ 1,300,000,000	$ 900,000,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.32%	0.89%
Line of Credit Facility maximum borrowing capacity		$ 475,000,000	$ 475,000,000
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
TECO Finance [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
Interest rate description		provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the one-month London interbank deposit rate plus 1.00%.
TECO Finance [Member] | 1-year Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity	$ 400,000,000
Credit facility maturity date	Mar. 14, 2017
TECO Finance [Member] | Federal Funds Rate [Member]
Line Of Credit Facility [Line Items]
Basis spread on referenced interest rate	0.50%
TECO Finance [Member] | London Interbank Deposit Rate [Member]
Line Of Credit Facility [Line Items]
Basis spread on referenced interest rate	1.00%
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.71%	1.29%
Minimum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Maximum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.30%

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions				9 Months Ended
	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, carrying amount				$ 3,490.3		$ 3,822.5
Estimated fair value				3,911.2		4,061.6
Purchase in lieu of redemption				333.3	$ 274.5
HCIDA Pollution Control Revenue Refunding Bonds [Member] | Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption				232.6
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount				2,162.6		2,245.0
Estimated fair value				2,505.6		$ 2,433.3
Purchase in lieu of redemption				83.3	$ 83.3
Tampa Electric Company [Member] | HCIDA Pollution Control Revenue Refunding Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, repurchase date	Mar. 15, 2016	Mar. 15, 2012	Mar. 19, 2008
Purchase in lieu of redemption			$ 86.0
Stated interest rate	2.00%	1.875%	5.00%
Level 1 [Member]
Debt Instrument [Line Items]
Fair value of debt securities				58.3
Level 1 [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Fair value of debt securities				$ 58.3

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Commitments and Contingencies - Additional Information (Detail) $ in Millions				9 Months Ended
	Apr. 05, 2016 USD ($)	Dec. 19, 2013 USD ($)	Feb. 08, 2011 Customer InsuranceCarrier Lawsuit	Sep. 30, 2016 USD ($) Claims	Sep. 30, 2015 USD ($)	Mar. 31, 2011 Customer
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers | Customer			28,700			32,000
Number of class actions settled | Claims				2
Number of insurance carriers | InsuranceCarrier			18
Number of lawsuits for insurance carriers | Lawsuit			2
Dismissed annulment of the award	$ 21.1
Letters of indemnity coal mining permits					$ 93.8
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites				$ 33.9
PGS [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites				$ 33.9
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement amount		$ 7.5
Damages awarded		$ 21.1
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member] | U.S. prime rate plus [Member]
Long Term Commitments [Line Items]
Litigation settlement interest		2.00%

XML

Commitments and Contingencies - Guarantees (Detail)	Sep. 30, 2016 USD ($)
Guarantee Obligations [Line Items]
Year of expiration 2016	$ 0
Year of expiration 2017	84,500,000
Year of expiration 2018-2020	0
Year of expiration After 2020	93,900,000
Maximum Theoretical Obligation	178,400,000
Liabilities Recognized at Sept. 30, 2016	0
Fuel Sales and Transportation [Member]
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017	0
Year of expiration 2018-2020	0
Year of expiration After 2020	93,900,000
Maximum Theoretical Obligation	93,900,000
Liabilities Recognized at Sept. 30, 2016	0
Letters of Indemnity - Coal Mining Permits
Guarantee Obligations [Line Items]
Year of expiration 2016	0
Year of expiration 2017	84,500,000
Year of expiration 2018-2020	0
Year of expiration After 2020	0
Maximum Theoretical Obligation	84,500,000
Liabilities Recognized at Sept. 30, 2016	$ 0

XML

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total revenues	$ 726.7	$ 693.8	$ 2,038.5	$ 2,067.4
Total interest charges	43.9	46.1	133.6	140.4
Net income (loss) from continuing operations	69.4	64.9	148.6	190.2
Income (loss) from discontinued operations, net	0.0	(11.7)	(0.1)	(67.2)
Net income	69.4	53.2	148.5	123.0
Total assets	9,223.7		9,223.7		$ 8,933.5
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	689.1	648.2	1,838.9	1,844.9
Total interest charges	26.1	27.8	79.8	82.0
Net income	100.6	88.3	239.6	226.4
Total assets	7,953.8		7,953.8		7,708.6
Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0	0.0	0.0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(1.3)	(2.8)	(9.9)	(7.0)
Total interest charges	(0.2)	(0.3)	(0.7)	(1.0)
Net income (loss) from continuing operations	0.0	0.0	0.0	0.0
Income (loss) from discontinued operations, net	0.0	0.0	0.0	0.0
Net income	0.0	0.0	0.0	0.0
Total assets	(2,444.9)		(2,444.9)		(2,381.2)
Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	(0.5)	(2.1)	(7.5)	(4.8)
Total interest charges	0.0	0.0	(0.1)	0.0
Net income	0.0	0.0	0.0	0.0
Total assets	(452.6)		(452.6)		(431.3)
Eliminations [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(0.5)	(2.1)	(7.5)	(4.8)
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	726.7	693.8	2,038.5	2,067.4
Revenues - External [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	689.1	648.2	1,838.9	1,844.9
Revenues - External [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0	0.0	0.0
Revenues - External [Member] | Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0	0.0	0.0
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0	0.0	0.0
Sales to Affiliates [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(1.3)	(2.8)	(9.9)	(7.0)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.2	1,509.6	1,543.2
Total interest charges	22.4	24.1	68.8	71.2
Net income (loss) from continuing operations	94.1	82.1	212.9	198.0
Income (loss) from discontinued operations, net	0.0	0.0	0.0	0.0
Net income	94.1	82.1	212.9	198.0
Total assets	7,244.9		7,244.9		7,003.8
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.2	1,509.6	1,543.2
Total interest charges	22.4	24.1	68.8	71.2
Net income	94.1	82.1	212.9	198.0
Total assets	7,244.9		7,244.9		7,003.8
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.1	0.7	0.3
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	585.1	559.4	1,506.6	1,540.8
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	585.9	560.1	1,508.9	1,542.9
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.8	0.8	3.0	2.4
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	103.7	90.1	336.8	306.5
Total interest charges	3.7	3.7	11.1	10.8
Net income (loss) from continuing operations	6.5	6.2	26.7	28.4
Income (loss) from discontinued operations, net	0.0	0.0	0.0	0.0
Net income	6.5	6.2	26.7	28.4
Total assets	1,161.5		1,161.5		1,136.1
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	103.7	90.1	336.8	306.5
Total interest charges	3.7	3.7	11.1	10.8
Net income	6.5	6.2	26.7	28.4
Total assets	1,161.5		1,161.5		1,136.1
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.5	2.0	6.8	4.5
PGS [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	103.3	88.1	330.0	302.0
PGS [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	103.2	88.1	330.0	302.0
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.4	2.0	6.8	4.5
New Mexico Gas Co. [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	35.7	43.7	194.0	216.7
Total interest charges	2.8	3.2	9.1	9.8
Net income (loss) from continuing operations	(19.8)	(2.8)	(4.8)	11.0
Income (loss) from discontinued operations, net	0.0	0.0	0.0	0.0
Net income	(19.8)	(2.8)	(4.8)	11.0
Total assets	1,230.4		1,230.4		1,229.7
New Mexico Gas Co. [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	35.7	43.7	194.0	216.7
New Mexico Gas Co. [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0	0.0	0.0
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0	0.0	0.0
Total interest charges	0.0	0.0	0.0	0.0
Net income (loss) from continuing operations	0.0	0.0	0.0	0.0
Income (loss) from discontinued operations, net	0.0	(12.1)	0.0	(69.6)
Net income	0.0	(12.1)	0.0	(69.6)
Total assets	0.0		0.0		0.0
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0.0	0.0	0.0	0.0
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.0	0.0	0.0	0.0
Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.7	2.6	8.0	8.0
Total interest charges	15.2	15.4	45.3	49.6
Net income (loss) from continuing operations	(11.4)	(20.6)	(86.2)	(47.2)
Income (loss) from discontinued operations, net	0.0	0.4	(0.1)	2.4
Net income	(11.4)	(20.2)	(86.3)	(44.8)
Total assets	2,031.8		2,031.8		$ 1,945.1
Other [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.6	2.6	7.9	7.9
Other [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	$ 0.1	$ 0.0	$ 0.1	$ 0.1

XML

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative assets	$ 2,200,000	$ 200,000
Derivative liabilities	1,700,000	26,200,000
Cash collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	500,000
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	1,500,000	0
Derivative liabilities	1,500,000	26,200,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	$ (100,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2018
Natural Gas Contracts [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2018

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Sep. 30, 2016 MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2016 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	52,300,000
Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,200,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,200,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2016 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,700,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,800,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	23,200,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,300,000
Financial [Member] | Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,300,000

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	$ 2.2	$ 0.2
Natural gas derivative liabilities	1.7	26.2
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5	0.0
Natural gas derivative liabilities	1.5	26.2
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0	0.0
Natural gas derivative liabilities	0.0	0.0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0	0.0
Natural gas derivative liabilities	0.0	0.0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	2.2	0.2
Natural gas derivative liabilities	1.7	26.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5
Natural gas derivative liabilities	1.5	26.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0	0.0
Natural gas derivative liabilities	0.0	0.0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0
Natural gas derivative liabilities	0.0	0.0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	2.2	0.2
Natural gas derivative liabilities	1.7	26.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	1.5
Natural gas derivative liabilities	1.5	26.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0	0.0
Natural gas derivative liabilities	0.0	0.0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.0
Natural gas derivative liabilities	$ 0.0	$ 0.0

XML

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 2.2	$ 0.2
Derivative liabilities	1.7	26.2
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	1.5	0.0
Derivative liabilities	1.5	26.2
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0.0	0.0
Derivative liabilities	0.0	0.0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0.0	0.0
Derivative liabilities	$ 0.0	$ 0.0

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015		Dec. 31, 2015
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income (loss), Gross		$ (10.1)		$ 4.1		$ (8.8)		$ 11.6
Amortization of unrecognized benefit costs and other, Gross		0.8	[1]	0.4	[2]	1.3	[1]	2.9	[2]
Change in benefit obligation due to remeasurement, Gross	[3]	(11.2)				(11.2)
Recognized cost due to curtailment , Gross	[2]	0.0				0.1
Change in benefit obligation due to valuation, Gross	[4]			(8.7)				(8.7)
Recognized cost due to settlement, Gross	[5]			12.1				12.1
Total other comprehensive income (loss), Tax		3.9		(1.7)		3.4		(4.5)
Amortization of unrecognized benefit costs and other, Tax	[1]	(0.3)		(0.2)		(0.5)		(1.1)
Change in benefit obligation due to remeasurement, Tax	[3]	4.3				4.3
Recognized cost due to curtailment , Tax	[2]	0.0				0.0
Change in benefit obligation due to valuation, Tax	[4]			3.0				3.0
Recognized cost due to settlement, Tax	[5]			(4.4)				(4.4)
Other comprehensive income (loss), net of tax		(6.2)		2.4		(5.4)		7.1
Amortization of unrecognized benefit costs and other, Net	[1]	0.5		0.2		0.8		1.8
Change in benefit obligation due to remeasurement, Net	[3]	(6.9)				(6.9)
Recognized cost due to curtailment , Net		0.0	[2]	0.0		0.1	[2]	0.0
Change in benefit obligation due to valuation, Net	[4]			(5.7)				(5.7)
Recognized cost due to settlement, Net		0.0		7.7	[5]	0.0		7.7	[5]
Unamortized pension loss and prior service credit	[6]	(37.7)				(37.7)				$ (34.2)
Unamortized other benefit gains, prior service costs and transition obligations	[7]	23.1				23.1				25.6
Net unrealized losses from cash flow hedges	[8]	(3.0)				(3.0)				(3.6)
Total accumulated other comprehensive loss		(17.6)				(17.6)				(12.2)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income (loss), Gross		0.3		0.3		1.0		5.3
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2.0)
Other comprehensive income (loss), net of tax		0.2		0.2		0.6		3.3
Net unrealized losses from cash flow hedges	[8]	(3.0)				(3.0)				(3.6)
Total accumulated other comprehensive loss		(3.0)				(3.0)				$ (3.6)
Accumulated Gain on Cash Flow Hedges [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0.0		0.0		0.0		4.3
Reclassification from AOCI to net income, Gross	[9]	0.3		0.3		1.0		1.0
Total other comprehensive income (loss), Gross		0.3		0.3		1.0		5.3
Unrealized gain on cash flow hedges, Tax		0.0		0.0		0.0		(1.5)
Reclassification from AOCI to net income, Tax	[9]	(0.1)		(0.1)		(0.4)		(0.5)
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2.0)
Unrealized gain on cash flow hedges, Net		0.0		0.0		0.0		2.8
Reclassification from AOCI to net income, Net	[9]	0.2		0.2		0.6		0.5
Other comprehensive income (loss), net of tax		0.2		0.2		0.6		3.3
Accumulated Gain on Cash Flow Hedges [Member] | Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0.0		0.0		0.0		4.3
Reclassification from AOCI to net income, Gross		0.3		0.3		1.0		1.0
Total other comprehensive income (loss), Gross		0.3		0.3		1.0		5.3
Unrealized gain on cash flow hedges, Tax		0.0		0.0		0.0		(1.5)
Reclassification from AOCI to net income, Tax		(0.1)		(0.1)		(0.4)		(0.5)
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(0.4)		(2.0)
Unrealized gain on cash flow hedges, Net		0.0		0.0		0.0		2.8
Reclassification from AOCI to net income, Net		0.2		0.2		0.6		0.5
Other comprehensive income (loss), net of tax		$ 0.2		$ 0.2		$ 0.6		$ 3.3

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

[2] Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.

[3] Related to remeasurement of employee postretirement benefit plans on the Merger closing date. See Note 5 for additional information.

[4] Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.

[5] Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 15 for additional information.

[6] Net of tax benefit of $23.5 million and $21.5 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

[7] Net of tax expense of $14.3 million and $16.1 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

[8] Net of tax benefit of $1.9 million and $2.3 million as of Sept. 30, 2016 and Dec. 31, 2015, respectively.

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

XML

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 1.9	$ 2.3
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	1.9	2.3
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	23.5	21.5
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	$ 14.3	$ 16.1

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Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 38.3	$ 23.8	$ 80.5	$ 60.5
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	38.3	23.8	80.5	60.5
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	19.1	10.7	48.1	26.0
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 19.1	$ 10.7	$ 48.1	$ 26.0
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			117
Minimum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			250
Maximum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			250

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Mergers and Acquisitions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions				3 Months Ended		9 Months Ended
	Jul. 12, 2016	Jul. 02, 2016	Jun. 22, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jul. 01, 2016
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding								$ 27.55
Aggregate purchase price		$ 10,700.0
Senior secured notes								$ 4,200.0
Other expenses yet to be paid				$ 30.0		$ 30.0
Business combination transaction related costs				15.5	$ 15.4	87.0	$ 15.4
Business combination transaction related costs, after tax				9.6		68.1
Investment banking, legal and other consultant costs						27.7
Change-in-control and other compensation payments						42.4
Non-cash SERP curtailment charge						1.3
Contributions from parent				22.0
Accelerated vesting of outstanding stock-based compensation awards				15.5
Business combination transaction related costs payable				20.0		20.0
Dividends payable, declared date			Jun. 22, 2016
Declared a special pro-rated dividend			$ 0.002527
Dividends paid	$ 26.8
Tampa Electric Company [Member] | Emera Inc. [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding								$ 27.55
Aggregate purchase price		$ 10,700.0
Senior secured notes								$ 4,200.0
Senior secured notes								2,300.0
Regulated Gas Revenues [Member]
Business Acquisition [Line Items]
Recognition of bill credit				8.0		8.0
Pipeline [Member]
Business Acquisition [Line Items]
Other commitment								5.0
Natural Gas Infrastructure [Member]
Business Acquisition [Line Items]
Other commitment								10.0
Annual Commitment to Charitable Contributions and Certain Enterprises [Member]
Business Acquisition [Line Items]
Other commitment								0.8
Period of commitment		3 years
Annual Bill Reduction Credit [Member]
Business Acquisition [Line Items]
Other commitment								4.0
Economic Development Projects [Member]
Business Acquisition [Line Items]
Other commitment								$ 5.0
Period of commitment		5 years
Commitments to NMPRC, Pretax [Member]
Business Acquisition [Line Items]
Other commitment				30.4		30.4
Commitments to NMPRC, After Tax [Member]
Business Acquisition [Line Items]
Other commitment				$ 17.7		$ 17.7

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

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Discontinued Operations and Asset Impairments - Components of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from discontinued operations	$ (0.2)	$ (17.8)	$ (0.4)	$ (105.5)
Benefit for income taxes	0.2	6.1	0.3	38.3
Loss from discontinued operations, net	0.0	(11.7)	(0.1)	(67.2)
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	0.0	51.6	0.0	200.4
Loss from operations	(0.1)	(7.4)	(0.2)	(16.4)
Loss on sale	0.0	(10.0)	0.0	(10.0)
Loss on impairment	0.0	0.0	0.0	(78.6)
Loss from discontinued operations	(0.1)	(17.4)	(0.2)	(105.0)
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from operations	(0.1)	(0.4)	(0.2)	(0.5)
Loss from discontinued operations	$ (0.1)	$ (0.4)	$ (0.2)	$ (0.5)