te-10q_20160630.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 x NO ¨

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

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

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 x

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

As of July 29, 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 Inc. As of July 29, 2016, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

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

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

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

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

Assets	June 30,			Dec. 31,
(millions)	2016			2015
Current assets
Cash and cash equivalents	$	29.2		$	23.8
Receivables, less allowance for uncollectibles of $2.0 and $2.1 at June 30, 2016 and Dec. 31, 2015, respectively		256.5			280.7
Inventories, at average cost
Fuel	106.8			113.4
Materials and supplies		78.8			76.8
Regulatory assets		18.4			44.8
Prepayments and other current assets		29.4			30.8
Total current assets		519.1			570.3

Property, plant and equipment
Utility plant in service
Electric		7,419.5			7,270.3
Gas		2,191.9			2,113.8
Construction work in progress		855.9			794.7
Other property		16.4			15.9
Property, plant and equipment, at original costs		10,483.7			10,194.7
Accumulated depreciation		(2,810.1	)		(2,712.9	)
Total property, plant and equipment, net		7,673.6			7,481.8

Other assets
Regulatory assets		392.9			395.2
Goodwill		408.4			408.4
Deferred charges and other assets		85.7			77.8
Total other assets		887.0			881.4
Total assets	$	9,079.7		$	8,933.5

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

Liabilities and Capital	June 30,			Dec. 31,
(millions)	2016			2015
Current liabilities
Long-term debt due within one year	$	0.0		$	333.3
Notes payable		615.0			247.0
Accounts payable		295.1			255.4
Customer deposits		168.5			182.1
Regulatory liabilities		130.1			84.8
Derivative liabilities		1.1			24.1
Interest accrued		34.3			36.2
Taxes accrued		46.0			13.2
Dividends declared		26.8			0.0
Other		21.8			22.6
Total current liabilities		1,338.7			1,198.7

Other liabilities
Deferred income taxes		635.1			570.7
Investment tax credits		10.3			10.5
Regulatory liabilities		723.8			715.8
Deferred credits and other liabilities		371.5			389.6
Long-term debt, less amount due within one year		3,490.0			3,489.2
Total other liabilities		5,230.7			5,175.8

Commitments and contingencies (see Note 10)

Capital
Common equity (400.0 million shares authorized; par value $1; 235.5 million and 235.3 million shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively)		235.5			235.3
Additional paid in capital		1,898.5			1,894.5
Retained earnings		387.7			441.4
Accumulated other comprehensive loss		(11.4	)		(12.2	)
Total capital		2,510.3			2,559.0
Total liabilities and capital	$	9,079.7		$	8,933.5

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

		Three months ended June 30,
(millions, except per share amounts)		2016			2015
Revenues
Regulated electric		$	498.0		$	531.7
Regulated gas			151.4			146.5
Unregulated			2.9			2.4
Total revenues			652.3			680.6
Expenses
Regulated operations and maintenance
Fuel			137.4			171.8
Purchased power			27.8			19.6
Cost of natural gas sold			50.8			49.1
Other			154.6			155.4
Operations and maintenance other expense			1.4			1.1
Merger transaction-related costs			71.4			0.0
Depreciation and amortization			90.2			87.0
Taxes, other than income			52.0			53.3
Total expenses			585.6			537.3
Income from operations			66.7			143.3
Other income
Allowance for other funds used during construction			5.9			3.7
Other income, net			1.0			1.4
Total other income			6.9			5.1
Interest charges
Interest expense			46.7			48.2
Allowance for borrowed funds used during construction			(2.9	)		(1.8	)
Total interest charges			43.8			46.4
Income from continuing operations before provision for income taxes			29.8			102.0
Provision for income taxes			24.3			40.5
Net income from continuing operations			5.5			61.5
Discontinued operations
Loss from discontinued operations			(0.4	)		(78.1	)
Benefit for income taxes			(0.2	)		(28.4	)
Loss from discontinued operations, net			(0.2	)		(49.7	)
Net income		$	5.3		$	11.8
Average common shares outstanding	– Basic		234.3			233.0
	– Diluted		235.5			233.6
Earnings per share from continuing operations	– Basic	$	0.03		$	0.26
	– Diluted	$	0.03		$	0.26
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.21	)
	– Diluted	$	0.00		$	(0.21	)
Earnings per share	– Basic	$	0.03		$	0.05
	– Diluted	$	0.03		$	0.05
Dividends paid per common share outstanding		$	0.230		$	0.225

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

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

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

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

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

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 intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of June 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended June 30, 2016 and 2015. The results of operations for the three and six months ended June 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, Merger Sub merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

As of June 30, 2016 and Dec. 31, 2015, unbilled revenues of $73.2 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 prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $28.6 million and $56.5 million for the three and six months ended June 30, 2016, respectively, compared to $29.3 million and $56.6 million for the three and six months ended June 30, 2015, respectively.

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

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of June 30, 2016 and Dec. 31, 2015, the company classified $25.2 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.

In March 2016, the FASB issued guidance regarding employee share-based payment accounting. The guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liability, and presentation on the statement of cash flows. This guidance will be

required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact and was implemented as follows:

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

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

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

modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on future derivative contract novations, if any.

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

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

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

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)	June 30, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	80.8	$	74.7
Cost-recovery clauses - deferred balances⁽²⁾		2.5		5.5
Cost-recovery clauses - offsets to derivative liabilities ⁽²⁾		1.1		26.5
Environmental remediation ⁽³⁾		54.6		54.0
Postretirement benefits ⁽⁴⁾		236.2		240.6
Deferred bond refinancing costs ⁽⁵⁾		7.4		6.5
Debt basis adjustment ⁽⁶⁾		15.8		17.5
Competitive rate adjustment ⁽²⁾		2.5		2.6
Other		10.4		12.1
Total regulatory assets		411.3		440.0
Less: Current portion		18.4		44.8
Long-term regulatory assets	$	392.9	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.3	$	7.9
Cost-recovery clauses⁽²⁾		98.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal ⁽⁷⁾		678.6		679.9
Other		13.9		0.8
Total regulatory liabilities		853.9		800.6
Less: Current portion		130.1		84.8
Long-term regulatory liabilities	$	723.8	$	715.8

The effective tax rate increased to 43.10% for the six months ended June 30, 2016 from 39.09% for the same period in 2015 primarily due to non-deductible Merger transaction costs offset by the tax benefit related to long-term incentive compensation (see Notes 2 and 16 for further description).

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations

remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, the company is only eligible to participate in the CAP through its short tax year ending June 30, 2016. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward. TECO Energy does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

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 June 30,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.6		$	6.4		$	0.4		$	0.5
Interest cost		8.3			8.7			2.2			2.1
Expected return on assets		(11.4	)		(12.5	)		(0.3	)		(0.2	)
Amortization of:
Prior service (benefit) cost		0.2			0.0			(0.7	)		(0.6	)
Actuarial loss		3.5			4.8			0.0			0.0
Regulatory asset		0.0			0.0			0.3			0.2
Curtailment cost		1.3			0.0			0.0			0.0
Settlement cost		0.6			0.0			0.0			0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	7.1		$	7.4		$	1.9		$	2.0
Six months ended June 30,
Components of net periodic benefit expense
Service cost	$	9.0		$	10.9		$	0.9		$	1.1
Interest cost		16.4			16.1			4.4			4.1
Expected return on assets		(22.7	)		(23.3	)		(0.6	)		(0.5	)
Amortization of:
Prior service (benefit) cost		0.2			(0.1	)		(1.3	)		(1.2	)
Actuarial loss		6.9			8.2			0.0			0.0
Regulatory asset		0.0			0.0			0.5			0.5
Curtailment cost		1.3			0.0			0.0			0.0
Settlement cost		0.6			0.0			0.0			0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	11.7		$	11.8		$	3.9		$	4.0

For the 2016 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of $15.6 million and $24.5 million to its pension plan for the six months ended June 30, 2016 and 2015, respectively.

For the three and six months ended June 30, 2016, TECO Energy and its subsidiaries reclassified $0.2 million and $1.0 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $1.4 million and $2.2 million for the three and six months ended June 30, 2015, respectively. In addition, during the three and six months ended June, 2016, the regulated companies reclassified $3.1 million and $5.3 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $3.0 million and $5.2 million for the three and six months ended June 30, 2015, respectively.

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

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

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

Credit Facilities
	June 30, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts receivable facility ⁽³⁾		150.0		123.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility ⁽²⁾⁽⁴⁾		300.0		90.0		0.0		300.0		163.0		0.0
1-year term facility ⁽⁴⁾⁽⁵⁾		400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility⁽²⁾		125.0		2.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	615.0	$	2.2	$	900.0	$	247.0	$	2.2

(1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Dec. 17, 2018.
(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.
(4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5) This 1-year facility matures Mar. 14, 2017.

At June 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 June 30, 2016 and Dec. 31, 2015 was 1.33% 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 June 30, 2016, total long-term debt had a carrying amount of $3,490.0 million and an estimated fair market value of $3,845.8 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.8 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements (see Note 13 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 June 30, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

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

Other Comprehensive Income
	Three months ended June 30,									Six months ended June 30,
(millions)	Gross			Tax			Net			Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0		$	0.0		$	0.0		$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income ⁽¹⁾		0.3			(0.1	)		0.2			0.7		(0.3	)		0.4
Gain on cash flow hedges		0.3			(0.1	)		0.2			0.7		(0.3	)		0.4
Amortization of unrecognized benefit costs and other ⁽²⁾		(0.3	)		0.1			(0.2	)		0.5		(0.2	)		0.3
Recognized cost due to curtailment ⁽³⁾		0.1			0.0			0.1			0.1		0.0			0.1
Total other comprehensive income	$	0.1		$	0.0		$	0.1		$	1.3	$	(0.5	)	$	0.8
2015
Unrealized gain on cash flow hedges	$	4.0		$	(1.4	)	$	2.6		$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income ⁽¹⁾		0.3			(0.1	)		0.2			0.7		(0.4	)		0.3
Gain on cash flow hedges		4.3			(1.5	)		2.8			5.0		(1.9	)		3.1
Amortization of unrecognized benefit costs ⁽²⁾		1.6			(0.6	)		1.0			2.5		(0.9	)		1.6
Total other comprehensive income	$	5.9		$	(2.1	)	$	3.8		$	7.5	$	(2.8	)	$	4.7

(1) Related to interest rate contracts recognized in Interest expense.
(2) Related to postretirement benefits. See Note 5 for additional information.
(3) Related to the estimated curtailment loss for the SERP. See Note 5 for additional information.

	For the three months ended June 30,						For the six months ended June 30,
(millions, except per share amounts)	2016			2015			2016			2015
Basic earnings per share
Net income from continuing operations	$	5.5		$	61.5		$	79.2		$	125.3
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Income before discontinued operations available to common shareholders - Basic	$	5.4		$	61.3		$	79.0		$	124.9
Income (loss) from discontinued operations, net	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Basic	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)
Net income	$	5.3		$	11.8		$	79.1		$	69.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Net income available to common shareholders - Basic	$	5.2		$	11.6		$	78.9		$	69.4
Average common shares outstanding - Basic		234.3			233.0			234.1			232.9
Earnings per share from continuing operations available to common shareholders - Basic	$	0.03		$	0.26		$	0.34		$	0.53
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.0		$	(0.21	)	$	0.0		$	(0.23	)
Earnings per share available to common shareholders - Basic	$	0.03		$	0.05		$	0.34		$	0.30
Diluted earnings per share
Net income from continuing operations	$	5.5		$	61.5		$	79.2		$	125.3
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Income before discontinued operations available to common shareholders - Diluted	$	5.4		$	61.3		$	79.0		$	124.9
Income (loss) from discontinued operations, net	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Diluted	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)
Net income	$	5.3		$	11.8		$	79.1		$	69.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)		(0.2	)		(0.4	)
Net income available to common shareholders - Diluted	$	5.2		$	11.6		$	78.9		$	69.4
Unadjusted average common shares outstanding - Diluted		234.3			233.0			234.1			232.9
Assumed conversion of stock options, unvested restricted stock, unvested RSUs and contingent performance shares, net		1.2			0.6			1.3			0.6
Average common shares outstanding - Diluted		235.5			233.6			235.4			233.5
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.03		$	0.26		$	0.34		$	0.53
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.0		$	(0.21	)	$	0.0		$	(0.23	)
Earnings per share available to common shareholders - Diluted	$	0.03		$	0.05		$	0.34		$	0.30
Anti-dilutive shares		0.0			0.4			0.3			0.3

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

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.

The settlements are not material to the company’s financial position as of June 30, 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. In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

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

In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger. As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement. Subsequent to the Merger closing the parties are expected to enter into a formal settlement agreement in August, which will be filed with the Hillsborough Circuit Court Judge for approval. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

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 has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

PGS Compliance Matter

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

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 June 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 16 for additional information.

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


(millions)							Maximum
					After ⁽¹⁾		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at June 30, 2016
TECO Energy
Fuel sales and transportation ⁽²⁾	$	0.0	$	0.0	$	93.9	$	93.9	$	0.0
Letters of indemnity - coal mining permits ⁽³⁾		85.9		0.0		0.0		85.9		0.0
	$	85.9	$	0.0	$	93.9	$	179.8	$	0.0

							Maximum
(millions)					After ⁽¹⁾		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at June 30, 2016 ⁽⁴⁾
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.8
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.9

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at June 30, 2016. See Note 12 for additional information.
(3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities. Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred, subject to the indemnification terms set forth in the SPA, that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

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 June 30,	Electric		Gas		Gas Co. ⁽²⁾			Coal ⁽¹⁾			Other ⁽²⁾				Eliminations			Energy
2016
Revenues - external	$	498.1	$	99.9	$	51.7		$	0.0		$	2.6			$	0.0		$	652.3
Sales to affiliates		1.1		2.0		0.0			0.0			0.0				(3.1	)		0.0
Total revenues		499.2		101.9		51.7			0.0			2.6				(3.1	)		652.3
Depreciation and amortization		66.5		14.9		8.5			0.0			0.3				0.0			90.2
Total interest charges		22.6		3.7		3.3			0.0			14.5				(0.3	)		43.8
Internally allocated interest		0.0		0.0		0.0			0.0			0.3				(0.3	)		0.0
Provision (benefit) for income taxes		36.9		4.6		(0.1	)		0.0			(17.1	)			0.0			24.3
Net income (loss) from continuing operations		68.6		7.1		(0.2	)		0.0			(70.0	)	⁽⁵⁾		0.0			5.5
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0			0.0			(0.2	)			0.0			(0.2	)
Net income (loss)	$	68.6	$	7.1	$	(0.2	)	$	0.0		$	(70.2	)		$	0.0			5.3
2015
Revenues - external	$	531.6	$	92.2	$	54.0		$	0.0		$	2.8			$	0.0		$	680.6
Sales to affiliates		0.8		1.3		0.0			0.0			0.1				(2.2	)		0.0
Total revenues		532.4		93.5		54.0			0.0			2.9				(2.2	)		680.6
Depreciation and amortization		64.0		14.0		8.4			0.0			0.6				0.0			87.0
Total interest charges		23.6		3.6		3.3			0.0			16.3				(0.4	)		46.4
Internally allocated interest		0.0		0.0		0.0			0.0			0.4				(0.4	)		0.0
Provision (benefit) for income taxes		38.9		4.8		0.0			0.0			(3.2	)			0.0			40.5
Net income (loss) from continuing operations		67.7		7.6		(0.1	)		0.0			(13.7	)			0.0			61.5
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0			(51.5	)		1.8				0.0			(49.7	)
Net income (loss)	$	67.7	$	7.6	$	(0.1	)	$	(51.5	)	$	(11.9	)		$	0.0			11.8

(millions)	Tampa		Peoples		New Mexico		TECO											TECO
Six months ended June 30,	Electric		Gas		Gas Co. ⁽²⁾		Coal ⁽¹⁾			Other ⁽²⁾				Eliminations				Energy
2016
Revenues - external	$	921.5	$	226.7	$	158.3	$	0.0		$	5.3			$	0.0			$	1,311.8
Sales to affiliates		2.2		6.4		0.0		0.0			0.0				(8.6	)			0.0
Total revenues		923.7		233.1		158.3		0.0			5.3				(8.6	)			1,311.8
Depreciation and amortization		132.6		29.7		16.9		0.0			0.8				0.0				180.0
Total interest charges		46.4		7.4		6.3		0.0			30.1				(0.5	)			89.7
Internally allocated interest		0.0		0.0		0.0		0.0			0.5				(0.5	)			0.0
Provision (benefit) for income taxes		64.7		13.5		9.6		0.0			(27.8	)			0.0				60.0
Net income (loss) from continuing operations		118.8		20.2		15.0		0.0			(74.8	)	⁽⁵⁾		0.0				79.2
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0		0.0			(0.1	)			0.0				(0.1	)
Net income (loss)	$	118.8	$	20.2	$	15.0	$	0.0		$	(74.9	)		$	0.0			$	79.1
2015
Revenues - external	$	981.4	$	213.9	$	173.0	$	0.0		$	5.3			$	0.0			$	1,373.6
Sales to affiliates		1.6		2.5		0.0		0.0			0.1				(4.2	)			0.0
Total revenues		983.0		216.4		173.0		0.0			5.4				(4.2	)			1,373.6
Depreciation and amortization		126.9		27.9		16.8		0.0			0.9				0.0				172.5
Total interest charges		47.1		7.1		6.6		0.0			34.2				(0.7	)			94.3
Internally allocated interest		0.0		0.0		0.0		0.0			0.7				(0.7	)			0.0
Provision (benefit) for income taxes		66.3		14.0		9.0		0.0			(8.9	)			0.0				80.4
Net income (loss) from continuing operations		115.9		22.2		13.8		0.0			(26.6	)			0.0				125.3
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0		(57.5	)		2.0				0.0				(55.5	)
Net income (loss)	$	115.9	$	22.2	$	13.8	$	(57.5	)	$	(24.6	)		$	0.0			$	69.8
At June 30, 2016
Total assets	$	7,103.4	$	1,135.9	$	1,200.9	$	0.0		$	1,945.8			$	(2,306.3	)	⁽⁴⁾		9,079.7
At Dec. 31, 2015
Total assets ⁽³⁾	$	7,003.8	$	1,136.1	$	1,229.7	$	0.0		$	1,945.1			$	(2,381.2	)	⁽⁴⁾		8,933.5

(1) All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
(2) NMGI is included in the Other segment.
(3) Certain prior year amounts have been reclassified to conform to current year presentation.
(4) Amounts primarily relate to intercompany advances and consolidated tax eliminations.
(5) Comprised primarily of transaction costs associated with the Merger with Emera. See Note 16.

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 13). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 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 June 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 $5.5 million and $0.2 million as of June 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $1.1 million and $26.2 million as of June 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at June 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 June 30, 2016, net pretax losses of $3.0 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The June 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 8.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and six months ended June 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 six months ended June 30, 2016 and 2015 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to June 30, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of June 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 June 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 June 30, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	5.5	$	0.0	$	5.5

Liabilities
Natural gas derivatives	$	0.0	$	1.1	$	0.0	$	1.1

	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2

Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

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

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 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 June 30, 2016 and Dec. 31, 2015, the carrying value of the company’s short-term debt is not materially different from the fair value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value is determined using Level 2 measurements. See Note 7 for information regarding the fair value of the company’s long-term debt.

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.

has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $16.4 million and $29.0 million under these PPAs for the three and six months ended June 30, 2016, respectively, and $9.9 million and $15.3 million for the three and six months ended June 30, 2015, respectively.

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

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

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 10). 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						Six months ended
	June 30,						June 30,
(millions)	2016			2015			2016			2015
Revenues—TECO Coal	$	0.0		$	76.1		$	0.0		$	148.8
Income (loss) from operations—TECO Coal		(0.3	)		0.5			(0.1	)		(9.0	)
Loss on impairment—TECO Coal		0.0			(78.6	)		0.0			(78.6	)
Loss from operations—TECO Guatemala		(0.1	)		0.0			(0.1	)		(0.1	)
Loss from discontinued operations—TECO Coal		(0.3	)		(78.1	)		(0.1	)		(87.6	)
Loss from discontinued operations—TECO Guatemala		(0.1	)		0.0			(0.1	)		(0.1	)
Loss from discontinued operations		(0.4	)		(78.1	)		(0.2	)		(87.7	)
Benefit for income taxes		(0.2	)		(28.4	)		(0.1	)		(32.2	)
Loss from discontinued operations, net	$	(0.2	)	$	(49.7	)	$	(0.1	)	$	(55.5	)

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 noted above, upon closing of the Merger, NMGC agreed, among other things, to:

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

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

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

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

Assets	June 30,			Dec. 31,
(millions)	2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,419.5		$	7,270.3
Gas		1,447.0			1,398.6
Construction work in progress		832.1			771.1
Utility plant in service, at original costs		9,698.6			9,440.0
Accumulated depreciation		(2,762.0	)		(2,676.8	)
Utility plant in service, net		6,936.6			6,763.2
Other property		10.2			9.7
Total property, plant and equipment, net		6,946.8			6,772.9

Current assets
Cash and cash equivalents		13.8			9.1
Receivables, less allowance for uncollectibles of $1.6 and $1.5 at June 30, 2016 and Dec. 31, 2015, respectively		238.7			230.2
Inventories, at average cost
Fuel		102.2			105.6
Materials and supplies		75.1			73.1
Regulatory assets		18.0			44.3
Taxes receivable from affiliate		0.0			61.3
Prepayments and other current assets		20.6			21.5
Total current assets		468.4			545.1

Deferred debits
Regulatory assets		373.8			373.8
Other		27.7			16.8
Total deferred debits		401.5			390.6
Total assets	$	7,816.7		$	7,708.6

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

Liabilities and Capitalization	June 30,			Dec. 31,
(millions)	2016			2015
Capitalization
Common stock	$	2,395.4		$	2,305.4
Accumulated other comprehensive loss		(3.2	)		(3.6	)
Retained earnings		270.6			313.7
Total capital		2,662.8			2,615.5
Long-term debt		2,162.3			2,161.7
Total capitalization		4,825.1			4,777.2

Current liabilities
Long-term debt due within one year		0.0			83.3
Notes payable		123.0			61.0
Accounts payable		209.5			221.6
Customer deposits		162.7			176.3
Regulatory liabilities		124.4			83.2
Derivative liabilities		0.7			24.1
Interest accrued		17.7			16.9
Taxes accrued		72.2			13.2
Other		10.0			10.2
Total current liabilities		720.2			689.8

Deferred credits
Deferred income taxes		1,352.1			1,308.8
Investment tax credits		10.3			10.5
Regulatory liabilities		608.0			603.5
Deferred credits and other liabilities		301.0			318.8
Total deferred credits		2,271.4			2,241.6

Commitments and Contingencies (see Note 8)

Total liabilities and capitalization	$	7,816.7		$	7,708.6

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

	Three months ended June 30,
(millions)	2016			2015
Revenues
Electric	$	498.8		$	532.4
Gas		100.0			92.2
Total revenues		598.8			624.6
Expenses
Regulated operations and maintenance
Fuel		137.4			171.8
Purchased power		27.8			19.6
Cost of natural gas sold		35.7			30.1
Other		132.5			134.3
Depreciation and amortization		81.4			78.0
Taxes, other than income		47.5			49.5
Total expenses		462.3			483.3
Income from operations		136.5			141.3
Other income
Allowance for other funds used during construction		6.0			3.7
Other income, net		0.9			1.2
Total other income		6.9			4.9
Interest charges
Interest on long-term debt		27.8			27.8
Other interest		1.2			1.2
Allowance for borrowed funds used during construction		(2.8	)		(1.8	)
Total interest charges		26.2			27.2
Income before provision for income taxes		117.2			119.0
Provision for income taxes		41.5			43.7
Net income		75.7			75.3
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			2.8
Total other comprehensive income, net of tax		0.2			2.8
Comprehensive income	$	75.9		$	78.1

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

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

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

	Six months ended June 30,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	139.0		$	138.1
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		162.3			154.8
Deferred income taxes and investment tax credits		36.5			30.0
Allowance for funds used during construction		(11.6	)		(7.5	)
Deferred recovery clauses		41.0			(3.2	)
Receivables, less allowance for uncollectibles		(8.5	)		(24.4	)
Inventories		1.4			(42.1	)
Prepayments		4.3			(6.2	)
Taxes accrued		120.3			93.1
Interest accrued		0.8			2.0
Accounts payable		3.6			(14.3	)
Other		(25.9	)		(14.9	)
Cash flows from operating activities		463.2			305.4
Cash flows from investing activities
Capital expenditures		(353.8	)		(312.4	)
Net proceeds from sale of assets		8.7			0.0
Cash flows used in investing activities		(345.1	)		(312.4	)
Cash flows from financing activities
Common stock		90.0			30.0
Proceeds from long-term debt issuance		0.0			251.3
Repayment of long-term debt		(83.3	)		(83.3	)
Net decrease in short-term debt		62.0			(58.0	)
Dividends		(182.1	)		(109.5	)
Cash flows from (used in) financing activities		(113.4	)		30.5
Net increase in cash and cash equivalents		4.7			23.5
Cash and cash equivalents at beginning of period		9.1			10.4
Cash and cash equivalents at end of period	$	13.8		$	33.9
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(13.9	)	$	1.5

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, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended June 30, 2016 and 2015. The results of operations for the three and six months ended June 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

As of June 30, 2016 and Dec. 31, 2015, unbilled revenues of $66.6 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 prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $28.6 million and $56.5 million for the three and six months ended June 30, 2016, respectively, and $29.3 million and $56.6 million for the three and six months ended June 30, 2015, respectively.

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of June 30, 2016 and Dec. 31, 2015, TEC classified $17.5 million and $18.1 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously

classified as an asset in the “Unamortized debt expense” line item). The guidance did not affect TEC’s results of operations or cash flows.

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

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

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

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

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

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

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

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the six months ended June 30, 2016 and 2015 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only eligible to participate in the CAP through its short tax year ending June 30, 2016. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

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 June 30, 2016 and 2015, respectively, was $3.2 million and $4.2 million for pension benefits, and $1.5 million and $1.5 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2016 and 2015, respectively, was $6.1 million and $6.8 million for pension benefits, and $3.0 million and $2.9 million for other postretirement benefits.

For the 2016 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.685%. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. Additionally, TECO Energy made contributions of $15.6 million and $24.5 million to its pension plan in the six months ended June 30, 2016 and 2015, respectively. TEC’s portion of the contributions was $12.9 million and $18.5 million, respectively.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2016, TEC reclassified $2.8 million and $ 4.8 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.8 million and $4.7 million for the three and six months ended June 30, 2015, respectively.

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

Credit Facilities
	June 30, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts receivable facility ⁽³⁾		150.0		123.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	123.0	$	0.5	$	475.0	$	61.0	$	0.5

At June 30, 2016, TEC’s total long-term debt had a carrying amount of $2,162.3 million and an estimated fair market value of $2,446.2 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $58.8 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 June 30, 2016, $232.6 million of bonds purchased in lieu of redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

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.

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

the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

The 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.

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2016 is as follows:

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2016, TEC was in compliance with all applicable financial covenants.

(millions)	Tampa							Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	498.8	$	100.0	$	0.0		$	598.8
Intracompany sales		0.4		1.9		(2.3	)		0.0
Total revenues		499.2		101.9		(2.3	)		598.8
Depreciation and amortization		66.5		14.9		0.0			81.4
Total interest charges		22.6		3.7		(0.1	)		26.2
Provision for income taxes		36.9		4.6		0.0			41.5
Net income	$	68.6	$	7.1	$	0.0			75.7
2015
Revenues - external	$	532.4	$	92.2	$	0.0		$	624.6
Intracompany sales		0.0		1.3		(1.3	)		0.0
Total revenues		532.4		93.5		(1.3	)		624.6
Depreciation and amortization		64.0		14.0		0.0			78.0
Total interest charges		23.6		3.6		0.0			27.2
Provision for income taxes		38.9		4.8		0.0			43.7
Net income	$	67.7	$	7.6	$	0.0		$	75.3
Six months ended June 30,
2016
Revenues - external	$	923.0	$	226.8	$	0.0		$	1,149.8
Intracompany sales		0.7		6.3		(7.0	)		0.0
Total revenues		923.7		233.1		(7.0	)		1,149.8
Depreciation and amortization		132.6		29.7		0.0			162.3
Total interest charges		46.4		7.4		(0.1	)		53.7
Provision for income taxes		64.7		13.5		0.0			78.2
Net income	$	118.8	$	20.2	$	0.0		$	139.0
2015
Revenues - external	$	982.8	$	213.9	$	0.0		$	1,196.7
Intracompany sales		0.2		2.5		(2.7	)		0.0
Total revenues		983.0		216.4		(2.7	)		1,196.7
Depreciation and amortization		126.9		27.9		0.0			154.8
Total interest charges		47.1		7.1		0.0			54.2
Provision for income taxes		66.3		14.0		0.0			80.3
Net income	$	115.9	$	22.2	$	0.0		$	138.1
Total assets at June 30, 2016	$	6,720.1	$	1,099.8	$	(3.2	)	$	7,816.7
Total assets at Dec. 31, 2015 ⁽¹⁾		6,620.2		1,097.7		(9.3	)		7,708.6

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 on the underlying physical transaction.

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

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

The derivatives that are designated as cash flow hedges at June 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 $4.9 million and $0.0 as of June 30, 2016 and Dec. 31, 2015, respectively. Derivative liabilities totaled $0.7 million and $26.2 million as of June 30, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at June 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 June 30, 2016, net pretax losses of $2.7 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The June 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 June 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of June 30, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

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

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

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

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

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

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

	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

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

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 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 June 30,							Six months ended June 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		0.7		(0.3	)		0.4
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.7		(0.3	)		0.4
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.7	$	(0.3	)	$	0.4
2015
Unrealized gain on cash flow hedges	$	4.0	$	(1.4	)	$	2.6	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		0.7		(0.4	)		0.3
Gain on cash flow hedges		4.3		(1.5	)		2.8		5.0		(1.9	)		3.1
Total other comprehensive income	$	4.3	$	(1.5	)	$	2.8	$	5.0	$	(1.9	)	$	3.1

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 $16.4 million and $29.0 million under these PPAs for the three and six months ended June 30, 2016, respectively, and $9.9 million and $15.3 million for the three and six months ended June 30, 2015, respectively.

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, Merger Sub merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. 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 Item 1A Risk Factors of Part II of this Quarterly Report.

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

	Three Months Ended June 30,						Six Months Ended June 30,
(millions) Except per-share amounts	2016			2015			2016			2015
Consolidated revenues	$	652.3		$	680.6		$	1,311.8		$	1,373.6
Net income from continuing operations		5.5			61.5			79.2			125.3
Loss on discontinued operations, net		(0.2	)		(49.7	)		(0.1	)		(55.5	)
Net income		5.3			11.8			79.1			69.8
Average common shares outstanding
Basic		234.3			233.0			234.1		232.9
Diluted	235.5			233.6			235.4			233.5
Earnings per share – basic
Continuing operations	$	0.03		$	0.26		$	0.34		$	0.53
Discontinued operations		0.00			(0.21	)		0.00			(0.23	)
Earnings per share - basic	$	0.03		$	0.05		$	0.34		$	0.30
Earnings per share – diluted
Continuing operations	$	0.03		$	0.26		$	0.34		$	0.53
Discontinued operations		0.00			(0.21	)		0.00			(0.23	)
Earnings per share - diluted	$	0.03		$	0.05		$	0.34		$	0.30

Second-quarter 2016 net income was $5.3 million, or $0.03 per share, compared with $11.8 million, or $0.05 per share, in the second quarter of 2015. Net income from continuing operations was $5.5 million, or $0.03 per share, in the 2016 second quarter, compared with $61.5 million, or $0.26 per share, for the same period in 2015. Net income from continuing operations in the 2016 period reflects $58.4 million of Emera acquisition-related costs ($71.4 million pretax) (see Note 16 to the TECO Energy Consolidated Financial Statements). The second quarter losses in discontinued operations of $49.7 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 second quarter of 2016 was $79.1 million, or $0.34 per share, compared with $69.8 million, or $0.30 per share, in the 2015 year-to-date period. Net income from continuing operations was $79.2 million, or $0.34 per share, in

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

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

Tampa Electric’s net income for the second quarter of 2016 was $68.6 million, compared with $67.7 million for the same period in 2015. Second-quarter net income in 2016 included $6.0 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $3.7 million in the 2015 quarter. Results for the quarter reflected a 1.6% higher average number of customers. Energy sales were lower due to more normal weather compared to the second quarter of 2015 when consistently higher than normal spring temperatures were experienced. Results reflected operations and maintenance expense slightly higher than in 2015 and higher depreciation expenses.

Total degree days in Tampa Electric's service area in the second quarter of 2016 were 5% above normal, but 10% below the 2015 period, when degree days were 15% above normal. Total net energy for load decreased 2.6% in the second quarter of 2016, compared with the same period in 2015. In the 2016 period, pretax base revenues were $2.5 million lower than in 2015, as lower energy sales from more normal weather was only partially offset by customer growth and $1.6 million of higher pretax base revenue from higher base rates effective Nov. 1, 2015, as a result of the 2013 rate case settlement.

While net energy for load is a calendar measurement of retail energy sales rather than a billing-cycle measurement, the quarterly energy sales shown on the following table reflect the energy sales based on billing cycles, which can vary period to period. Retail energy sales to residential and commercial customers decreased in the second quarter of 2016 primarily due to milder weather compared to the 2015 quarter when spring temperatures were higher. Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased and mining activity migrates out of Tampa Electric’s service area.

In the second quarter of 2016 operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was slightly higher than in the 2015 quarter, reflecting higher costs to safely and reliably operate and maintain the generating system and provide high-quality customer service, essentially offset by lower employee-related costs primarily due to the lower level of short-term incentive accruals for all employees in 2016 compared to 2015. Depreciation and amortization expense increased $1.5 million in 2016 as a result of normal additions to facilities to reliably serve customers.

Tampa Electric’s year-to-date net income through the second quarter of 2016 was $118.8 million, compared with $115.9 million for the same period in 2015. Year-to-date net income in 2016 included $11.6 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $7.5 million in the 2015 period. Results for the year-to-date period reflected a 1.6% higher average number of customers. Energy sales were lower compared to 2015 due to the well-above-normal second quarter temperatures experienced in the 2015 period. Results reflected operations and maintenance expense slightly higher than in 2015 and higher depreciation expense.

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

In the 2016 year-to-date period, retail energy sales to residential customers decreased primarily from milder spring weather than was experienced in the 2015 period. Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy. Sales to lower-margin industrial-phosphate customers decreased as a result of the same factors as the second quarter.

In the 2016 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was almost $1.0 million higher than in the 2015 period, reflecting higher costs to safely and reliably operate and maintain the generating, transmission and distribution systems and provide high-quality customer service, partially offset by lower employee-related costs, primarily due to the lower level of short-term incentive accruals for all employees in 2016 compared to 2015. Depreciation and amortization expense increased $3.5 million in 2016, as a result of normal additions to facilities to reliably serve customers.

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

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

Six months ended June 30,
By Customer Type
Residential	$	470.0		$	480.8		(2.2	)		4,155.3		4,170.0		(0.4	)
Commercial		280.4			287.9		(2.6	)		2,953.2		2,960.1		(0.2	)
Industrial – Phosphate		25.8			27.3		(5.5	)		321.6		340.9		(5.7	)
Industrial – Other		52.9			52.7		0.4			617.9		598.9		3.2
Other sales of electricity		82.8			85.4		(3.0	)		848.0		856.1		(0.9	)
Deferred and other revenues ⁽¹⁾		(17.5	)		16.7		(204.8	)
Total energy sales		894.4			950.8		(5.9	)		8,896.0		8,926.0		(0.3	)
Sales for resale		2.1			2.9		(27.6	)		68.6		84.7		(19.0	)
Other operating revenue		27.2			29.4		(7.5	)
Total revenues	$	923.7		$	983.1		(6.0	)		8,964.6		9,010.7		(0.5	)
Average customers (thousands)		727.7			716.0		1.6
Retail net energy for load (kilowatt hours)										9,578.5		9,664.9		(0.9	)
Total degree days										1,857		2,034		(8.7	)

(1) Primarily reflects the timing of environmental and fuel clause recoveries.

PGS reported net income of $7.1 million for the second quarter, compared with $7.6 million in the 2015 quarter. Average customer growth was 2.3% in the quarter. Therm sales to residential and commercial customers increased primarily as a result of customer growth. Sales to commercial and industrial customers increased as a result of the stronger Florida economy and increased sales of compressed natural gas to vehicle fleets. Off-system sales increased, reflecting higher levels of operation by gas-fired generation in Florida due to lower natural gas prices and weather-related demand. Second-quarter results in 2016 reflected non-fuel operations and maintenance expense $1.1 million higher than in 2015, driven by higher operating and compliance costs due to increasing pipeline safety regulations, partially offset by lower employee-related costs primarily due to the lower level of short-term incentive accruals for all employees in 2016 compared to 2015. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers.

PGS reported net income of $20.2 million for the 2016 year-to-date period, compared with $22.2 million in the 2015 period. These results reflect higher therm sales as a result of the same factors that drove therm sales in the second quarter. Operations and maintenance expense was $2.1 million higher and depreciation expense was $1.0 million higher than the 2015 period, both driven by the same factors as the second quarter.

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

(millions, except average customers)	Operating Revenues							Therms
Three months ended June 30,	2016		2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	30.5	$	28.1		8.5			14.6		12.5		16.8
Commercial		34.5		32.5		6.2			117.8		109.9		7.2
Industrial		3.4		3.2		6.2			77.9		70.2		11.0
Off system sales		18.4		14.4		27.8			72.2		46.4		55.6
Power generation		0.1		1.9		(94.7	)		189.1		190.8		(0.9	)
Other revenues		12.3		11.1		10.8
Total	$	99.2	$	91.2		8.8			471.6		429.8		9.7
By Sales Type
System supply	$	57.5	$	51.6		11.4			92.5		65.7		40.8
Transportation		29.3		28.5		2.8			379.1		364.1		4.1
Other revenues		12.4		11.1		11.7
Total	$	99.2	$	91.2		8.8			471.6		429.8		9.7
Average customers (thousands)		369.9		361.7		2.3

Six months ended June 30,
By Customer Type
Residential	$	81.0	$	77.3		4.8			47.5		46.9		1.3
Commercial		77.3		74.1		4.3			258.9		248.1		4.4
Industrial		6.7		6.4		4.7			161.4		146.3		10.3
Off system sales		31.3		22.2		41.0			126.0		69.8		80.5
Power generation		2.1		3.9		(46.2	)		379.7		375.4		1.1
Other revenues		28.9		27.3		5.9
Total	$	227.3	$	211.2		7.6			973.5		886.5		9.8
By Sales Type
System supply	$	132.9	$	121.0		9.8			186.6		132.0		41.4
Transportation		65.5		62.9		4.1			786.9		754.5		4.3
Other revenues		28.9		27.3		5.9
Total	$	227.3	$	211.2		7.6			973.5		886.5		9.8
Average customers (thousands)		368.7		360.4		2.3

NMGC reported a second-quarter loss of $0.2 million, compared with a $0.1 million loss in the 2015 period. Growth in the average number of customers in the 2016 quarter and year-to-date periods were 0.6%. In the second quarter, heating degree days were 7% above normal but 3% below the 2015 quarter. Non-fuel operating and maintenance expense was slightly higher than in the 2015 quarter due to higher employee related expenses. Results included $0.6 million of pretax rate credits to customers under the stipulation approved by the NMPRC in 2014.

NMGC reported year-to-date net income of $15.0 million compared with $13.8 million in the 2015 period. Results reflected the benefit of heating degree days that were slightly higher than in 2015, but more than 4% below normal. Operating and maintenance expense was essentially unchanged from the prior period. Results included $2.5 million of pretax rate credits to customers under the stipulation approved by the NMPRC in 2014.

NMGC expects to record $30.4 million of pretax expense in the third quarter of 2016 related to the conditions contained in the Emera acquisition stipulation approved by the NMPRC (see Note 16 to the TECO Energy Consolidated Financial Statements).

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

(millions, except average customers and total degree days)	Operating Revenues							Therms
Three months ended June 30,	2016		2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	37.1	$	38.2		(2.9	)		42.8		38.9		10.0
Commercial		8.5		10.1		(15.8	)		16.1		16.8		(4.2	)
Industrial		0.1		0.1		-			0.2		0.2		-
Off system sales		0.2		0.2		-			0.0		0.0		-
On system transportation		4.1		3.7		10.8			76.1		73.4		3.7
Off system transportation		0.2		0.2		-			12.3		12.3		-
Other revenues		1.5		1.5		-
Total	$	51.7	$	54.0		(4.3	)		147.5		141.6		4.2
By Sales Type
System supply	$	45.9	$	48.6		(5.6	)		59.1		55.9		5.7
Transportation		4.3		3.9		10.3			88.4		85.7		3.2
Other revenues		1.5		1.5		-
Total	$	51.7	$	54.0		(4.3	)		147.5		141.6		4.2
Average customers (thousands)		518.8		515.8		0.6
Total degree days									457		472		(3.2	)

Six months ended June 30,
By Customer Type
Residential	$	114.8	$	125.7		(8.7	)		165.3		160.1		3.2
Commercial		28.1		33.1		(15.1	)		58.1		57.8		0.5
Industrial		0.3		0.3		-			0.7		0.7		-
Off system sales		1.0		0.7		42.9			3.9		1.2		225.0
On system transportation		10.7		9.8		9.2			171.2		158.1		8.3
Off system transportation		0.4		0.4		-			23.4		22.6		3.5
Other revenues		3.0		3.0		-
Total	$	158.3	$	173.0		(8.5	)		422.6		400.5		5.5
By Sales Type
System supply	$	144.2	$	159.8		(9.8	)		228.0		219.8		3.7
Transportation		11.1		10.2		8.8			194.6		180.7		7.7
Other revenues		3.0		3.0		-
Total	$	158.3	$	173.0		(8.5	)		422.6		400.5		5.5
Average customers (thousands)		519.3		516.3		0.6
Total degree days									2,427		2,393		1.4

The second quarter 2016 cost for Other – net was $70.2 million, which included $0.2 million in discontinued operations related to TECO Coal, which was sold in 2015. The second quarter 2016 cost from continuing operations for Other – net was $70.0 million and included $58.4 million ($71.4 million pretax) of costs associated with the Emera transaction, compared with the cost of $13.7 million in 2015, which included $0.4 million of NMGC-related integration costs. Emera transaction costs included primarily employee-related and consultant fees (see Note 16 to the TECO Energy Consolidated Financial Statements). Year-to-date 2016 cost for Other – net was $74.9 million, compared with $24.6 million in the 2015 period, which included $1.0 million of NMGC integration costs. Year-to-date cost from continuing operations for Other – net was $74.8 million compared with $26.6 million in the 2015 period. Year-to-date 2016 costs reflect the Emera transaction costs, a $5.8 million tax benefit due to an accounting rule change related to stock-based incentive compensation recorded in the first quarter, and lower interest expense as a result of refinancing debt maturities.

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

The sale of TECO Coal closed in September 2015. The $0.2 million second quarter 2016 loss recorded in discontinued operations reflects trailing costs associated with the sale of TECO Coal recorded in the Other – net segment, compared with a $49.7 million loss in the 2015 period, which reflected TECO Coal’s operating results prior to its sale, net of impairment charges. The $0.1 million loss in discontinued operations for the 2016 year-to-date period reflects the second quarter cost net of a $0.1 million refund of prepaid costs recorded in the first quarter of 2016, compared with a loss of $55.5 million in the 2015 period, which reflected TECO Coal’s operating results prior to its sale net of impairment charges (see Note 15 to the TECO Energy Consolidated Financial Statements).

The provisions for income taxes from continuing operations for the six month periods ended June 30, 2016 and 2015 were $60.0 million and $80.4 million, respectively. The provision for income taxes for the six months ended June 30, 2016 was impacted by lower pre-tax income and a tax benefit related to long-term incentive compensation offset by the tax impact of the Merger transaction costs. (see Note 2 and Note 16 to the TECO Energy Consolidated Financial Statements).

The table below sets forth the June 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 expect net cash outflows associated with the acquisition of approximately $50 million in 2016, primarily in the third quarter, and approximately $20 million in 2017 (representing cash payments of transaction costs accrued at June 30). In connection with the stipulation approved by the NMPRC, pre-tax costs of approximately $30 million are expected to be 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.

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 June 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 June 30, 2016. Reference is made to the specific agreements and instruments for more details.

On July 6, 2016, Moody’s downgraded the 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 Sept. 8, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC, following the announcement of the pending Merger with Emera. On Oct. 9, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy at BBB and TEC at BBB+ and affirmed the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC. Fitch Ratings also described the ratings outlook as "Stable".

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

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors in Item 1A of 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.

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 13 to the TECO Energy Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 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, 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 13% from Dec. 31, 2015 to June 30, 2016. For natural gas, the company maintained a similar volume hedged as of June 30, 2016 as compared to Dec. 31, 2015.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six month period ended June 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 Notes 10 and 8, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

TECO Energy updated the risk factors in its 2015 Annual Report on Form 10-K as described below.

TECO Energy and its subsidiaries are subject to business uncertainties during the period of integration with Emera that could adversely affect TECO Energy’s financial results.

Uncertainty about the effect of the Merger on employees or vendors and others, including contractors, may have an adverse effect on TECO Energy. These uncertainties may impair TECO Energy’s and its subsidiaries’ ability to attract, retain and motivate key personnel, and could cause vendors and others, including contractors, that deal with TECO Energy to seek to change existing business relationships. Employee retention and recruitment may continue to be challenging after the completion of the Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite TECO Energy’s retention and recruiting efforts, key employees retire, depart or fail to accept employment with TECO Energy or its subsidiaries due to the uncertainty of employment and difficulty of integration or a desire not to remain with the combined company, TECO Energy may incur significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a material adverse effect on TECO Energy’s business operations and financial results.

Matters relating to integration-related issues may place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on integration -related issues could affect TECO Energy’s financial results.

We have been and may continue to be the target of securities class action suits and derivative suits which could result in substantial costs and divert management attention and resources.

Securities class action suits and derivative suits are often brought against companies who have entered into mergers and acquisition transactions. Following the announcement of the execution of the Merger Agreement, 12 putative stockholder class actions were filed challenging the Merger. In November 2015, the defendants party to the litigation entered into a Memorandum of Understanding (the “MOU”) 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 MOU, TECO Energy made additional disclosures related to the proposed Merger in a proxy supplement filed on Nov. 18, 2015. Subsequent to the Merger closing the parties are expected to enter into a formal settlement agreement in August, which will be filed with the Hillsborough Circuit Court Judge for approval. Additionally, the judge will consider the award of attorneys’ fees to the plaintiffs’ lawyers. See Note 12 to the TECO Energy Consolidated Financial Statements. Defending against these claims, even if meritless, can result in substantial costs to us and could divert the attention of our management.

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TECO Energy and its subsidiaries.

The business of TECO Energy is concentrated in Florida and New Mexico. While economic conditions in Florida and New Mexico have improved since the worst of the economic downturn in 2008, if they do not continue to improve or if they should worsen, retail customer growth rates may stagnate or decline, and customers’ energy usage may further decline, adversely affecting TECO Energy’s results of operations, net income and cash flows.

A factor in our customer growth in both Florida and New Mexico is net in migration of new residents, both domestic and non-U.S. A slowdown in the U.S. economy could reduce the number of new residents and slow customer growth. In addition, New Mexico has significant oil and natural gas production from the San Juan and Permian production basins. The current low oil and natural gas-price environment has reduced drilling activity and oil and natural gas production in some producing regions, which has reduced employment in those industries and industries that serve them. A continuation of these conditions could slow growth in the New Mexico economy, which could reduce earnings and cash flow from NMGC.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient appliances and equipment. Advances in these or other technologies could reduce the cost of producing electricity or transporting gas, or otherwise make the existing generating facilities of Tampa Electric uneconomic. In addition, advances in such technologies could reduce demand for electricity or natural gas, which could negatively impact the results of operations, net income and cash flows of TECO Energy.

Results at TECO Energy’s utilities may be affected by changes in customer energy-usage patterns.

For the past several years, at Tampa Electric and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts, economic conditions and improvements in lighting and appliance efficiency.

Forecasts by TECO Energy’s utilities are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of TECO Energy’s utilities to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency, economic conditions or other factors.

TECO Energy’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.

TECO Energy’s utility businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by its electric and gas utilities are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS and NMGC, which typically have short but significant winter peak periods that are dependent on cold weather, and are more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. NMGC typically earns all of its net income in the first and fourth quarters, due to winter weather. Mild winter weather could negatively impact results at TECO Energy.

TECO Energy’s electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition.

TECO Energy’s electric and gas utilities operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC in Florida and the NMPRC in New Mexico, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on TECO Energy’s utilities’ financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, indicating an overearnings trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged overearnings could result in credits or refunds to customers, which could reduce earnings and cash flow.

Increased customer use of distributed generation could adversely affect TECO Energy’s regulated electric utility business.

In many areas of the United States, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s Clean Power Plan could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule.

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

Potential amendments to the Florida Constitution regarding solar energy could adversely impact Tampa Electric.

In 2015, there was a proposed constitutional ballot initiative for the 2016 election approved by the Florida Supreme Court to promote increased direct sale and use of solar energy to generate electricity which has now been delayed to the 2018 election. There is also a proposed constitutional amendment on the August 2016 primary election ballot that could, if passed by 60% of the voters, lead to lower property taxes on solar technology used in commercial applications, and promote increased direct sale and use of solar energy to generate electricity.

The potential amendment to the Florida constitution in 2018 and the proposed amendment on the August 2016 primary election ballot would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and allow sales of electricity by non-utility generators. Increased use of solar generation and sales by third parties would reduce energy sales and revenues at Tampa Electric. In addition, Tampa Electric could make investments in facilities to serve customers during periods that solar energy is not available that would not be profitable.

Changes in the environmental laws and regulations affecting its businesses could increase TECO Energy’s costs or curtail its activities.

TECO Energy’s businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TECO Energy, requiring cost-recovery proceedings and/or requiring it to curtail some of its businesses’ activities.

Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.

The U.S. EPA published a new CCR rule in the U.S. Federal Register on April 17, 2015, setting federal standards for companies that dispose of CCRs in onsite landfills and impoundments. The rule went into effect on Oct. 19, 2015, and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. Activities in 2016 will consist primarily of monitoring and testing of the two existing CCR impoundments that are affected by this rule. Potential capital expenditures that may be required to comply with this rule are not expected to be significant. This rule is likely to face continued legal challenges by the utility industry and environmental groups, and legislation is required to fix certain portions of the rule. At this time, the ultimate outcome of any litigation or legislation is uncertain, so that it is not possible to predict the ultimate impact on Tampa Electric. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, TECO Energy cannot be assured that any increased costs associated with the new regulations will be eligible for such treatment.

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase TECO Energy’s costs or the rates charged to TECO Energy customers, which could curtail sales.

Among TECO Energy’s companies, Tampa Electric has the most significant number of stationary sources with air emissions.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new state or federal environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but TECO Energy cannot be assured that the FPSC would grant such recovery. Under the Clean Power Plan, each state is responsible for implementing its own regulations to accord to the federal standards. Accordingly, a change in Florida’s regulatory landscape could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by

governmental authorities of existing requirements may impose additional costs on TECO Energy requiring FPSC cost recovery proceedings and/or requiring it to curtail some of its business activities.

The Clean Power Plan establishes state-specific emission rate- and mass-based goals measured against a 2012 baseline. As Tampa Electric’s investments in lower-GHG production largely occurred before 2012 and are factored into Florida’s baseline generating capacity, Tampa Electric may encounter more difficulty than its competitors in achieving cost-effective GHG emission reductions. Because the ultimate form of Florida’s state plan remains unknown, the increased compliance costs that Tampa Electric may face as a result of the Clean Power Plan are currently uncertain.

On Feb. 9, 2016, the U.S. Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the U.S. Court of Appeals for the District of Columbia Circuit. The timing of the resolution of the legal challenges and the removal of the stay by the U.S. Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018.

NMGC operates high-pressure natural gas transmission pipelines, which involve risks that may result in accidents or otherwise affect its operations.

There are a variety of hazards and operating risks inherent in operating high-pressure natural gas transmission pipelines, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by floods, fires and other natural disasters that may cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, known as High Consequence Areas, the level of damage resulting from these risks could be greater. NMGC does not maintain insurance coverage against all of these risks and losses, and any insurance coverage it might maintain may not fully cover damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material adverse effect on TECO Energy’s business, earnings, financial condition and cash flows.

NMGC’s high-pressure transmission pipeline operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase TECO Energy’s cost of operations and affect or limit its business plans.

TECO Energy’s pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation. These laws and regulations require TECO Energy to comply with a significant set of requirements for the design, construction, maintenance and operation of its pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipelines. The regulations determine the pressures at which its pipelines can operate.

PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand pipeline integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. Pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on TECO Energy’s pipelines. Should any of these risks materialize, it may have a material adverse effect on TECO Energy’s operations, earnings, financial condition and cash flows.

TECO Energy’s computer systems and the infrastructure of its utility companies are subject to cyber- (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer-, employee-related or other critical information or systems, or otherwise adversely affect its business and financial results and condition.

There have been an increasing number of cyberattacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems inside of the organization.

TECO Energy has security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, TECO Energy cannot be assured that a cyberattack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject it to additional regulation, litigation or damage to its reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of TECO Energy’s utility companies are designed and operated in a manner intended to mitigate the impact of this type

of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting TECO Energy’s facilities or the industry in general, could also cause TECO Energy to incur additional security- and insurance-related costs, and could have adverse effects on its business and financial results and condition.

Potential competitive changes may adversely affect TECO Energy’s regulated electric and gas businesses.

There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

The gas distribution industry has been subject to competitive forces for a number of years. Gas services provided by TECO Energy’s gas utilities are unbundled for all non-residential customers. Because its gas utilities earn margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted TECO Energy’s results. However, future structural changes could adversely affect PGS and NMGC.

The value of TECO Energy’s existing deferred tax benefits are determined by existing tax laws and could be negatively impacted by changes in these laws.

“Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of TECO Energy’s existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and it would reduce future tax payments received by TECO Energy from its subsidiaries.

TECO Energy relies on some natural gas transmission assets that it does not own or control to deliver natural gas. If transmission is disrupted, or if capacity is inadequate, TECO Energy’s ability to sell and deliver natural gas and supply natural gas to its customers and its electric generating stations may be hindered.

TECO Energy depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets, as well as the natural gas it purchases for use in its electric generation facilities. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations could be adversely affected.

Disruption of fuel supply could have an adverse impact on the financial condition of TECO Energy.

Tampa Electric, PGS and NMGC depend on third parties to supply fuel, including natural gas and coal. As a result, there are risks of supply interruptions and fuel-price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams, pipeline failures or other events, could impair the ability to deliver electricity or gas or generate electricity and could adversely affect operations. Further, the loss of coal suppliers or the inability to renew existing coal and natural gas contracts at favorable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TECO Energy.

Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses.

TECO Energy’s businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes in the availability of these commodities could affect the prices charged by suppliers as well as suppliers’ operating costs and the competitive positions of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales of, and the margins earned on, wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS and NMGC, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive positions of PGS and NMGC as compared to electricity, other forms of energy and other gas suppliers.

The facilities and operations of TECO Energy could be affected by natural disasters or other catastrophic events.

TECO Energy’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures, vandalism, potentially catastrophic events such as the occurrence of a major accident or incident at one of the sites, and other events beyond the control of TECO Energy. The operation of transmission and distribution systems involves certain risks, including gas leaks, fires, explosions, pipeline ruptures and other hazards and risks that may cause unforeseen interruptions, personal injury or property damage. Any such incident could have an adverse effect on TECO Energy and any costs relating to such events may not be recoverable through insurance or recovered in rates. In certain cases, there is potential that such an event may not excuse TECO Energy’s utility companies from servicing customers as required by their respective tariffs.

The franchise rights held by TECO Energy’s utilities could be lost in the event of a breach by such TECO Energy utilities or could expire and not be renewed.

TECO Energy’s utilities hold franchise rights that are memorialized in agreements with selected counterparties throughout their service areas. In some cases these rights could be lost in the event of a breach of these agreements by the applicable TECO Energy utility. In addition, these agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Some agreements also contain provisions allowing municipalities to purchase the portion of the applicable utility’s system located within a given municipality’s boundaries under certain conditions.

Tampa Electric, PGS and NMGC may not be able to secure adequate rights of way to construct transmission lines, gas interconnection lines and distribution-related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

Tampa Electric, PGS and NMGC rely on federal, state and local governmental agencies and, in New Mexico, cooperation with local Native American tribes and councils, to secure rights of way and siting permits to construct transmission lines, gas interconnection lines and distribution-related facilities. If adequate rights of way and siting permits to build new transportation and transmission lines cannot be secured:

Impairment testing of certain long-lived assets could result in impairment charges.

TECO Energy assesses long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, TECO Energy may be required to record non-cash impairment charges that could have a material adverse impact on TECO Energy’s financial condition and results from operations. In connection with the NMGC acquisition, TECO Energy recorded additional goodwill and long-lived assets that could become impaired.

TECO Energy has substantial indebtedness, which could adversely affect its financial condition and financial flexibility.

TECO Energy has substantial indebtedness, which has resulted in fixed charges it is obligated to pay. The level of TECO Energy’s indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing (see Management’s Discussion & Analysis – Significant Financial Covenants section).

TECO Energy, TECO Finance, TEC, NMGC and NMGI must meet certain financial covenants as defined in the applicable agreements to borrow under their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments.

Although TECO Energy was in compliance with all required financial covenants as of June 30, 2016, it cannot assure compliance with these financial covenants in the future. TECO Energy’s failure to comply with any of these covenants or to meet its payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. TECO Energy may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a portion of its outstanding obligations. If TECO Energy’s cash flows and capital resources are insufficient to fund its debt service obligations, it may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance its indebtedness. TECO Energy’s ability to restructure or refinance its debt will depend on the condition of the capital markets and TECO Energy’s financial condition at such time. Any refinancing of TECO Energy’s debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict TECO Energy from adopting some of these alternatives.

TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates that do not appear on its balance sheet. Such obligations include guarantees, letters of credit and certain other types of contractual commitments.

Financial market conditions could limit TECO Energy’s access to capital and increase TECO Energy’s costs of borrowing or refinancing, or have other adverse effects on its results.

TECO Finance and TEC have debt maturing in 2017 and subsequent years, which may need to be refinanced. Future financial market conditions could limit TECO Energy’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings. If TECO Energy is not able to issue new debt, or TECO Energy issues debt at interest rates higher than expected, its financial results or condition could be adversely affected.

TECO Energy enters into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable.

TECO Energy enters into derivative transactions with counterparties, most of which are financial institutions, to hedge its exposure to commodity price and interest rate changes. Although TECO Energy believes it has appropriate credit policies in place to manage the non-performance risk associated with these transactions, turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which TECO Energy has an in-the-money position, TECO Energy could be unable to collect from such counterparty.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase TECO Energy’s pension expense or the required cash contributions to maintain required levels of funding for its plan.

Under calculation requirements of the Pension Protection Act, as of the Jan. 1, 2016, measurement date, TECO Energy’s pension plan was essentially fully funded. Under MAP 21, TECO Energy is not required to make additional cash contributions over the next five years; however, TECO Energy may make additional cash contributions from time to time. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund its pension plan in the future, and could cause pension expense to increase.

TECO Energy’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast.

In 2016, TECO Energy is forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. In 2016, TECO Energy is forecasting capital expenditures at PGS to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe. Forecasted capital expenditures at NMGC are expected to support customer and system reliability and expansion.

If TECO Energy’s capital expenditures exceed the forecasted levels, it may need to draw on credit facilities or access the capital markets on unfavorable terms. TECO Energy cannot be sure that it will be able to obtain additional financing, in which case its financial position could be adversely affected.

TECO Energy’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade, and TECO Energy cannot be assured of any rating improvements in the future.

TECO Energy’s senior unsecured debt is rated as investment grade by S&P at ‘BBB’, by Moody’s at ‘Baa2’, and by Fitch at ‘BBB’. The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A3’ and by Fitch at ‘A-’. The senior unsecured debt of NMGC is rated by S&P at BBB+. A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P, Moody’s and Fitch, may affect TECO Energy’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. TECO Energy may also experience greater interest expense than it would have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any downgrades. In addition, downgrades could adversely affect TECO Energy’s relationships with customers and counterparties.

At current ratings, TEC and NMGC are able to purchase electricity and gas without providing collateral. If the ratings of TEC or NMGC decline to below investment grade, Tampa Electric, PGS or NMGC, as applicable, could be required to post collateral to support their purchases of electricity and gas.

TECO Energy is a holding company with no business operations of its own and depends on cash flow from its subsidiaries to meet its obligations.

TECO Energy is a holding company with no business operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of TECO Energy’s operations are conducted by its subsidiaries. As a holding company, TECO Energy requires dividends and other payments from its subsidiaries to meet its cash requirements. If TECO Energy’s subsidiaries are unable to pay it dividends or make other cash payments to it, TECO Energy may be unable to satisfy its obligations.

In connection with the sale of TECO Coal to Cambrian, TECO Energy temporarily retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the completion of the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia.

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 by TECO Energy to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder or TECO Coal or one of the affiliates transferred to Cambrian as part of the sale did not pay the surety company. Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of ownership and control of TECO Coal and its affiliates with the appropriate governmental entities with respect to the coal mining permits. Pursuant to the terms of the SPA, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond(s) secured by the TECO Energy indemnity for that permit. The company is working with Cambrian on the process of replacing the bonds. However, until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective.

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

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 July 1, 2016 (Exhibit 3.2, Form 8-K dated July 1, 2016 of TECO Energy, Inc.).	*

3.3	Restated Articles of Incorporation of Tampa Electric Company, as amended on Nov. 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*

3.4	Bylaws of Tampa Electric Company, as amended effective Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*

4.1	Twelfth Supplemental Indenture dated as of July 1, 2016 between TECO Energy, Inc. and The Bank of New York Mellon, as trustee.

4.2	Fifth Supplemental Indenture dated as of July 1, 2016 between TECO Finance, Inc., TECO Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.

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

Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	x	Smaller reporting company	¨

Accumulated Other Comprehensive Loss
(millions)	June 30, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit ⁽¹⁾	$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and transition obligations ⁽²⁾		25.4			25.6
Net unrealized losses from cash flow hedges ⁽³⁾		(3.2	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.4	)	$	(12.2	)

(1) Net of tax benefit of $20.9 million and $21.5 million as of June 30, 2016 and Dec. 31, 2015, respectively.
(2) Net of tax expense of $15.8 million and $16.1 million as of June 30, 2016 and Dec. 31, 2015, respectively.
(3) Net of tax benefit of $2.0 million and $2.3 million as of June 30, 2016 and Dec. 31, 2015, respectively.

							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⁾		617.2		123.5		3.7		490.0
Available credit facilities		682.8		351.5		121.3		210.0
Cash and short-term investments		29.2		13.8		1.7		13.7
Total liquidity	$	712.0	$	365.3	$	123.0	$	223.7

Derivative Volumes	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		19.3
2017		0.0		17.7
2018		0.0		2.6
Total		0.0		39.6

Letters of Credit - Tampa Electric Company
(millions)					After ⁽¹⁾				Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Total		at June 30, 2016
TEC ⁽²⁾	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at June 30, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

(millions, unless otherwise indicated)
			Calculation
Instrument	Financial Covenant ⁽¹⁾	Requirement/Restriction	June 30, 2016
TEC
Credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		46.2%
Accounts receivable credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		46.2%
NMGC
Credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		29.1%
3.54% and 4.87% senior unsecured notes	Debt/capital	Cannot exceed 65%		29.1%
NMGI
2.71% and 3.64% senior unsecured notes	Debt/capital	Cannot exceed 65%		46.1%
TECO Energy/TECO Finance
Credit facility - 2013 $300 million ⁽²⁾	Debt/capital	Cannot exceed 65%		62.4%
Credit facility - 2016 $400 million ⁽²⁾	Debt/capital	Cannot exceed 65%		62.4%

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

Net fair value of derivatives as of Dec. 31, 2015	$	(26.0	)
Additions and net changes in unrealized fair value of derivatives		6.6
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		23.8
Net fair value of derivatives as of June 30, 2016	$	4.4

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		6.2
Recorded in earnings		0.0
Realized net settlement of derivatives		23.8
Option premium payments		0.4
Net fair value of derivatives as of June 30, 2016	$	4.4

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⁾		3.0		1.4		4.4
Model prices⁽²⁾		0.0		0.0		0.0
Total	$	3.0	$	1.4	$	4.4

	Total Number of		Average Price		Total Number of Shares		Maximum Number (or
	Shares (or Units)		Paid per Share		(or Units) Purchased as		Approximate Dollar Value)
	Purchased⁽¹⁾		(or Unit)		Part of Publicly		of Shares (or Units) that
					Announced Plans or		May Yet Be Purchased
					Programs		Under the Plans or
							Programs
Apr. 1, 2016 - Apr. 30, 2016		348	$	27.75	0		0
May 1, 2016 - May 31, 2016		4,109	$	27.55	0		0
June 1, 2016 - June 30, 2016		323	$	27.70	0		0
Total 2nd Quarter 2016		4,780	$	27.57		0		0

	TECO ENERGY, INC.
	(Registrant)

Date: August 8, 2016	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

	TAMPA ELECTRIC COMPANY
	(Registrant)

Date: August 8, 2016	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)