te-10q_20160930.htm

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.

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.

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.

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

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
NO_x		nitrogen oxide
NPNS		normal purchase normal sale
NYMEX		New York Mercantile Exchange
O&M expenses		operations and maintenance expenses
OCI		other comprehensive income
OPC		Office of Public Counsel
OPEB		other postretirement benefits
OTC		over-the-counter
Parent		TECO Energy (the holding company, excluding subsidiaries)
PBGC		Pension Benefit Guarantee Corporation
PBO		postretirement benefit obligation
PCI		pulverized coal injection
PGA		purchased gas adjustment
PGAC		purchased gas adjustment clause
PGS		Peoples Gas System, the gas division of Tampa Electric Company
PPA		power purchase agreement
PPSA		Power Plant Siting Act
PRP		potentially responsible party
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.

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.

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.

	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.

	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.

	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.

	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.

													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.

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:

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.

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.

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.

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

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.

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:

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.

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.

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.

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’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.

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

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.

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.

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.

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.

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%.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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

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:

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.

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 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

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

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.

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.

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.

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.

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:

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.

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.

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.

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.

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.

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	)

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.

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.

	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.

	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.

	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.

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

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.

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.

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.

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

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.

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.

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.

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.

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.

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

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 being utilized.

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.

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%.

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.

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

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).

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.

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.

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.

(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

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

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

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.

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:

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.

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

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

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.

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

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.

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.

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.

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.

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.

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).

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.

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

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:

(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.

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:

(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

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.

NMGC’s regulated operating statistics for the three and nine months ended Sept. 30, 2016 and 2015 are 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.

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.

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 $44.8 million 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.

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).

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).

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.

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.

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 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.

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.

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

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.

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

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.

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.

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:

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.

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.

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.

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.

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.

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

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

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.

							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


			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%

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

Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	☒	Smaller reporting company	☐

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

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

	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

	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

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

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

	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)