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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of ~~July 31, 2015~~April 29, 2016 was ~~235,215,710.~~235,550,000. As of ~~July 31, 2015,~~April 29, 2016, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

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

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

Assets	June 30,			Dec. 31,			Mar. 31,			Dec. 31,
(millions)	2015			2014			2016			2015
Current assets
Cash and cash equivalents	$	56.0		$	25.4		$	46.1		$	23.8
Receivables, less allowance for uncollectibles of $2.2 and $2.1 at June 30, 2015 and Dec. 31, 2014, respectively		273.3			299.8
Receivables, less allowance for uncollectibles of $2.1 and $2.1 at Mar. 31, 2016 and Dec. 31, 2015, respectively								240.1			280.7
Inventories, at average cost
Fuel	132.7			96.4			118.3			113.4
Materials and supplies		75.8			75.4			77.1			76.8
Derivative assets		0.6			0.0
Regulatory assets		39.4			53.6			40.2			44.8
Deferred income taxes		73.4			72.8
Prepayments and other current assets		31.5			22.6			25.4			30.8
Assets held for sale		96.5			109.6
Total current assets		779.2			755.6			547.2			570.3

Property, plant and equipment
Utility plant in service
Electric		7,217.1			7,094.8			7,328.3			7,270.3
Gas		2,055.2			1,984.6			2,154.1			2,113.8
Construction work in progress		648.0			640.0			816.9			794.7
Other property		14.8			14.5			16.1			15.9
Property, plant and equipment, at original costs		9,935.1			9,733.9			10,315.4			10,194.7
Accumulated depreciation		(2,693.4	)		(2,645.7	)		(2,762.4	)		(2,712.9	)
Total property, plant and equipment, net		7,241.7			7,088.2			7,553.0			7,481.8

Other assets
Regulatory assets		343.3			348.5			393.4			395.2
Goodwill		408.4			408.3			408.4			408.4
Deferred charges and other assets		65.8			65.8			79.1			77.8
Assets held for sale		0.0			59.8
Total other assets		817.5			882.4			880.9			881.4
Total assets	$	8,838.4		$	8,726.2		$	8,981.1		$	8,933.5

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

Liabilities and Capital	June 30,			Dec. 31,			Mar. 31,			Dec. 31,
(millions)	2015			2014			2016			2015
Current liabilities
Long-term debt due within one year	$	333.3		$	274.5		$	83.3		$	333.3
Notes payable		85.5			139.0			513.0			247.0
Accounts payable		258.2			288.6			189.5			255.4
Customer deposits		179.5			176.2			176.7			182.1
Regulatory liabilities		49.9			57.0			108.4			84.8
Derivative liabilities		24.4			36.6			22.3			24.1
Interest accrued		38.1			39.9			54.0			36.2
Taxes accrued		46.0			29.9			28.2			13.2
Other		16.7			16.8			25.2			22.6
Liabilities associated with assets held for sale		30.2			39.4
Total current liabilities		1,061.8			1,097.9			1,200.6			1,198.7

Other liabilities
Deferred income taxes		573.1			519.2			607.0			570.7
Investment tax credits		8.8			9.0			10.4			10.5
Regulatory liabilities		713.2			729.0			709.4			715.8
Derivative liabilities		1.9			6.1			0.8			2.1
Deferred credits and other liabilities		341.5			370.9			380.9			387.5
Liabilities associated with assets held for sale		66.3			65.4
Long-term debt, less amount due within one year		3,518.5			3,354.0			3,489.7			3,489.2
Total other liabilities		5,223.3			5,053.6			5,198.2			5,175.8

Commitments and contingencies (see Note 10)

Capital
Common equity (400.0 million shares authorized; par value $1; 235.1 million and 234.9 million shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively)		235.1			234.9
Common equity (400.0 million shares authorized; par value $1; 235.5 million and 235.3 million shares outstanding at Mar. 31, 2016 and Dec. 31, 2015, respectively)								235.5			235.3
Additional paid in capital		1,885.7			1,875.9			1,894.8			1,894.5
Retained earnings		443.5			479.6			463.5			441.4
Accumulated other comprehensive loss		(11.0	)		(15.7	)		(11.5	)		(12.2	)
Total capital		2,553.3			2,574.7			2,582.3			2,559.0
Total liabilities and capital	$	8,838.4		$	8,726.2		$	8,981.1		$	8,933.5

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

		Three months ended June 30,							Three months ended Mar. 31,
(millions, except per share amounts)		2015			2014				2016			2015
Revenues
Regulated electric and gas		$	678.2		$	603.6
Regulated electric									$	423.4		$	449.7
Regulated gas										232.9			240.2
Unregulated			2.4			2.1				3.2			3.1
Total revenues			680.6			605.7				659.5			693.0
Expenses
Regulated operations and maintenance
Fuel			171.8			169.7				115.2			144.1
Purchased power			19.6			19.9				14.4			17.1
Cost of natural gas sold			49.1			29.1				96.8			103.0
Other			155.4			126.8				142.3			143.7
Operations and maintenance other expense			1.1			4.6
Operation and maintenance other expense										0.0			1.6
Depreciation and amortization			87.0			75.5				89.8			85.5
Taxes, other than income			53.3			48.1				52.9			51.8
Total expenses			537.3			473.7				511.4			546.8
Income from operations			143.3			132.0				148.1			146.2
Other income
Allowance for other funds used during construction			3.7			2.0				5.7			3.8
Other income, net			1.4			(0.5	)			1.5			1.6
Total other income			5.1			1.5				7.2			5.4
Interest charges
Interest expense			48.2			41.4				48.9			49.8
Allowance for borrowed funds used during construction			(1.8	)		(0.7	)			(3.0	)		(1.9	)
Total interest charges			46.4			40.7				45.9			47.9
Income from continuing operations before provision for income taxes			102.0			92.8				109.4			103.7
Provision for income taxes			40.5			35.2				35.7			39.9
Net income from continuing operations			61.5			57.6				73.7			63.8
Discontinued operations
Income (loss) from discontinued operations			(78.1	)		0.0				0.2			(9.6	)
Benefit from income taxes			(28.4	)		(0.8	)
Income (loss) on discontinued operations, net			(49.7	)		0.8
Provision (benefit) from income taxes										0.1			(3.8	)
Income (loss) from discontinued operations, net										0.1			(5.8	)
Net income		$	11.8		$	58.4			$	73.8		$	58.0
Average common shares outstanding	– Basic		233.0			215.4		– Basic		234.0			232.8
	– Diluted		233.6			215.9		– Diluted		235.2			233.5
Earnings per share from continuing operations	– Basic	$	0.26		$	0.27		– Basic	$	0.31		$	0.27
	– Diluted	$	0.26		$	0.27		– Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations	– Basic	$	(0.21	)	$	0.00		– Basic	$	0.00		$	(0.02	)
	– Diluted	$	(0.21	)	$	0.00		– Diluted	$	0.00		$	(0.02	)
Earnings per share	– Basic	$	0.05		$	0.27		– Basic	$	0.31		$	0.25
	– Diluted	$	0.05		$	0.27		– Diluted	$	0.31		$	0.25
Dividends paid per common share outstanding		$	0.225		$	0.220			$	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)

2015

2014

Revenues

Regulated electric and gas

$
1,368.1

$
1,179.3

Unregulated

5.5

4.4

Total revenues

1,373.6

1,183.7

Expenses

Regulated operations and maintenance

Fuel

315.9

319.3

Purchased power

36.7

38.1

Cost of natural gas sold

152.1

76.2

Other

299.1

247.4

Operation and maintenance other expense

2.7

7.8

Depreciation and amortization

172.5

151.4

Taxes, other than income

105.1

95.9

Total expenses

1,084.1

936.1

Income from operations

289.5

247.6

Other income

Allowance for other funds used during construction

7.5

4.4

Other income, net

3.0

(1.4
)
Total other income

10.5

3.0

Interest charges

Interest expense

98.0

82.4

Allowance for borrowed funds used during construction

(3.7
)

(2.1
)
Total interest charges

94.3

80.3

Income from continuing operations before provision for
income taxes

205.7

170.3

Provision for income taxes

80.4

64.3

Net income from continuing operations

125.3

106.0

Discontinued operations

Income (loss) from discontinued operations

(87.7
)

1.2

Benefit from income taxes

(32.2
)

(1.3
)
Income (loss) from discontinued operations, net

(55.5
)

2.5

Net income

$
69.8

$
108.5

Average common shares outstanding
– Basic

232.9

215.3

– Diluted

233.5

215.8

Earnings per share from continuing operations
– Basic

$
0.53

$
0.49

– Diluted

$
0.53

$
0.49

Earnings per share from discontinued operations
– Basic

$
(0.23
)

$
0.01

– Diluted

$
(0.23
)

$
0.01

Earnings per share
– Basic

$
0.30

$
0.50

– Diluted

$
0.30

$
0.50

Dividends paid per common share outstanding

$
0.45

$
0.44

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

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

	Six months ended June 30,						Three months ended Mar. 31,
(millions)	2015			2014			2016			2015
Cash flows from operating activities
Net income	$	69.8		$	108.5		$	73.8		$	58.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		173.3			169.1			89.8			85.9
Deferred income taxes and investment tax credits		46.9			61.8			36.1			36.0
Allowance for other funds used during construction		(7.5	)		(4.4	)		(5.7	)		(3.8	)
Non-cash stock compensation		6.9			7.1			3.0			3.9
Gain on sales of business/assets		0.0			(0.1	)
Deferred recovery clauses		(4.1	)		(14.4	)		26.4			(5.7	)
Asset impairment, pretax		78.6			0.0
Receivables, less allowance for uncollectibles		39.8			(36.6	)		40.6			51.0
Inventories		(37.2	)		(16.2	)		(5.2	)		(15.7	)
Prepayments and other current assets		(12.2	)		(2.1	)		2.8			(10.9	)
Taxes accrued		19.0			34.3			18.1			1.7
Interest accrued		(1.8	)		2.5			17.8			17.8
Accounts payable		(58.3	)		(36.0	)		(59.1	)		(63.5	)
Other		(16.4	)		(12.5	)		(6.8	)		(7.7	)
Cash flows from operating activities		296.8			261.0			231.6			147.0
Cash flows from investing activities
Capital expenditures		(343.2	)		(320.3	)		(168.0	)		(156.2	)
Allowance for other funds used during construction		7.5			4.4
Other investing activities		(0.1	)		0.3			(0.2	)		(0.2	)
Cash flows used in investing activities		(335.8	)		(315.6	)		(168.2	)		(156.4	)
Cash flows from financing activities
Dividends		(105.9	)		(95.9	)
Dividends and dividend equivalents								(54.3	)		(53.0	)
Proceeds from the sale of common stock		3.5			3.0			3.9			2.8
Proceeds from long-term debt issuance		500.0			296.6
Repayment of long-term debt		(274.5	)		(83.3	)
Net decrease in short-term debt		(53.5	)		(84.0	)
Cash flows from financing activities		69.6			36.4
Net increase (decrease) in cash and cash equivalents		30.6			(18.2	)
Repayment of long-term debt/purchase in lieu of redemption								(250.0	)		0.0
Net increase (decrease) in short-term debt (maturities of 90 days or less)								(134.0	)		67.0
Proceeds from other short-term debt (maturities over 90 days)								400.0			0.0
Other financing activities								(6.7	)		0.0
Cash flows from (used in) financing activities								(41.1	)		16.8
Net increase in cash and cash equivalents								22.3			7.4
Cash and cash equivalents at beginning of the period		25.4			185.2			23.8			25.4
Cash and cash equivalents at end of the period	$	56.0		$	167.0		$	46.1		$	32.8
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	1.6		$	8.6		$	(6.0	)	$	11.5

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

See TECO Energy, Inc.’s ~~2014~~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, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, and the results of operations and cash flows for the periods ended ~~June 30, 2015~~Mar. 31, 2016 and ~~2014.~~2015. The results of operations for the three ~~and six~~ months ended ~~June 30, 2015~~Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, ~~2015.~~

The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through June 30, 2015. In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly related to TECO Coal and TECO Guatemala (see ~~Note 15~~).2016.

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

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

As of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, unbilled revenues of ~~$66.7~~$67.3 million and ~~$86.6~~$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 ~~$29.3~~$27.9 million and ~~$56.6~~$27.4 million ~~respectively,~~ for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~compared to $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014.~~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.

Presentation of ~~TECO Energy’s total excise taxes, which are accrued~~Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an ~~expense~~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 ~~reconciled~~is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the ~~actual~~company classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash ~~payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.~~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 expects to adopt this guidance effective Jan. 1, 2018, and is ~~currently evaluating~~continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of ~~Debt Issuance Costs~~Financial Assets and Financial Liabilities

In ~~April 2015,~~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 ~~presentation~~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 ~~debt issuance costs~~more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. ~~Under the new~~Recognition of expenses for both operating and finance leases will be similar to existing guidance ~~an entity is required to present debt issuance costs~~and as a ~~direct deduction from~~result is expected to limit the ~~carrying amount~~impact of the ~~related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance.~~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 ~~2016~~2019, with early adoption permitted, and will be ~~required to be~~ applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on ~~a retrospective basis for all periods presented. As of June 30, 2015, $30.5 million of debt~~its financial statements.

~~issuance costs are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet.~~

~~Disclosure of Investments Using Net Asset Value~~Derivative Contract Novations

In ~~May 2015,~~March 2016, the FASB issued guidance ~~stating~~clarifying that ~~investments for which fair value is measured using the NAV per share practical expedient should not be categorized~~a change in the ~~fair value hierarchy but should be~~counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided ~~to reconcile to total investments on the balance sheet. In addition, the guidance clarifies~~ that ~~a plan sponsor’s pension assets are eligible~~all other hedge accounting criteria continue to be ~~measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in~~ ~~Note 5~~ ~~of its~~ ~~2014 Annual Report on Form 10-K. This standard will be~~met. The guidance is effective for the company beginning in ~~2016~~2017, with early adoption permitted, and ~~will be required to~~may be applied on a prospective or modified retrospective ~~basis for all periods presented.~~basis. The guidance will not affect the company’s current financial statements. However, the company ~~is considering adopting~~will assess the ~~standard for its 2015 fiscal year, as early adoption is permitted.~~impact of this guidance on future derivative contract novations, if any.

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 as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	June 30, 2015		Dec. 31, 2014		Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	71.7	$	69.2	$	77.1	$	74.7
Other:
Cost-recovery clauses		27.0		45.1
Postretirement benefit asset ⁽²⁾		188.8		194.0
Deferred bond refinancing costs ⁽³⁾		6.8		7.2
Debt basis adjustment ⁽³⁾		19.2		20.9
Environmental remediation		52.5		53.1
Cost-recovery clauses - deferred balances⁽²⁾						0.1		5.5
Cost-recovery clauses - offsets to derivative liabilities ⁽²⁾						26.0		26.5
Environmental remediation ⁽³⁾						54.4		54.0
Postretirement benefits ⁽⁴⁾						238.5		240.6
Deferred bond refinancing costs ⁽⁵⁾						6.2		6.5
Debt basis adjustment ⁽⁶⁾						16.7		17.5
Competitive rate adjustment(2)		2.5		2.8		2.5		2.6
Other		14.2		9.8		12.1		12.1
Total other regulatory assets		311.0		332.9
Total regulatory assets		382.7		402.1		433.6		440.0
Less: Current portion		39.4		53.6		40.2		44.8
Long-term regulatory assets	$	343.3	$	348.5	$	393.4	$	395.2
Regulatory liabilities:
Regulatory tax liability ⁽¹⁾	$	6.3	$	6.9
Other:
Cost-recovery clauses		20.6		25.9
Regulatory tax liability					$	7.6	$	7.9
Cost-recovery clauses⁽²⁾						80.0		55.9
Transmission and delivery storm reserve		56.1		56.1		56.1		56.1
Deferred gain on property sales ⁽⁴⁾		0.2		0.8
Accumulated reserve - cost of removal		679.1		695.2
Accumulated reserve - cost of removal ⁽⁷⁾						673.6		679.9
Other		0.8		1.1		0.5		0.8
Total other regulatory liabilities		756.8		779.1
Total regulatory liabilities		763.1		786.0		817.8		800.6
Less: Current portion		49.9		57.0		108.4		84.8
Long-term regulatory liabilities	$	713.2	$	729.0	$	709.4	$	715.8

~~All regulatory assets~~to FPSC and NMPRC clauses and riders. They are ~~recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:~~

The effective tax rate ~~increased~~decreased to ~~39.09%~~32.63% for the ~~six~~three months ended ~~June 30, 2015~~Mar. 31, 2016 from ~~37.76%~~38.48% for the same period in ~~2014~~2015 primarily due to the tax ~~expense~~benefit related to long-term incentive compensation ~~shares that vested below target levels.~~share vestings (see Note 2 for further description).

The company’s ~~U.S.~~ subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s ~~2013~~2014 consolidated federal income tax return in ~~January~~December 2015. The U.S. federal statute of limitations remains open for the year ~~2011~~2012 and forward. Years ~~2014~~2015 and ~~2015~~2016 are currently under examination by the IRS under its Compliance Assurance Program. ~~TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015.~~ 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						Pension Benefits						Other Postretirement Benefits
Three months ended June 30,	2015			2014			2015			2014
Three months ended Mar. 31,													2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	6.4		$	4.2		$	0.5		$	0.6		$	4.4		$	4.5		$	0.5		$	0.6
Interest cost		8.7			8.2			2.1			2.6			8.1			7.4			2.2			2.0
Expected return on assets		(12.5	)		(10.4	)		(0.2	)		0.0			(11.3	)		(10.8	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.1	)		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		4.8			3.5			0.0			0.1			3.4			3.4			0.0			0.0
Regulatory asset		0.0			0.0			0.2			0.0			0.0			0.0			0.2			0.3
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	7.4		$	5.4		$	2.0		$	3.2		$	4.6		$	4.4		$	2.0		$	2.0
Six months ended June 30,
Components of net periodic benefit expense
Service cost	$	10.9		$	8.3		$	1.1		$	1.2
Interest cost		16.1			16.4			4.1			5.2
Expected return on assets		(23.3	)		(20.7	)		(0.5	)		0.0
Amortization of:
Prior service (benefit) cost		(0.1	)		(0.2	)		(1.2	)		(0.1	)
Actuarial loss		8.2			6.7			0.0			0.1
Regulatory asset		0.0			0.0			0.5			0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	11.8		$	10.5		$	4.0		$	6.4

For the fiscal ~~2015~~2016 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of ~~4.256%~~4.685% for pension benefits under its qualified pension plan. For the Jan. 1, ~~2015~~2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of ~~4.206%.~~4.667% for the Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of ~~$24.5~~$4.7 million and ~~$26.5~~$14.9 million to its pension plan for the ~~six~~three months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~and 2014,~~ respectively.

For the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, TECO Energy and its subsidiaries reclassified ~~$1.4~~$0.8 million ~~and $2.2 million, respectively,~~ of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit ~~expense, compared with $0.7 million and $1.3 million for the three and six months ended June 30, 2014, respectively.~~expense. In addition, during the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, the regulated companies reclassified ~~$3.0~~$2.2 million ~~and $5.2 million, respectively,~~ of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit ~~expense, compared with $2.7 million and $5.2 million during the three and six months ended June 30, 2014, respectively.~~expense.

TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. TECO Coal applies the accounting guidance of ASC 715, Compensation – Retirement Benefits, and annual expense is recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially-computed liability for such benefits over the employee’s applicable term of service. At June 30, 2015 and Dec. 31, 2014, TECO Coal had an actuarially-determined black lung liability of $25.0 million and $24.7 million, respectively. Expense related to the black lung liability recognized during the three and six months ended June 30, 2015 and 2014 was not material.

~~As discussed in~~ ~~Note 15~~, TECO Coal was classified as an asset held for sale at June 30, 2015. In accordance with ASC 715, an after-tax settlement charge of approximately $7.7 million related to the unfunded black lung obligations recorded in AOCI will be recognized as a loss from discontinued operations upon completion of the sale of TECO Coal, which is expected to occur in 2015.

At ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, the following credit facilities and related borrowings existed:

Credit Facilities
	June 30, 2015						Dec. 31, 2014						Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters						Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325.0	$	0.0	$	0.6	$	325.0	$	12.0	$	0.6	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts receivable facility ⁽³⁾		150.0		0.0		0.0		150.0		46.0		0.0		150.0		0.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility ⁽²⁾⁽⁴⁾		300.0		75.0		0.0		300.0		50.0		0.0		300.0		113.0		0.0		300.0		163.0		0.0
1-year term facility ⁽⁴⁾⁽⁵⁾														400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility⁽²⁾		125.0		10.5		1.7		125.0		31.0		1.7		125.0		0.0		1.7		125.0		23.0		1.7
Total	$	900.0	$	85.5	$	2.3	$	900.0	$	139.0	$	2.3	$	1,300.0	$	513.0	$	2.2	$	900.0	$	247.0	$	2.2

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

At ~~June 30, 2015,~~Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~2015 was ~~1.23%~~1.44% and ~~1.16%~~1.29%, respectively.

~~Tampa Electric Company Accounts Receivable~~TECO Energy/TECO Finance Credit Facility

On Mar. ~~24, 2015, TEC~~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 ~~TRC amended~~warranties, events of default, and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders,financial and other covenants; and (iii) ~~extend~~ provides for interest to accrue at variable rates based on the ~~scheduled termination date from Apr. 14, 2015~~London interbank deposit rate plus a margin, or, as an alternative to ~~Mar. 23, 2018, by entering into (a)~~such interest rate, at an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivablesinterest rate equal to a margin plus the ~~borrowings outstanding in~~higher of JPMorgan Chase Bank’s prime rate, the ~~case of default. TEC continues to service, administer and collect~~federal funds rate plus 50 basis points, or the ~~pledged receivables, which are classified as receivables on the balance sheet. As of June 30, 2015, TEC was in compliance with the requirements of the agreement.~~one-month London interbank deposit rate plus 1.00%.

At ~~June 30,~~Mar. 31, 2016, total long-term debt had a carrying amount of $3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of ~~$3,851.8~~$3,822.5 million and an estimated fair market value of ~~$4,136.2 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8~~$4,061.6 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued

using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 ~~instruments.~~ instruments (see Note 13 for information regarding the fair value hierarchy).

~~Issuance~~Purchase in Lieu of ~~TEC 4.20% Notes due 2045~~Redemption of Revenue Refunding Bonds

On ~~May 20, 2015, TEC completed an offering of $250~~Mar. 19, 2008, the HCIDA remarketed $86.0 million ~~aggregate principal amount of 4.20% Notes due May 15, 2045~~HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (the ~~Notes). The Notes were sold at 99.814% of par. The offering resulted~~Series 2006 HCIDA Bonds) in ~~net proceeds~~a term rate mode pursuant to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any partthe terms of the ~~Notes at its option at any time~~Loan and ~~from time to time~~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 ~~price equal~~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 ~~greater of (i) 100%~~terms of the ~~principal amount~~Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of ~~Notes~~2.00% per annum will apply from Mar. 15, 2016 to ~~be redeemed or (ii)~~Mar. 15, 2020. The 2016 mandatory tender did not impact the ~~sum~~Consolidated Condensed Balance Sheet. TEC is responsible for payment of the ~~present value of~~interest and principal associated with the ~~remaining payments of~~Series 2006 HCIDA Bonds. Regularly scheduled principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100%when due, are insured by Ambac Assurance Corporation.

As of ~~the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.~~

On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018. The 2018 Notes will bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points, which is payable quarterly on Jan. 10, Apr. 10, July 10 and Oct. 10 of each year, beginning July 10, 2015. Interest on the 2018 Notes will be computed on the basis of the actual number of days elapsed over a 360-day year. The 2018 Notes will not be subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness. TECO Finance is a wholly owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment at maturity of $191Mar. 31, 2016, $232.6 million of ~~TECO Finance notes due~~bonds purchased in ~~May 2015.~~ 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 for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014,~~ related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
		Three months ended June 30,							Six months ended June 30,										Three months ended Mar. 31,
(millions)		Gross		Tax			Net		Gross			Tax			Net				Gross		Tax			Net
2016
Unrealized gain on cash flow hedges																			$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income ⁽¹⁾																				0.3		(0.1	)		0.2
Gain on cash flow hedges																				0.3		(0.1	)		0.2
Amortization of unrecognized benefit costs ⁽²⁾																				0.8		(0.3	)		0.5
Total other comprehensive income																			$	1.1	$	(0.4	)	$	0.7
2015
Unrealized gain on cash flow hedges		$	4.0	$	(1.4	)	$	2.6	$	4.3		$	(1.5	)	$	2.8			$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income ⁽¹⁾			0.3		(0.1	)		0.2		0.7			(0.4	)		0.3				0.4		(0.2	)		0.2
Gain on cash flow hedges			4.3		(1.5	)		2.8		5.0			(1.9	)		3.1				0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs ⁽²⁾			1.6		(0.6	)		1.0		2.5			(0.9	)		1.6				0.9		(0.3	)		0.6
Total other comprehensive income (loss)		$	5.9	$	(2.1	)	$	3.8	$	7.5		$	(2.8	)	$	4.7
2014
Unrealized gain on cash flow hedges		$	0.1	$	0.0		$	0.1	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income ⁽¹⁾			0.1		(0.1	)		0.0		0.5			(0.2	)		0.3
Gain on cash flow hedges			0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Amortization of unrecognized benefit costs ⁽²⁾			0.8		(0.3	)		0.5		1.6			(0.6	)		1.0
Decrease (increase) in unrecognized postemployment costs ⁽³⁾			0.0		0.0			0.0		(12.9	)		4.7			(8.2	)
Total other comprehensive income (loss)		$	1.0	$	(0.4	)	$	0.6	$	(10.8	)	$	3.9		$	(6.9	)
Total other comprehensive income																			$	1.6	$	(0.7	)	$	0.9

(1) Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations.
(1) Related to interest rate contracts recognized in Interest expense.																		(1) Related to interest rate contracts recognized in Interest expense.
(2) Related to postretirement and postemployment benefits. See Note 5 for additional information.	(2) Related to postretirement and postemployment benefits. See Note 5 for additional information.																	(2) Related to postretirement and postemployment benefits. See Note 5 for additional information.
(3) Amounts reflect an out-of-period adjustment related to TECO Coal's unfunded black lung liability.

Accumulated Other Comprehensive Loss
(millions)	June 30, 2015			Dec. 31, 2014				Mar. 31, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit ⁽¹⁾	$	(21.0	)	$	(22.5	)		$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and transition obligations ⁽²⁾		14.0			13.9				25.5			25.6
Net unrealized gains (losses) from cash flow hedges ⁽³⁾		(4.0	)		(7.1	)
Net unrealized losses from cash flow hedges ⁽³⁾									(3.4	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.0	)	$	(15.7	)		$	(11.5	)	$	(12.2	)

(1) Net of tax benefit of $12.9 million and $13.8 million as of June 30, 2015 and Dec. 31, 2014, respectively.
(2) Net of tax expense of $8.3 million and $8.3 million as of June 30, 2015 and Dec. 31, 2014, respectively. Balance includes a $7.7 million loss as of June 30, 2015 related to TECO Coal's unfunded black lung liability that will be reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 15.
(3) Net of tax benefit of $2.5 million and $4.5 million as of June 30, 2015 and Dec. 31, 2014, respectively.
(1) Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.							(1) Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(2) Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.							(2) Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(3) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.							(3) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

	For the three months ended June 30,						For the six months ended June 30,						For the three months ended Mar. 31,
(millions, except per share amounts)	2015			2014 ⁽¹⁾			2015			2014 ⁽¹⁾			2016			2015
Basic earnings per share
Net income from continuing operations	$	61.5		$	57.6		$	125.3		$	106.0		$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.4	)		(0.1	)		(0.2	)
Income before discontinued operations available to common shareholders - Basic	$	61.3		$	57.4		$	124.9		$	105.6		$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	(49.7	)	$	0.8		$	(55.5	)	$	2.5		$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Basic	$	(49.7	)	$	0.8		$	(55.5	)	$	2.5		$	0.1		$	(5.8	)
Net income	$	11.8		$	58.4		$	69.8		$	108.5		$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.4	)		(0.1	)		(0.2	)
Net income available to common shareholders - Basic	$	11.6		$	58.2		$	69.4		$	108.1		$	73.7		$	57.8
Average common shares outstanding - Basic		233.0			215.4			232.9			215.3			234.0			232.8
Earnings per share from continuing operations available to common shareholders - Basic	$	0.26		$	0.27		$	0.53		$	0.49		$	0.31		$	0.27
Earnings per share from discontinued operations available to common shareholders - Basic	$	(0.21	)	$	0.0		$	(0.23	)	$	0.01			0.0		$	(0.02	)
Earnings per share available to common shareholders - Basic	$	0.05		$	0.27		$	0.30		$	0.50		$	0.31		$	0.25
Diluted earnings per share
Net income from continuing operations	$	61.5		$	57.6		$	125.3		$	106.0		$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.4	)		(0.1	)		(0.2	)
Income before discontinued operations available to common shareholders - Diluted	$	61.3		$	57.4		$	124.9		$	105.6		$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	(49.7	)	$	0.8		$	(55.5	)	$	2.5		$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders - Diluted	$	(49.7	)	$	0.8		$	(55.5	)	$	2.5		$	0.1		$	(5.8	)
Net income	$	11.8		$	58.4		$	69.8		$	108.5		$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.4	)		(0.1	)		(0.2	)
Net income available to common shareholders - Diluted	$	11.6		$	58.2		$	69.4		$	108.1		$	73.7		$	57.8
Unadjusted average common shares outstanding - Diluted		233.0			215.4			232.9			215.3			234.0			232.8
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.6			0.5			0.6			0.5
Assumed conversion of stock options, unvested restricted stock, unvested RSUs and contingent performance shares, net														1.2			0.7
Average common shares outstanding - Diluted		233.6			215.9			233.5			215.8			235.2			233.5
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.26		$	0.27		$	0.53		$	0.49		$	0.31		$	0.27
Earnings per share from discontinued operations available to common shareholders - Diluted	$	(0.21	)	$	0.0		$	(0.23	)	$	0.01			0.0		$	(0.02	)
Earnings per share available to common shareholders - Diluted	$	0.05		$	0.27		$	0.30		$	0.50		$	0.31		$	0.25
Anti-dilutive shares		0.4			0.0			0.3			0.0			0.2			0.1
(1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 15).

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 ~~its~~a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

A thirty-six year old man died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and fourteen other defendants alleges, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. This case is scheduled for trial in the fall of 2015.

A thirty-three year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence. Plaintiffs' case against Tampa Electric alleges, among other things, negligence and loss of consortium. Discovery is currently ongoing in the case.

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently ~~scheduled for the fourth quarter of 2015.~~expected in October 2016.

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.”

~~The two purported~~In September 2015, a settlement was reached with all the named plaintiff class ~~action suits (three purported classes) were consolidated. The court dismissed~~representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Mar. 31, 2016.

In addition to the two settled class actions ~~in their entirety with prejudice in October 2014 and appeals from the dismissal were taken by the plaintiffs in November 2014 and are pending.~~

~~Eighteen~~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. ~~These~~In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation ~~matters are pending~~lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.

Twelve securities class action lawsuits were filed against the company and ~~discovery is proceeding. NMGC has filed motions to dismiss similar to those~~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 ~~actions.~~action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

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

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

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.

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, ~~Inc.,~~ 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. If

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 ~~is successful,~~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 ~~will be able~~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 ~~from Guatemala in a~~(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.

While the duration of the annulment proceedings is uncertain, a hearing is scheduled in October 2015 with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results 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, 2015,~~Mar. 31, 2016, TEC has estimated its ultimate financial liability to be ~~$33.3~~$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.

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, 2015~~Mar. 31, 2016 is as follows:


(millions)	Year of expiration						Maximum										Maximum
					After ⁽¹⁾		Theoretical		Liabilities Recognized						After ⁽¹⁾		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2015		2016-2019		2019		Obligation		at June 30, 2015 ⁽²⁾		2016		2017-2020		2020		Obligation		at Mar. 31, 2016
TECO Energy
Fuel sales and transportation(2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits ⁽³⁾												89.4		0.0		0.0		89.4		0.0
											$	89.4	$	0.0	$	92.9	$	182.3	$	0.0

							Maximum										Maximum
(millions)					After ⁽¹⁾		Theoretical		Liabilities Recognized						After ⁽¹⁾		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2015		2016-2019		2019		Obligation		at June 30, 2015 ⁽³⁾		2016		2017-2020		2020		Obligation		at Mar. 31, 2016 ⁽⁴⁾
TEC	$	0.0	$	0.0	$	0.6	$	0.6	$	0.1	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC	$	0.0	$	0.0	$	1.7	$	1.7	$	0.0		0.0		0.0		1.7		1.7		0.0
											$	0.0	$	0.0	$	2.2	$	2.2	$	0.1
(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019.
(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, 2015. See Note 12 for additional information.
(3) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at June 30, 2015. 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.

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

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, 2015,~~Mar. 31, 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

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

2014

Revenues - external
$
512.5

$
90.7

$
0.0

$
0.0

$
2.5

$
0.0

$
605.7

Sales to affiliates

0.2

0.4

0.0

0.0

0.1

(0.7
)

0.0

Total revenues

512.7

91.1

0.0

0.0

2.6

(0.7
)

605.7

Depreciation and amortization

61.7

13.4

0.0

0.0

0.4

0.0

75.5

Total interest charges

23.3

3.4

0.0

0.0

15.9

(1.9
)

40.7

Internally allocated interest

0.0

0.0

0.0

0.0

1.9

(1.9
)

0.0

Provision (benefit) for income taxes

37.1

4.8

0.0

0.0

(6.7
)

0.0

35.2

Net income (loss) from continuing operations

62.2

7.5

0.0

0.0

(12.1
)

0.0

57.6

Income (loss) from discontinued operations, net ⁽¹⁾

0.0

0.0

0.0

0.8

0.0

0.0

0.8

Net income (loss)
$
62.2

$
7.5

$
0.0

$
0.8

$
(12.1
)

$
0.0

58.4

(millions)	Tampa		Peoples		New Mexico		TECO									TECO
Six months ended June 30,	Electric		Gas		Gas Co. ⁽²⁾		Coal ⁽¹⁾			Other ^{(2) (3)}			Eliminations ⁽³⁾			Energy
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 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
2014
Three months ended Mar. 31,																			Tampa Electric		PGS		NMGC ⁽²⁾		TECO Coal ⁽¹⁾			Other ^{(2) (3)}			Eliminations ⁽³⁾				TECO Energy
2016
Revenues - external	$	965.4	$	213.1	$	0.0	$	0.0		$	5.2		$	0.0		$	1,183.7		$	423.4	$	126.8	$	106.6	$	0.0		$	2.7		$	0.0			$	659.5
Sales to affiliates		0.5		0.6		0.0		0.0			0.1			(1.2	)		0.0			1.1		4.4		0.0		0.0			0.0			(5.5	)			0.0
Total revenues		965.9		213.7		0.0		0.0			5.3			(1.2	)		1,183.7			424.5		131.2		106.6		0.0			2.7			(5.5	)			659.5
Depreciation and amortization		123.8		26.7		0.0		0.0			0.9			0.0			151.4			66.1		14.8		8.4		0.0			0.5			0.0				89.8
Total interest charges		45.3		6.8		0.0		0.0			31.9			(3.7	)		80.3			23.8		3.7		3.0		0.0			15.6			(0.2	)			45.9
Internally allocated interest		0.0		0.0		0.0		0.0			3.7			(3.7	)		0.0			0.0		0.0		0.0		0.0			0.2			(0.2	)			0.0
Provision (benefit) for income taxes		63.7		14.0		0.0		0.0			(13.4	)		0.0			64.3			27.8		8.9		9.7		0.0			(10.7	)		0.0				35.7
Net income (loss) from continuing operations		107.4		22.1		0.0		0.0			(23.5	)		0.0			106.0			50.2		13.1		15.2		0.0			(4.8	)		0.0				73.7
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0		(0.8	)		3.3			0.0			2.5			0.0		0.0		0.0		0.0			0.1			0.0				0.1
Net income (loss)	$	107.4	$	22.1	$	0.0	$	(0.8	)	$	(20.2	)	$	0.0		$	108.5		$	50.2	$	13.1	$	15.2	$	0.0		$	(4.7	)	$	0.0			$	73.8
At June 30, 2015
2015
Revenues - external																			$	449.8	$	121.7	$	119.0	$	0.0		$	2.5		$	0.0			$	693.0
Sales to affiliates																				0.8		1.2		0.0		0.0			0.0			(2.0	)			0.0
Total revenues																				450.6		122.9		119.0		0.0			2.5			(2.0	)			693.0
Depreciation and amortization																				62.9		13.9		8.4		0.0			0.3			0.0				85.5
Total interest charges																				23.5		3.5		3.3		0.0			17.9			(0.3	)			47.9
Internally allocated interest																				0.0		0.0		0.0		0.0			0.3			(0.3	)			0.0
Provision (benefit) for income taxes																				27.4		9.2		9.0		0.0			(5.7	)		0.0				39.9
Net income (loss) from continuing operations																				48.2		14.6		13.9		0.0			(12.9	)		0.0				63.8
Income (loss) from discontinued operations, net ⁽¹⁾																				0.0		0.0		0.0		(6.0	)		0.2			0.0				(5.8	)
Net income (loss)																			$	48.2	$	14.6	$	13.9	$	(6.0	)	$	(12.7	)	$	0.0			$	58.0
At Mar. 31, 2016
Total assets	$	6,739.5	$	1,089.2	$	1,180.2	$	173.0		$	1,701.7		$	(2,045.2	)	$	8,838.4		$	6,988.2	$	1,147.0	$	1,210.9	$	0.0		$	1,982.1		$	(2,347.1	)	⁽⁴⁾	$	8,981.1
At Dec. 31, 2014
Total assets	$	6,565.4	$	1,082.8	$	1,237.2	$	227.7		$	1,611.6		$	(1,998.5	)		8,726.2
(1) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to TECO Coal and TECO Guatemala. See Note 15.
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.																			(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.	(2) NMGI is included in the Other segment.																		(2) NMGI is included in the Other segment.
(3) Certain prior year amounts have been reclassified to conform to current year presentation.	(3) Certain prior year amounts have been reclassified to conform to current year presentation.																		(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.																			(4) Amounts primarily relate to intercompany advances and consolidated tax eliminations.

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.~~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, 2015,~~Mar. 31, 2016, all of the company’s physical contracts qualify for the NPNS ~~exception.~~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, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled ~~$0.6~~$0.0 million and $0$0.2 million as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, respectively, and ~~derivative~~are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative liabilities totaled ~~$26.3~~$23.1 million and ~~$42.7~~$26.2 million as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~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, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~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, 2015,~~Mar. 31, 2016, net pretax losses of ~~$23.8~~$22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~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,~~Mar. 31, 2016 and 2015, ~~and 2014,~~ 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

~~the~~ three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ is presented in Note 8. These gains and losses were the result of interest rate contracts for ~~TEC and diesel fuel derivatives related to TECO Coal operations.~~TEC. The ~~locations~~location of the ~~reclassifications~~reclassification to income ~~were~~was reflected in ~~Interest expense~~“Interest expense” for ~~TEC and Income (loss) from discontinued operations for TECO Coal.~~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, 2017~~Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of ~~June 30, 2015,~~Mar. 31, 2016, are expected to settle during the ~~2015,~~ 2016, 2017 and ~~2017~~2018 fiscal years:

Derivative Volumes	Natural Gas Contracts				Natural Gas Contracts
(millions)	(MMBTUs)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2015		0.0		21.3
2016		0.0		15.7		0.0		25.1
2017		0.0		1.8		0.0		9.9
2018						0.0		0.7
Total		0.0		38.8		0.0		35.7

The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of ~~June 30, 2015,~~Mar. 31, 2016, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

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

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

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 of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014.~~2015. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

	As of June 30, 2015								As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.6	$	0.0	$	0.6	$	0.0	$	0.2	$	0.0	$	0.2

Liabilities
Natural gas derivatives	$	0.0	$	26.3	$	0.0	$	26.3	$	0.0	$	26.2	$	0.0	$	26.2

	As of Dec. 31, 2014
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas derivatives	$	0.0	$	42.7	$	0.0	$	42.7

The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and ~~options~~forwards are estimated utilizing the market ~~and income approach, respectively.~~approach. The price of swaps isand 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, 2015,~~Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

~~In the~~The determination of a VIE’s ~~primary beneficiary, the~~ 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.

or ~~benefits and hence remain the primary beneficiaries.~~benefits. As a result, ~~TEC~~Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. ~~TEC~~Tampa Electric purchased ~~$9.9~~$12.6 million and ~~$15.3~~$5.4 million ~~of capacity pursuant to~~under these PPAs for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~respectively, and $7.0 million and $12.8 million for the three and six months ended June 30, 2014,~~ 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.

~~In September 2014, the Board of Directors of~~On Sept. 21, 2015, TECO Energy authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014.

~~On Oct. 17, 2014,~~Energy’s subsidiary, TECO Diversified, entered into an SPA ~~to sell~~and completed the sale of all of its ownership interest in TECO Coal to ~~Cambrian Coal Corporation. On Feb. 5, 2015, the~~Cambrian. The SPA ~~was amended to extend the closing date to Mar. 13, 2015 and modify the~~did not provide for an up-front purchase ~~price to $80 million, subject to working capital adjustments, plus~~payment, but provides for future contingent ~~payments~~consideration of up to $60 million that may be paid ~~between 2015 and~~yearly through 2019 ~~depending on specified~~if certain coal benchmark ~~prices. In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale~~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 ~~their implied fair value based on~~TECO Coal reclamation bonds will remain in effect until the price per the amended SPA less estimated costs to sell. On Mar. 12, 2015, the SPA was further amended to extend the closing date to Apr. 24, 2015. On Apr. 17, 2015, the SPA was amended again to further extend the closing date to June 5, 2015. The closing did not occur on June 5, 2015, and the SPA was not terminatedbonds are replaced by ~~either party. Management continues~~Cambrian, which is expected to be completed in ~~active discussions with interested parties~~2016 (see description of guarantees in ~~an effort~~Note 10). The SPA contained customary representations, warranties and covenants (see Note 10 for description of a claim related to ~~complete~~ the ~~sale; however, based on management’s assessment~~SPA). The income shown for the first quarter of ~~current market conditions and the discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded~~2016 in the ~~second quarter~~table below reflects a refund of ~~2015, which includes~~prepaid costs.

~~After~~ closing of the sale, ~~which management expects to occur in 2015,~~ TECO Energy ~~will~~does not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal.

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

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 ~~2015~~ charges shown in the table below are legal costs associated with that claim. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

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

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

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

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

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

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

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

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

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

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

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

Assets	June 30,			Dec. 31,			Mar. 31,			Dec. 31,
(millions)	2015			2014			2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,217.1		$	7,094.8		$	7,328.3		$	7,270.3
Gas		1,359.0			1,308.9			1,419.3			1,398.6
Construction work in progress		633.2			624.2			797.0			771.1
Utility plant in service, at original costs		9,209.3			9,027.9			9,544.6			9,440.0
Accumulated depreciation		(2,668.8	)		(2,633.8	)		(2,720.3	)		(2,676.8	)
Utility plant in service, net		6,540.5			6,394.1			6,824.3			6,763.2
Other property		8.9			8.6			9.9			9.7
Total property, plant and equipment, net		6,549.4			6,402.7			6,834.2			6,772.9

Current assets
Cash and cash equivalents		33.9			10.4			28.2			9.1
Receivables, less allowance for uncollectibles of $1.5 and $1.4 at June 30, 2015 and Dec. 31, 2014, respectively		251.6			227.2
Receivables, less allowance for uncollectibles of $1.6 and $1.5 at Mar. 31, 2016 and Dec. 31, 2015, respectively								205.5			230.2
Inventories, at average cost
Fuel		127.0			85.2			115.4			105.6
Materials and supplies		72.5			72.2			73.6			73.1
Regulatory assets		39.3			52.1			39.9			44.3
Taxes receivable from affiliate		0.0			43.3			0.0			61.3
Deferred income taxes		21.0			24.8
Prepayments and other current assets		23.6			17.4			17.0			21.5
Total current assets		568.9			532.6			479.6			545.1

Deferred debits
Unamortized debt expense		18.7			16.8
Regulatory assets		316.9			319.6			373.1			373.8
Other		2.4			2.6			17.9			16.8
Total deferred debits		338.0			339.0			391.0			390.6
Total assets	$	7,456.3		$	7,274.3		$	7,704.8		$	7,708.6

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

Liabilities and Capitalization	June 30,			Dec. 31,			Mar. 31,			Dec. 31,
(millions)	2015			2014			2016			2015
Capitalization
Common stock	$	2,160.4		$	2,130.4		$	2,330.4		$	2,305.4
Accumulated other comprehensive loss		(4.0	)		(7.1	)		(3.4	)		(3.6	)
Retained earnings		334.4			305.8			314.4			313.7
Total capital		2,490.8			2,429.1			2,641.4			2,615.5
Long-term debt		2,179.9			2,013.8			2,162.0			2,161.7
Total capitalization		4,670.7			4,442.9			4,803.4			4,777.2

Current liabilities
Long-term debt due within one year		83.3			83.3			83.3			83.3
Notes payable		0.0			58.0			0.0			61.0
Accounts payable		231.4			242.3			174.6			221.6
Customer deposits		173.7			170.4			170.9			176.3
Regulatory liabilities		49.5			54.7			104.5			83.2
Derivative liabilities		24.4			36.6			22.2			24.1
Interest accrued		19.0			17.0			41.2			16.9
Taxes accrued		62.2			12.4			33.6			13.2
Other		10.0			10.0			10.1			10.2
Total current liabilities		653.5			684.7			640.4			689.8

Deferred credits
Deferred income taxes		1,240.5			1,209.1			1,342.0			1,308.8
Investment tax credits		8.8			9.0			10.4			10.5
Derivative liabilities		1.9			6.1			0.8			2.1
Regulatory liabilities		604.5			623.4			595.5			603.5
Deferred credits and other liabilities		276.4			299.1			312.3			316.7
Total deferred credits		2,132.1			2,146.7			2,261.0			2,241.6

Commitments and Contingencies (see Note 8)

Total liabilities and capitalization	$	7,456.3		$	7,274.3		$	7,704.8		$	7,708.6

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

	Three months ended June 30,						Three months ended Mar. 31,
(millions)	2015			2014			2016			2015
Revenues
Electric	$	532.4		$	512.7		$	424.2		$	450.4
Gas		92.2			90.6			126.8			121.7
Total revenues		624.6			603.3			551.0			572.1
Expenses
Regulated operations and maintenance
Fuel		171.8			169.7			115.1			144.1
Purchased power		19.6			19.9			14.4			17.1
Cost of natural gas sold		30.1			29.0			50.3			43.3
Other		134.3			126.8			121.2			121.8
Depreciation and amortization		78.0			75.1			80.9			76.8
Taxes, other than income		49.5			47.6			48.5			47.6
Total expenses		483.3			468.1			430.4			450.7
Income from operations		141.3			135.2			120.6			121.4
Other income
Allowance for other funds used during construction		3.7			2.0			5.6			3.8
Other income, net		1.2			1.1			1.3			1.2
Total other income		4.9			3.1			6.9			5.0
Interest charges
Interest on long-term debt		27.8			26.4			29.0			27.7
Other interest		1.2			1.0
Interest expense								1.2			1.1
Allowance for borrowed funds used during construction		(1.8	)		(0.7	)		(2.7	)		(1.8	)
Total interest charges		27.2			26.7			27.5			27.0
Income before provision for income taxes		119.0			111.6			100.0			99.4
Provision for income taxes		43.7			41.9			36.7			36.6
Net income		75.3			69.7			63.3			62.8
Other comprehensive income, net of tax
Gain on cash flow hedges		2.8			0.0			0.2			0.3
Total other comprehensive income, net of tax		2.8			0.0			0.2			0.3
Comprehensive income	$	78.1		$	69.7		$	63.5		$	63.1

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

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

	Six months ended June 30,						Three months ended Mar. 31,
(millions)	2015			2014			2016			2015
Cash flows from operating activities
Net income	$	138.1		$	129.5		$	63.3		$	62.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		154.8			150.5			80.9			76.8
Deferred income taxes and investment tax credits		30.0			34.8			30.4			21.2
Allowance for funds used during construction		(7.5	)		(4.4	)		(5.6	)		(3.8	)
Deferred recovery clauses		(3.2	)		(14.4	)		27.0			(4.7	)
Receivables, less allowance for uncollectibles		(24.4	)		(29.1	)		24.7			13.5
Inventories		(42.1	)		(2.6	)		(10.3	)		(21.1	)
Prepayments		(6.2	)		(2.8	)		4.6			(5.0	)
Taxes accrued		93.1			100.5			81.7			72.7
Interest accrued		2.0			2.2			24.3			22.9
Accounts payable		(14.3	)		(34.3	)		(41.2	)		(28.3	)
Other		(14.9	)		(10.6	)		(11.6	)		(6.9	)
Cash flows from operating activities		305.4			319.3			268.2			200.1
Cash flows from investing activities
Capital expenditures		(319.9	)		(312.7	)		(150.5	)		(148.8	)
Allowance for funds used during construction		7.5			4.4
Net proceeds from sale of assets		0.0			0.1
Cash flows used in investing activities		(312.4	)		(308.2	)		(150.5	)		(148.8	)
Cash flows from financing activities
Common stock		30.0			17.0			25.0			20.0
Proceeds from long-term debt issuance		251.3			296.6
Repayment of long-term debt		(83.3	)		(83.3	)
Net decrease in short-term debt		(58.0	)		(84.0	)		(61.0	)		(11.0	)
Dividends		(109.5	)		(112.0	)		(62.6	)		(55.7	)
Cash flows from financing activities		30.5			34.3
Cash flows used in financing activities								(98.6	)		(46.7	)
Net increase in cash and cash equivalents		23.5			45.4			19.1			4.6
Cash and cash equivalents at beginning of period		10.4			9.8			9.1			10.4
Cash and cash equivalents at end of period	$	33.9		$	55.2		$	28.2		$	15.0
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	1.5		$	8.6		$	(4.8	)	$	11.4

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

See TEC’s ~~2014~~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, Inc.~~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, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, and the results of operations and cash flows for the periods ended ~~June 30, 2015~~Mar. 31, 2016 and ~~2014.~~2015. The results of operations for the three ~~and six~~ months ended ~~June 30, 2015~~Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, ~~2015.~~2016.

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

As of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, unbilled revenues of ~~$60.3~~$56.8 million and ~~$49.3~~$53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

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

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

Recognition and Measurement of ~~Debt Issuance Costs~~Financial Assets and Financial Liabilities

In ~~April 2015,~~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 ~~presentation~~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 ~~debt issuance costs~~more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. ~~Under the new~~Recognition of expenses for both operating and finance leases will be similar to existing guidance ~~an entity is required to present debt issuance costs~~and as a ~~direct deduction from~~result is expected to limit the ~~carrying amount~~impact of the ~~related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance.~~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 ~~2016~~2019, with early adoption permitted, and will be ~~required to be~~ applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on ~~a retrospective basis for all periods presented. As of June 30, 2015, $18.7 million of debt issuance costs are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet.~~its financial statements.

~~Disclosure of Investments Using Net Asset Value~~Derivative Contract Novations

In ~~May 2015,~~March 2016, the FASB issued guidance ~~stating~~clarifying that ~~investments for which fair value is measured using the NAV per share practical expedient should not be categorized~~a change in the ~~fair value hierarchy but should be~~counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided ~~to reconcile to total investments on the balance sheet. In addition, the guidance clarifies~~ that ~~a plan sponsor’s pension assets are eligible~~all other hedge accounting criteria continue to be ~~measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in~~ ~~Note 5~~ ~~of TEC’s~~ ~~2014 Annual Report on Form 10-K. This standard will be~~met. The guidance is effective for TEC beginning in ~~2016~~2017, with early adoption permitted, and ~~will be required to~~may be applied on a prospective or modified retrospective ~~basis for all periods presented.~~basis. The guidance will not affect TEC’s current financial statements. However, TEC ~~is considering adopting~~will assess the ~~standard for its 2015 fiscal year, as early adoption is permitted.~~impact of this guidance on future derivative contract novations, if any.

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 as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	June 30, 2015		Dec. 31, 2014		Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	71.7	$	69.2	$	77.0	$	74.6
Other:
Cost-recovery clauses		27.0		43.6
Postretirement benefit asset ⁽²⁾		183.1		187.8
Deferred bond refinancing costs⁽³⁾		6.8		7.2
Environmental remediation		52.5		53.1
Cost-recovery clauses - deferred balances ⁽²⁾						0.0		5.2
Cost-recovery clauses - offsets to derivative liabilities⁽²⁾						25.9		26.2
Environmental remediation⁽³⁾						54.4		54.0
Postretirement benefits ⁽⁴⁾						236.4		238.3
Deferred bond refinancing costs⁽⁵⁾						6.2		6.5
Competitive rate adjustment(2)		2.5		2.8		2.5		2.6
Other		12.6		8.0		10.6		10.7
Total other regulatory assets		284.5		302.5
Total regulatory assets		356.2		371.7		413.0		418.1
Less: Current portion		39.3		52.1		39.9		44.3
Long-term regulatory assets	$	316.9	$	319.6	$	373.1	$	373.8
Regulatory liabilities:
Regulatory tax liability⁽¹⁾	$	4.6	$	5.1
Other:
Cost-recovery clauses		20.2		23.5
Regulatory tax liability					$	5.6	$	5.7
Cost-recovery clauses ⁽²⁾						76.1		54.2
Transmission and delivery storm reserve		56.1		56.1		56.1		56.1
Deferred gain on property sales ⁽⁴⁾		0.2		0.8
Accumulated reserve - cost of removal		572.3		591.5
Provision for stipulation and other		0.6		1.1
Total other regulatory liabilities		649.4		673.0
Accumulated reserve - cost of removal⁽⁶⁾						561.7		570.0
Other						0.5		0.7
Total regulatory liabilities		654.0		678.1		700.0		686.7
Less: Current portion		49.5		54.7		104.5		83.2
Long-term regulatory liabilities	$	604.5	$	623.4	$	595.5	$	603.5

~~All regulatory assets~~to FPSC clauses and riders. They are ~~recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:~~

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~~three months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s ~~2013~~2014 consolidated federal income tax return in ~~January~~December 2015. The U.S. federal statute of limitations remains open for the year ~~2011~~2012 and forward. Years ~~2014~~2015 and ~~2015~~2016 are currently under examination by the IRS under its Compliance Assurance Program. ~~TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015.~~ 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 ~~Inc.~~ Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~and 2014,~~ respectively, was ~~$4.2~~$2.9 million and ~~$3.9~~$2.6 million for pension benefits, and $1.5 million and $2.6 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2015 and 2014, respectively, was $6.8 million and $7.7 million for pension benefits, and $2.9 million and $5.2$1.4 million for other postretirement benefits.

For the fiscal ~~2015~~2016 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of ~~4.256%~~4.685%. For the Jan. 1, ~~2015~~2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of ~~4.206%~~4.667%. Additionally, TECO Energy made contributions of ~~$24.5~~$4.7 million and ~~$26.5~~$14.9 million to its pension plan in the ~~six~~three months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~and 2014,~~ respectively. TEC’s portion of the contributions was ~~$18.5~~$3.9 million and ~~$21.5~~$11.0 million, respectively.

Included in the benefit expenses discussed above, for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, TEC reclassified ~~$2.8~~$2.0 million and ~~$4.7~~$1.9 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net ~~income, compared with $2.7 million and $5.2 million for the three and six months ended June 30, 2014, respectively.~~income.

At ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~2015, the following credit facilities and related borrowings existed:

Credit Facilities
	June 30, 2015						Dec. 31, 2014						Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters						Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
Tampa Electric Company:
5-year facility ⁽²⁾	$	325.0	$	0.0	$	0.6	$	325.0	$	12.0	$	0.6	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts receivable facility ⁽³⁾		150.0		0.0		0.0		150.0		46.0		0.0		150.0		0.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0.0	$	0.6	$	475.0	$	58.0	$	0.6	$	475.0	$	0.0	$	0.5	$	475.0	$	61.0	$	0.5

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of June 30, 2015, TEC was in compliance with the requirements of the agreement.

At ~~June 30,~~Mar. 31, 2016, TEC’s total long-term debt had a carrying amount of $2,245.3 million and an estimated fair market value of $2,483.1 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of ~~$2,263.2~~$2,245.0 million and an estimated fair market value of ~~$2,479.6 million. At Dec. 31, 2014, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2~~$2,433.3 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 ~~instruments.~~instruments (see Note 11 for information regarding the fair value hierarchy).

~~Issuance~~Purchase in Lieu of ~~TEC 4.20% Notes due 2045~~Redemption of Revenue Refunding Bonds

On ~~May 20, 2015, TEC completed an offering of $250~~Mar. 19, 2008, the HCIDA remarketed $86.0 million ~~aggregate principal amount of 4.20% Notes due May 15, 2045~~HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (the ~~Notes). The Notes were sold at 99.814% of par. The offering resulted~~Series 2006 HCIDA Bonds) in ~~net proceeds~~a term-rate mode pursuant to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any partthe terms of the ~~Notes at its option at any time~~Loan and ~~from time to time~~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 ~~price equal~~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 ~~greater of (i) 100%~~terms of the ~~principal amount~~Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of ~~Notes~~2.00% per annum will apply from Mar. 15, 2016 to ~~be redeemed or (ii)~~Mar. 15, 2020. The 2016 mandatory tender did not impact the ~~sum~~Consolidated Condensed Balance Sheet. TEC is

responsible for payment of the ~~present value of~~interest and principal associated with the ~~remaining payments of~~Series 2006 HCIDA Bonds. Regularly scheduled principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.when due, are insured by Ambac Assurance Corporation.

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

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

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 ~~fourth quarter~~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 ~~2015.~~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 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.

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of ~~June 30, 2015~~Mar. 31, 2016 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After ⁽¹⁾				Liabilities Recognized						After ⁽¹⁾				Liabilities Recognized
Letters of Credit for the Benefit of:	2015		2016-2019		2019		Total		at June 30, 2015		2016		2017-2020		2020		Total		at Mar. 31, 2016
TEC ⁽²⁾	$	0.0	$	0.0	$	0.6	$	0.6	$	0.1	$	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 2019.
(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, 2015. 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.
(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.											(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.											(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

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, 2015,~~Mar. 31, 2016, TEC was in compliance with all applicable financial covenants.

(millions)	Tampa		Peoples					Tampa Electric		Tampa							Tampa Electric
Three months ended June 30,	Electric		Gas		Eliminations			Company
2015
Three months ended Mar. 31,										Electric		PGS		Eliminations			Company
2016
Revenues - external	$	532.4	$	92.2	$	0.0		$	624.6	$	424.2	$	126.8	$	0.0		$	551.0
Sales to affiliates		0.0		1.3		(1.3	)		0.0
Intracompany sales											0.3		4.4		(4.7	)		0.0
Total revenues		532.4		93.5		(1.3	)		624.6		424.5		131.2		(4.7	)		551.0
Depreciation and amortization		64.0		14.0		0.0			78.0		66.1		14.8		0.0			80.9
Total interest charges		23.6		3.6		0.0			27.2		23.8		3.7		0.0			27.5
Provision for income taxes		38.9		4.8		0.0			43.7		27.8		8.9		0.0			36.7
Net income		67.7		7.6		0.0			75.3	$	50.2	$	13.1	$	0.0		$	63.3
2014
2015
Revenues - external	$	512.6	$	90.7	$	0.0		$	603.3	$	450.4	$	121.7	$	0.0		$	572.1
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Intracompany sales											0.2		1.2		(1.4	)		0.0
Total revenues		512.7		91.1		(0.5	)		603.3		450.6		122.9		(1.4	)		572.1
Depreciation and amortization		61.7		13.4		0.0			75.1		62.9		13.9		0.0			76.8
Total interest charges		23.3		3.4		0.0			26.7		23.5		3.5		0.0			27.0
Provision for income taxes		37.1		4.8		0.0			41.9		27.4		9.2		0.0			36.6
Net income	$	62.2	$	7.5	$	0.0		$	69.7	$	48.2	$	14.6	$	0.0		$	62.8
Six months ended June 30,
2015
Revenues - external	$	982.8	$	213.9	$	0.0		$	1,196.7
Sales to affiliates		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
2014
Revenues - external	$	965.7	$	213.1	$	0.0		$	1,178.8
Sales to affiliates		0.2		0.6		(0.8	)		0.0
Total revenues		965.9		213.7		(0.8	)		1,178.8
Depreciation and amortization		123.8		26.7		0.0			150.5
Total interest charges		45.3		6.8		0.0			52.1
Provision for income taxes		63.7		14.0		0.0			77.7
Net income	$	107.4	$	22.1	$	0.0		$	129.5
Total assets at June 30, 2015	$	6,406.3	$	1,055.7	$	(5.7	)	$	7,456.3
Total assets at Dec. 31, 2014		6,234.4		1,047.0		(7.1	)		7,274.3
Total assets at Mar. 31, 2016										$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Total assets at Dec. 31, 2015 ⁽¹⁾											6,620.2		1,097.7		(9.3	)		7,708.6

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, 2015,~~Mar. 31, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~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~~There were no derivative assets ~~totaled $0~~ as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014, and derivative~~2015. Derivative liabilities totaled ~~$26.3~~$23.0 million and ~~$42.7~~$26.2 million as of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014,~~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, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~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, 2015,~~Mar. 31, 2016, net pretax losses of ~~$24.4~~$22.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014~~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, 2017~~Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of ~~June 30, 2015,~~Mar. 31, 2016, are expected to settle during the ~~2015,~~ 2016, 2017 and ~~2017~~2018 fiscal years:

	Natural Gas Contracts				Natural Gas Contracts
(millions)	(MMBTUs)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2015		0.0		18.8
2016		0.0		11.3		0.0		25.1
2017		0.0		1.8		0.0		9.9
2018						0.0		0.7
Total		0.0		31.9		0.0		35.7

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

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

financial loss. However, as of ~~June 30, 2015,~~Mar. 31, 2016, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

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

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

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 of ~~June 30, 2015~~Mar. 31, 2016 and Dec. 31, ~~2014.~~2015. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Derivative Fair Value Measures
	As of June 30, 2015								As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.3	$	0.0	$	26.3	$	0.0	$	23.0	$	0.0	$	23.0

	As of Dec. 31, 2014								As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	42.7	$	0.0	$	42.7	$	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, 2015,~~Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Other Comprehensive Income	Three months ended June 30,							Six months ended June 30,							Three months ended Mar. 31,
(millions)	Gross		Tax			Net		Gross		Tax			Net		Gross		Tax			Net
2016
Unrealized gain on cash flow hedges															$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income																0.3		(0.1	)		0.2
Gain on cash flow hedges																0.3		(0.1	)		0.2
Total other comprehensive income															$	0.3	$	(0.1	)	$	0.2
2015
Unrealized gain on cash flow hedges	$	4.0	$	(1.4	)	$	2.6	$	4.3	$	(1.5	)	$	2.8	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income		0.3		(0.1	)		0.2		0.7		(0.4	)		0.3		0.4		(0.2	)		0.2
Gain on cash flow hedges		4.3		(1.5	)		2.8		5.0		(1.9	)		3.1		0.7		(0.4	)		0.3
Total other comprehensive income	$	4.3	$	(1.5	)	$	2.8	$	5.0	$	(1.9	)	$	3.1	$	0.7	$	(0.4	)	$	0.3
2014
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.0		0.0			0.0		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.0		0.0			0.0		0.4		(0.2	)		0.2
Total other comprehensive income	$	0.0	$	0.0		$	0.0	$	0.4	$	(0.2	)	$	0.2

Accumulated Other Comprehensive Loss
(millions)	June 30, 2015			Dec. 31, 2014			Mar. 31, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges ⁽¹⁾	$	(4.0	)	$	(7.1	)	$	(3.4	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(4.0	)	$	(7.1	)	$	(3.4	)	$	(3.6	)

~~TEC~~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 ~~159~~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. ~~TEC~~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 and hence remain the primary beneficiaries.~~benefits. As a result, ~~TEC~~Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. ~~TEC~~Tampa Electric purchased ~~$9.9~~$12.6 million and ~~$15.3~~$5.4 million ~~of capacity pursuant to~~under these PPAs for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015, ~~respectively, and $7.0 million and $12.8 million for the three and six months ended June 30, 2014,~~ 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.

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

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 ~~Management’s~~Managements Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: the ability to successfully close the Merger with Emera on the anticipated schedule, if at all; regulatory actions by federal, state or local authorities; the ability to successfully implement the integration plans for NMGC and generate the expected financial ~~results to make the acquisition accretive;~~results; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or ~~failures; the ability of TECO Energy to successfully close the sale of TECO Coal on the anticipated terms, or otherwise exit the coal business.~~failures. Additional information is contained under "Risk Factors" in TECO Energy, Inc.'s Annual Report on Form 10-K for the period ended Dec. 31, ~~2014.~~2015.

	Three Months Ended June 30, 2015					Six Months Ended June 30, 2015					Three Months Ended Mar. 31,
(millions) Except per-share amounts	2015			2014		2015			2014		2016		2015
Consolidated revenues	$	680.6		$	605.7	$	1,373.6		$	1,183.7	$	659.5	$	693.0
Net income from continuing operations		61.5			57.6		125.3			106.0		73.7		63.8
Income (loss) on discontinued operations, net		(49.7	)		0.8		(55.5	)		2.5
Loss on discontinued operations, net												0.1		(5.8	)
Net income		11.8			58.4		69.8			108.5		73.8		58.0
Average common shares outstanding
Basic		233.0		215.4		232.9			215.3			234.0	232.8
Diluted	233.6			215.9		233.5			215.8		235.2		233.5
Earnings per share – basic
Continuing operations	$	0.26		$	0.27	$	0.53		$	0.49	$	0.31	$	0.27
Discontinued operations		(0.21	)		0.0		(0.23	)		0.01		0.00		(0.02	)
Earnings per share - basic	$	0.05		$	0.27	$	0.30		$	0.50	$	0.31	$	0.25
Earnings per share – diluted
Continuing operations	$	0.26		$	0.27	$	0.53		$	0.49	$	0.31	$	0.27
Discontinued operations		(0.21	)		0.0		(0.23	)		0.01		0.00		(0.02	)
Earnings per share - diluted	$	0.05		$	0.27	$	0.30		$	0.50	$	0.31	$	0.25

~~Second-quarter 2015~~First-quarter 2016 net income was ~~$11.8~~$73.8 million, or ~~$0.05~~$0.31 per share, compared with ~~$58.4~~$58.0 million, or ~~$0.27~~$0.25 per share, in the ~~second~~first quarter of ~~2014.~~2015. Net income from continuing operations was ~~$61.5~~$73.7 million, or ~~$0.26~~$0.31 per share, in the ~~2015 second~~2016 first quarter, compared with ~~$57.6~~$63.8 million, or $0.27 per share, for the same period in ~~2014.~~2015. The ~~$49.7 million loss~~first quarter losses in discontinued operations of $5.8 million in ~~the second quarter reflects~~2015 reflected the operating results atand charges associated with TECO Coal, ~~of $1.1 million and net impairment charges of $50.8 million associated with the pending sale of TECO Coal.~~

~~As a result of the previously announced agreement to sell TECO Coal, those operations were classified as discontinued operations effective~~which was sold in ~~the third quarter of 2014~~2015 (see Note 15to the TECO Energy Consolidated Financial Statements~~and the~~ ~~Discontinued Operations~~ ~~section later in this~~ ~~MD&A~~).

Year-to-date net income was $69.8 million, or $0.30 per share, compared with net income of $108.5 million, or $0.50 per share in the 2014 period. Net income from continuing operations was $125.3 million or $0.53 per share, compared with $106.0 million or $0.49 per share in the 2014 period. The $55.5 million loss in discontinued operations in the year-to-date period reflects the $4.7 million operating loss at TECO Coal and net impairment charges discussed above.

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

Tampa Electric’s net income for the ~~second~~first quarter of ~~2015~~2016 was ~~$67.7~~$50.2 million, compared with ~~$62.2~~$48.2 million for the same period in ~~2014.~~2015. Results for the quarter reflected a ~~1.8%~~1.7% higher average number of customers, and higher energy sales primarily due to ~~hotter spring weather.~~the higher number of customers. Results reflected ~~higher~~ operations and maintenance expense slightly higher than 2015, and higher depreciation and interest expenses. ~~Second-quarter~~First-quarter net income in ~~2015~~2016 included ~~$3.6~~$5.6 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with ~~$2.1~~$3.8 million in the ~~2014~~2015 quarter.

Total degree days in Tampa Electric's service area in the ~~second~~first quarter of ~~2015~~2016 were ~~15%~~3% above normal, ~~and 22%~~but 4% below the 2015 period, when degree days were 6% above ~~the 2014 period, driven by very warm weather in April, which is traditionally a shoulder month for energy sales.~~normal. Total net energy for load ~~which~~increased 1.7% in the first quarter of 2016, compared with the same period in 2015. In the 2016 period, pretax base revenues were $6.2 million higher than in 2015, driven by customer growth and higher energy sales. The quarter included more than $1 million of higher pretax base revenue from higher base rates, as a result of the 2013 rate case settlement.

While net energy for load is a calendar measurement of retail energy sales rather than a billing-cycle measurement, ~~increased 6.6% in~~ the ~~second quarter of 2015 compared with~~quarterly energy sales shown on the ~~same~~following table reflect the energy sales based on billing cycles, which can vary period in 2014. In the 2015 period, pretax base revenues were almost $17 million higher than in 2014, driven by weather, customer growth and almost $2 million of higher pretax base revenue from the $7.5 million of higher base rates effective Nov. 1, 2014 as a result of the 2013 rate case settlement. Salesto period. Retail energy sales to residential and commercial customers increased primarily from weather and customer growth. Sales to ~~commercial and~~ non-phosphate industrial customers increased due to ~~hotter weather and~~ the strength of the Tampa area economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was ~~$5.0 million~~slightly higher than in the ~~2014~~2015 quarter, reflecting ~~$2.2 million of~~ higher ~~cost~~costs to safely and reliably operate and maintain the generating, ~~system~~transmission and ~~$1.6 million of higher~~distribution systems, essentially offset by lower employee-related costs, ~~including~~primarily due to the lower level of short-term incentive accruals for all ~~employees.~~employees in 2016 compared to 2015. Depreciation and amortization expense increased ~~$1.4~~$2.0 million in ~~2015,~~2016, as a result of normal additions to facilities to reliably serve ~~customers.~~

~~Year-to-date net income was $115.9 million, compared with $107.4 million in the 2014 period, driven by 1.7% higher average number of~~ customers, ~~higher energy sales from customer growth, more favorable weather~~ and a stronger economy, partially offset by higher operations and maintenance expenses and depreciation expense. Year-to-date net income in 2015 included $7.4 million of AFUDC-equity, compared with $4.4 million in the 2014 period.

~~Year-to-date total degree days in Tampa Electric's service area were 12% above normal, and 18% above the prior year-to-date period. Pretax base revenue was almost $20 million higher than in 2014, including~~ approximately $3 million of higher pretax base revenue as a result of the Nov.1, 2014 base rate increase. In the 2015 year-to-date period, total net energy for load was 4.2% higher than the same period in 2014. Higher energy sales were driven by the same factors as the quarterly sales, and winter weather that was colder than in 2014.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $4.9 million in the 2015 year-to-date period reflecting the same factors as in the second quarter. Compared to the 2014 year-to-date period, depreciation and amortizationinterest expense increased ~~$1.9 million, reflecting additions to facilities to serve customers~~. ~~Interest expense increased $1.1~~$0.7 million due to higher long-term debt balances.

A summary of Tampa Electric’s regulated operating statistics for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ follows: ~~(The quarterly energy sales in the following table reflect the energy sales based on the timing of billing cycles, which can vary period to period.)~~

(millions, except average customers)	Operating Revenues							Kilowatt-hour sales							Operating Revenues								Kilowatt-hour sales
Three months ended June 30,	2015		2014		% Change			2015		2014		% Change
Three months ended Mar. 31,															2016			2015		% Change			2016		2015		% Change
By Customer Type
Residential	$	267.4	$	243.5		9.9			2,330.6		2,089.2		11.6		$	217.4		$	213.4		1.9			1,914.6		1,839.4		4.1
Commercial		154.9		150.2		3.1			1,609.9		1,529.2		5.3			132.8			133.0		(0.2	)		1,388.0		1,350.1		2.8
Industrial – Phosphate		13.8		16.5		(16.4	)		173.2		203.5		(14.9	)		13.1			13.4		(2.4	)		163.5		167.7		(2.5	)
Industrial – Other		27.9		26.6		4.8			319.5		297.4		7.4			25.5			24.8		2.9			297.2		279.4		6.4
Other sales of electricity		44.9		45.6		(1.5	)		456.0		459.1		(0.7	)		39.5			40.5		(2.5	)		401.3		400.1		0.3
Deferred and other revenues ⁽¹⁾		9.3		15.2		(39.0	)									(19.4	)		7.5		(360.2	)
Total energy sales	$	518.2	$	497.6		4.1			4,889.2		4,578.4		6.8		$	408.9		$	432.6		(5.5	)		4,164.6		4,036.7		3.2
Sales for resale		1.0		1.2		(15.4	)		31.2		26.3		18.6			1.4			1.9		(25.8	)		50.3		53.5		(6.0	)
Other operating revenue		13.3		14.0		(5.2	)									14.2			16.1		(11.6	)
Total revenues	$	532.5	$	512.8		3.8			4,920.4		4,604.7		6.9		$	424.5		$	450.6		(5.8	)		4,214.9		4,090.2		3.0
Average customers (thousands)		717.9		705.3		1.8										726.1			714.0		1.7
Retail net energy for load (kilowatt hours)									5,401.2		5,068.8		6.6											4,317.0		4,242.3		1.7

Six months ended June 30,
By Customer Type
Residential	$	480.8	$	457.0		5.2			4,170.0		3,912.1		6.6
Commercial		287.9		285.0		1.0			2,960.1		2,880.1		2.8
Industrial – Phosphate		27.3		33.3		(18.1	)		340.9		411.8		(17.2	)
Industrial – Other		52.7		50.9		3.4			598.9		565.3		5.9
Other sales of electricity		85.4		88.1		(3.0	)		856.1		880.9		(2.8	)
Deferred and other revenues ⁽¹⁾		16.7		13.2		26.4
Total energy sales		950.8		927.5		2.5			8,926.0		8,650.2		3.2
Sales for resale		2.9		8.2		(64.7	)		84.7		132.7		(36.2	)
Other operating revenue		29.4		30.2		(2.8	)
Total revenues	$	983.1	$	965.9		1.8			9,010.7		8,782.9		2.6
Average customers (thousands)		716.0		703.8		1.7
Retail output to line (kilowatt hours)									9,644.9		9,254.0		4.2
(1) Primarily reflects the timing of environmental and fuel clause recoveries.	(1) Primarily reflects the timing of environmental and fuel clause recoveries.														(1) Primarily reflects the timing of environmental and fuel clause recoveries.

PGS reported net income of ~~$7.6~~$13.1 million for the ~~second~~first quarter, ~~essentially unchanged from~~compared with $14.6 million in the ~~2014~~2015 quarter. Average customer growth was ~~2.2%~~2.4% in the ~~quarter, and therm~~quarter. Therm sales to residential customers decreased as a result of ~~much warmer than normal spring weather. Second-quarter~~mild winter weather that was partially offset by customer growth. Sales to commercial customers increased due to customer growth from the stronger economy and increased sales of compressed natural gas to vehicle fleets. Sales to power-generation customers and off-system sales increased, reflecting higher levels of operation by gas-fired generation in the state due to lower natural gas prices. First-quarter results in ~~2015~~2016 reflected ~~slightly lower~~ non-fuel operations and maintenance expense $1.0 million higher than in 2015, driven by ~~the timing of certain activities~~higher operating and compliance costs, partially offset by ~~higher~~lower employee-related costs, ~~including~~primarily due to the lower level of short-term incentive accruals for all ~~employees.~~employees in 2016 compared to 2015. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers. ~~Sales to power-generation customers and off-system sales increased due to coal-to-gas switching by customers and new gas-fired generation in the state.~~

~~PGS reported net income of $22.2 million for the year-to-date period, essentially unchanged from the same period in 2014. Results reflect a 2.1% higher average number of customers,~~ ~~and lower therm sales~~ to residential customers due to warmer than normal spring weather. Commercial therm sales increased due to strong Florida economic conditions. Sales to power generation customers and off-system sales increased due to the same reasons as in the second quarter. Non-fuel operations and maintenance expense increased $0.5 million compared to the 2014 period, when operations and maintenance expense reflected ~~a first quarter recovery of $1.6 million of costs incurred in connection with a 2010 outage incident.~~

A summary of PGS’s regulated operating statistics for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ follows:

(millions, except average customers)	Operating Revenues							Therms							Operating Revenues						Therms
Three months ended June 30,	2015		2014		% Change			2015		2014		% Change
Three months ended Mar. 31,															2016		2015		% Change		2016		2015		% Change
By Customer Type
Residential	$	28.1	$	30.7		(8.4	)		12.5		15.3		(17.8	)	$	50.5	$	49.3		2.5		32.9		34.4		(4.2	)
Commercial		32.5		33.4		(2.7	)		109.9		110.9		(0.9	)		42.8		41.6		2.9		141.1		138.2		2.1
Industrial		3.2		3.3		(2.6	)		70.2		64.8		8.3			3.3		3.2		1.6		83.5		76.1		9.6
Off system sales		14.4		9.4		53.3			46.4		18.5		150.3			12.9		7.8		65.1		53.9		23.4		130.0
Power generation		1.9		1.6		17.1			190.8		148.7		28.3			2.1		1.9		7.9		190.6		184.6		3.2
Other revenues		11.1		10.6		5.3										16.6		16.1		3.0
Total	$	91.2	$	89.0		2.6			429.8		358.2		20.0		$	128.2	$	119.9		6.8		502.0		456.7		9.9
By Sales Type
System supply	$	51.6	$	50.0		3.2			65.7		40.6		61.6		$	75.5	$	69.4		8.6		94.1		66.3		42.0
Transportation		28.5		28.4		0.5			364.1		317.6		14.6			36.1		34.4		5.1		407.9		390.4		4.5
Other revenues		11.1		10.6		5.3										16.6		16.1		3.0
Total	$	91.2	$	89.0		2.6			429.8		358.2		20.0		$	128.2	$	119.9		6.8		502.0		456.7		9.9
Average customers (thousands)		361.7		353.9		2.2										367.5		359.0		2.4

Six months ended June 30,
By Customer Type
Residential	$	77.3	$	80.4		(3.8	)		46.9		48.6		(3.3	)
Commercial		74.1		74.3		(0.2	)		248.1		241.9		2.6
Industrial		6.4		6.9		(6.9	)		146.3		136.8		7.0
Off system sales		22.2		17.8		24.4			69.8		33.9		105.9
Power generation		3.9		3.6		8.9			375.4		304.3		23.3
Other revenues		27.3		26.5		2.6
Total	$	211.2	$	209.5		0.8			886.5		765.5		15.8
By Sales Type
System supply	$	121.0	$	121.7		(0.5	)		132.0		98.1		34.6
Transportation		62.9		61.3		2.6			754.5		667.4		13.1
Other revenues		27.3		26.5		2.6
Total	$	211.2	$	209.5		0.8			886.5		765.5		15.8
Average customers (thousands)		360.4		352.9		2.1

NMGC reported ~~a second quarter loss~~first-quarter net income of ~~$0.1~~$15.2 million, ~~which was less than historical second quarter loss patterns, reflecting~~compared with $13.9 million in the 2015 period. Results reflected the benefit of ~~0.7% customer growth and lower operating~~heating degree days that were almost 3% higher than 2015, but nearly 7% below normal. Growth in the average number of customers in the 2016 quarter was 0.6%. Operating and maintenance ~~expenses~~expense was slightly lower from acquisition ~~synergies.~~

~~NMGC reported year-to-date 2015 net income~~synergies and a focus on cost control. Results included $1.9 million of $13.8 million. Results reflect customer growth of 0.6%, much milder than normal winter weather in the first quarter, and degree days 5.4% below normal and 0.8% below 2014. Results include $0.7 million ofpretax rate credits to customers under the ~~acquisition approval agreement with~~Certification of Stipulation approved by the ~~NMPRC.~~NMPRC in 2014.

A summary of NMGC’s regulated operating statistics for the three ~~and six~~ months ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ follows:

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

(millions, except average customers)
Operating Revenues

Therms

Three months ended June 30,
2015

2014 ⁽¹⁾

% Change

2015

2014 ⁽¹⁾

% Change

By Customer Type

Residential
$
38.2

$
44.9

(14.9
)

38.9

37.0

5.1

Commercial

10.3

14.5

(28.7
)

16.8

17.6

(4.6
)
Industrial

0.1

0.2

(55.0
)

0.2

0.4

(32.4
)
On system transportation

3.7

3.9

(5.8
)

73.4

75.7

(3.1
)
Off system transportation

0.2

0.2

11.0

12.3

11.0

11.2

Other revenues

1.5

1.7

(11.4
)

     Total
$
54.0

$
65.4

(17.4
)

141.6

141.7

(0.1
)
By Sales Type

System supply
$
48.6

$
59.6

(18.4
)

55.9

54.9

1.7

Transportation

3.9

4.1

(5.0
)

85.7

86.8

(1.2
)
Other revenues

1.5

1.7

(11.4
)

     Total
$
54.0

$
65.4

(17.4
)

141.6

141.7

(0.1
)
Average customers (thousands)

515.8

512.3

0.7

Six months ended June 30,

By Customer Type

Residential
$
125.7

$
157.1

(20.0
)

160.1

159.6

0.3

Commercial

33.5

47.4

(29.3
)

57.8

61.6

(6.1
)
Industrial

0.3

0.7

(50.7
)

0.7

1.0

(35.3
)
Off system sales

0.3

2.2

(85.9
)

1.2

4.2

(71.8
)
On system transportation

9.8

10.2

(4.1
)

158.1

173.5

(8.9
)
Off system transportation

0.4

0.4

3.0

22.6

22.1

2.3

Other revenues

3.0

3.2

(6.6
)

     Total
$
173.0

$
221.2

(21.8
)

400.5

422.0

(5.1
)
By Sales Type

System supply
$
159.8

$
207.4

(22.9
)

219.8

226.4

(2.9
)
Transportation

10.2

10.6

(3.8
)

180.7

195.6

(7.6
)
Other revenues

3.0

3.2

(6.6
)

     Total
$
173.0

$
221.2

(21.8
)

400.5

422.0

(5.1
)
Average customers (thousands)

516.3

513.1

0.6

~~(1) Information presented for 2014 is for comparative purposes only, as this was before the date of acquisition (Sept. 2, 2014).~~

The ~~second~~first quarter ~~2015~~2016 cost from continuing operations for Other ~~(net)~~– net of ~~$13.7~~$4.8 million included ~~$0.4~~$0.1 million of costs associated with the ~~integration of NMGC,~~pending Emera transaction, compared with the cost of ~~$12.1~~$12.9 million in ~~2014,~~2015, which included ~~$2.7~~$0.7 million of ~~NMGC related~~NMGC-related integration costs. ~~Results~~First-quarter results in ~~2015 reflect $1.1 million of interest expense at NMGI, and~~2016 reflected a ~~$2.6~~$5.8 million tax ~~expense~~benefit due to an accounting rule change related to ~~long-term~~stock-based incentive compensation, ~~shares that vested below target levels. Results also reflect $1.0 million of interest expense previously allocated to TECO Coal, which was more than offset by~~and lower interest expense as a result of refinancing debt ~~maturities in May.~~maturities.

The 2015 year-to-date cost from continuing operations for Other (net) was $26.6 million, which included $1.0 million of NMGC integration-related costs, compared with $23.5 million in 2014, which included $4.7 million of NMGC acquisition-related costs. Cost drivers in the 2015 year-to-date period included $2.2 million of interest at NMGI, $1.0 million of interest previously allocated to TECO Coal that was not offset by lower interest expense, and the second quarter tax expense related to long-term incentive shares discussed above.

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 ~~second~~sale of TECO Coal closed in September 2015. The $0.1 million first quarter ~~2015 loss of $49.7 million~~gain recorded in discontinued operations reflects ~~TECO Coal’s second quarter operating results~~a refund of ~~$1.1~~prepaid costs recorded in the Other – net segment, compared with a $5.8 million ~~and net impairment charges of $50.8 million associated with~~loss in the ~~pending sale of TECO Coal.~~

~~The year-to-date loss of $55.5 million in discontinued operations reflects~~2015 period, which reflected TECO Coal’s operating ~~loss of $4.7 million and the net impairment charges recorded in the second quarter.~~

~~TECO Energy expects~~results prior to deliver consolidated earnings from continuing operations in a range between $1.08 and $1.11 in 2015, excluding any non-GAAP charges or gains. TECO Energy expects earnings in 2015 to be driven by the factors discussed in previous filings with the SEC.its sale.

On July 16, 2015, in response to market rumors, TECO Energy confirmed that it was exploring strategic alternatives and had retained Morgan Stanley & Co. LLC to advise it in connection with exploring such strategic alternatives. No assurance can be given that TECO Energy will determine to pursue a potential sale or enter into any definitive sale agreement.

The provisions for income taxes from continuing operations for the ~~six~~three month periods ended ~~June 30,~~Mar. 31, 2016 and 2015 ~~and 2014~~ were ~~$80.4~~$35.7 million and ~~$64.3~~$39.9 million, respectively. The provision for income taxes for the ~~six~~three months ended ~~June 30, 2015~~Mar. 31, 2016 was impacted by higher operating ~~income.~~income offset by a tax benefit related to long-term incentive compensation share vestings (see Note 2 to the TECO Energy Consolidated Financial Statements).

The table below sets forth the ~~June 30, 2015~~Mar. 31, 2016 consolidated liquidity and cash balances, the cash balances at the operating companies and ~~TECO Energy parent,~~Parent, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

							TECO Finance								TECO Finance
(millions)	Consolidated		TEC		NMGC		Parent/other		Consolidated		TEC		NMGC		Parent/other
Credit facilities(1)	$	900.0	$	475.0	$	125.0	$	300.0	$	1,300.0	$	475.0	$	125.0	$	700.0
Drawn amounts/LCs		87.8		0.6		12.2		75.0
Drawn amounts/letters of credit⁽¹⁾										515.2		0.5		1.7		513.0
Available credit facilities		812.2		474.4		112.8		225.0		784.8		474.5		123.3		187.0
Cash and short-term investments		56.0		33.9		2.7		19.4		46.1		28.2		3.1		14.8
Total liquidity	$	868.2	$	508.3	$	115.5	$	244.4	$	830.9	$	502.7	$	126.4	$	201.8

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, 2015,~~Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at ~~June 30, 2015.~~Mar. 31, 2016. Reference is made to the specific agreements and instruments for more details.

On ~~Oct. 27, 2014,~~Sept. 8, 2015, S&P ~~placed~~affirmed the issuer credit rating of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance, TEC and NMGC ~~on credit watch with positive implications,~~and revised the outlook to negative from developing, following the announcement of the ~~agreement to sell TECO Coal.~~ pending Merger with Emera.

On ~~July 6,~~Sept. 8, 2015, ~~S&P removed~~Moody’s Investors Service, Inc. announced that the pending Merger with Emera had no immediate impact on the senior unsecured debt ratings of TECO Energy and subsidiaries.

On Sept. 8, 2015, Fitch Ratings affirmed the issuer ~~credit~~default ratings of TECO Energy and the senior unsecured debt rating ~~from credit watch positive~~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 ~~all credit ratings after~~ the ~~expiration~~senior unsecured debt rating of ~~the letter agreement to sell~~its subsidiaries, TECO ~~Coal. S&P~~Finance and TEC. Fitch Ratings also described the ratings outlook as positive on Tampa Electric, NMGC, and TECO Energy. On July 17, 2015, S&P revised the outlook for TECO Energy and its subsidiaries from positive to developing and affirmed all credit ratings in response to TECO Energy’s confirmation that it is exploring strategic alternatives. (See the ~~Strategic Alternatives~~ ~~discussion above.)~~"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 ~~section~~in Item 1A of TECO Energy’s ~~2014~~ Annual Report on Form 10-K)for the year ended Dec. 31, 2015). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

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, 2015,~~Mar. 31, 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 ~~purchase accounting~~ 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, ~~2014.~~2015.

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

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

The ~~CCRs produced at Big Bend include fly ash, FGD gypsum, boiler slag, bottom ash~~FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and ~~economizer ash. The CCRs produced at~~found that further improvements were needed. As a result of this report, the ~~Polk Power Station include gasifier slag and sulfuric acid. Overall, greater than 95%~~OPC filed a petition with the FPSC pointing to the violations of ~~all CCRs produced at these facilities were marketed~~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 ~~beneficial use in commercial and industrial products. The remaining 5% were either disposed~~alleged safety rule violations, with total potential penalties of ~~onsite or shipped offsite~~up to ~~nearby industrial waste landfills in Central Florida.~~

~~The U.S. EPA published~~$3.9 million. On Apr. 18, 2016, PGS reached a new CCR rule in the Federal Register on April 17, 2015 setting federal standards for companies that dispose of CCRs in onsite landfills and impoundments. The rule will go into effect on October 19, 2015 and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliancesettlement regarding this matter with the ~~rule.~~OPC and FPSC staff and agreed to pay a $1.0 million civil penalty and make refunds to customers of $2.0 million. The ~~initial assessment is that activities in 2015 and~~FPSC approved the settlement agreement on May 5, 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. Under current Florida regulation, compliance related expenditures and capital investments related to complying with this new rule would be recoverable under the state’s Environmental Cost Recovery Clause. 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 and it is not possible to predict the ultimate impact on Tampa Electric at this time.

~~On June 29, 2015, the U.S. Supreme Court remanded the EPA’s Mercury and Air Toxics Standard (MATS)~~(see Note 10 to the U.S. District of Columbia Circuit Court for failing to properly consider the cost of compliance. The Circuit Court must now decide whether to vacate or stay the rule and require EPA to submit further cost benefit analysis. Many utilities had already taken steps to comply with the rule; therefore the Supreme Court’s decision is not expected to have a material effect on the utility industry.TECO Energy Consolidated Financial Statements).

All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.

The change in fair value of derivatives is largely due to settlements of natural gas swaps and the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 8%5% from Dec. 31, ~~2014~~2015 to ~~June 30, 2015.~~Mar. 31, 2016. For natural gas, the company maintained a similar volume hedged as of ~~June 30, 2015 from~~Mar. 31, 2016 as compared to Dec. 31, ~~2014.~~2015.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the ~~six~~three month period ended ~~June 30, 2015:~~Mar. 31, 2016:

Net fair value of derivatives as of Dec. 31, 2014	$	(42.7	)
Net fair value of derivatives as of Dec. 31, 2015				$	(26.0	)
Additions and net changes in unrealized fair value of derivatives		(4.6	)		(9.7	)
Changes in valuation techniques and assumptions		0.0			0.0
Realized net settlement of derivatives		21.6			12.6
Net fair value of derivatives as of June 30, 2015	$	(25.7	)
Net fair value of derivatives as of Mar. 31, 2016				$	(23.1	)

Total derivative net assets (liabilities) as of Dec. 31, 2014	$	(42.7	)
Total derivative net assets (liabilities) as of Dec. 31, 2015				$	(26.0	)
Change in fair value of derivative net asset (liabilities):
Recorded as regulatory assets and liabilities or other comprehensive income		(5.2	)		(9.7	)
Recorded in earnings		0.0			0.0
Realized net settlement of derivatives		21.6			12.6
Net option premium payments		0.6
Net fair value of derivatives as of June 30, 2015	$	(25.7	)
Net fair value of derivatives as of Mar. 31, 2016				$	(23.1	)

~~Below is a summary table of sources of fair value, by maturity period, for derivative contracts at June 30, 2015:~~

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)	Current			Non-current			Total Fair Value			Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0		$	0.0		$	0.0		$	0.0
Other external price sources ⁽¹⁾		(23.8	)		(1.9	)		(25.7	)		(22.3	)		(0.8	)		(23.1	)
Model prices⁽²⁾		0.0			0.0			0.0			0.0			0.0			0.0
Total	$	(23.8	)	$	(1.9	)	$	(25.7	)	$	(22.3	)	$	(0.8	)	$	(23.1	)

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.

On Sept. 2, 2014, TECO Energy completed the acquisition of the privately-held NMGI and its wholly owned subsidiary, NMGC. NMGI and NMGC’s business combined constitute 14.2% and 15.1% of the total assets of TECO Energy at June 30, 2015 and Dec. 31, 2014, respectively, and 7.9% and 12.6% of TECO Energy’s revenues for the three and six months ended June 30, 2015, respectively. As permitted by SEC guidance for newly acquired businesses, because it was not possible to complete an effective assessment of the acquired companies’ controls by June 30, 2015, TECO Energy’s management has excluded NMGI and NMGC from its evaluation of disclosure controls and procedures from the date of such acquisition through June 30, 2015. TECO Energy’s management is in the process of reviewing the operations of NMGI and NMGC and implementing TECO Energy’s internal control structure over the acquired operations.

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.

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

TECO Coal is subject to regulation by the Federal MSHA under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in ~~Exhibit 95~~ ~~to this quarterly report.~~

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.

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	¨

Term		Meaning
ABS		asset-backed security
~~ADR~~		~~American depository receipt~~
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
~~BTU~~		~~British Thermal Unit~~
~~CAA~~		~~Federal Clean Air Act~~
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
~~CGESJ~~		~~Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala~~
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
~~EEGSA~~		~~Empresa Eléctrica de Guatemala, S.A.~~
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
~~ERP~~		~~enterprise resource planning~~
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
~~fuel clause~~		~~fuel and purchased power cost-recovery clause, as established by the FPSC~~
GCBF		gas cost billing factor
GHG		greenhouse gas(es)
HAFTA		Highway and Transportation Funding Act
HCIDA		Hillsborough County Industrial Development Authority
~~IASB~~		~~International Accounting Standards Board~~
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

~~Term~~		~~Meaning~~
MD&A		the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
~~Met~~Merger		~~metallurgical~~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
~~MSHA~~		~~Mine Safety and Health Administration~~
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
~~PCIDA~~		~~Polk County Industrial Development Authority~~
PGA		purchased gas adjustment
PGAC		purchased gas adjustment clause
PGS		Peoples Gas System, the gas division of Tampa Electric Company
PM		~~particulate matter~~
PPA		power purchase agreement
PPSA		Power Plant Siting Act
PRP		potentially responsible party
~~PUHCA 2005~~		~~Public Utility Holding Company Act of 2005~~
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
~~RPS~~ ROW		~~renewable portfolio standards~~ 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		~~stock~~Securities Purchase Agreement dated Sept. 21, 2015, by and between TECO Diversified and Cambrian relating to the purchase ~~agreement~~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
~~USACE~~TSI		~~U.S. Army Corps of Engineers~~

~~Term~~		~~Meaning~~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

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
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
2014
Revenues - external	$	512.5	$	90.7	$	0.0		$	0.0		$	2.5		$	0.0		$	605.7
Sales to affiliates		0.2		0.4		0.0			0.0			0.1			(0.7	)		0.0
Total revenues		512.7		91.1		0.0			0.0			2.6			(0.7	)		605.7
Depreciation and amortization		61.7		13.4		0.0			0.0			0.4			0.0			75.5
Total interest charges		23.3		3.4		0.0			0.0			15.9			(1.9	)		40.7
Internally allocated interest		0.0		0.0		0.0			0.0			1.9			(1.9	)		0.0
Provision (benefit) for income taxes		37.1		4.8		0.0			0.0			(6.7	)		0.0			35.2
Net income (loss) from continuing operations		62.2		7.5		0.0			0.0			(12.1	)		0.0			57.6
Income (loss) from discontinued operations, net ⁽¹⁾		0.0		0.0		0.0			0.8			0.0			0.0			0.8
Net income (loss)	$	62.2	$	7.5	$	0.0		$	0.8		$	(12.1	)	$	0.0			58.4

Components of income from discontinued operations	Three months ended						Six months ended
	June 30,						June 30,
(millions)	2015			2014			2015			2014
Revenues—TECO Coal	$	76.1		$	120.6		$	148.8		$	226.7
Income (loss) from operations—TECO Coal		0.5			0.0			(9.0	)		(3.8	)
Loss on impairment—TECO Coal		(78.6	)		0.0			(78.6	)		0.0
Income (loss) from operations—TECO Guatemala		0.0			0.0			(0.1	)		5.0
Loss from discontinued operations—TECO Coal		(78.1	)		0.0			(87.6	)		(3.8	)
Income (loss) from discontinued operations—TECO Guatemala		0.0			0.0			(0.1	)		5.0
Income (loss) from discontinued operations		(78.1	)		0.0			(87.7	)		1.2
Benefit from income taxes		(28.4	)		(0.8	)		(32.2	)		(1.3	)
Income (loss) from discontinued operations, net	$	(49.7	)	$	0.8		$	(55.5	)	$	2.5

(millions, unless otherwise indicated)
			Calculation
Instrument	Financial Covenant ⁽¹⁾	Requirement/Restriction	~~at June 30, 2015~~Mar. 31, 2016
TEC
Credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		~~47.6%~~45.9%
Accounts receivable credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		~~47.6%~~45.9%
6.25% senior notes	Debt/capital Limit on liens ⁽³⁾	Cannot exceed 60% Cannot exceed $700	~~47.6%~~45.9% $0 liens outstanding
NMGC
Credit facility ⁽²⁾	Debt/capital	Cannot exceed 65%		~~29.7%~~28.7%
3.54% and 4.87% senior unsecured notes	Debt/capital	Cannot exceed 65%		~~29.7%~~28.7%
NMGI
2.71% and 3.64% senior unsecured notes	Debt/capital	Cannot exceed 65%		~~47.3%~~45.9%
TECO Energy/TECO Finance
Credit facility - 2013 $300 million ⁽²⁾	Debt/capital	Cannot exceed 65%		~~60.5%~~61.6%
Credit facility - 2016 $400 million ⁽²⁾	Debt/capital	Cannot exceed 65%		61.6%

	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

						Maximum Number (or
				Total Number of Shares		Approximate Dollar Value)
				(or Units) Purchased as		of Shares (or Units) that
	Total Number of		Average Price	Part of Publicly		May Yet Be Purchased
	Shares (or Units)		Paid per Share	Announced Plans or		Under the Plans or
	Purchased⁽¹⁾		(or Unit)		Programs	Programs
Apr. 1, 2015 - Apr. 30, 2015	2,013	$	19.36	0		$	0
May 1, 2015 - May 31, 2015	74,998	$	18.95	0		$	0
June 1, 2015 - June 30, 2015	690	$	17.88	0		$	0
Total 2nd Quarter 2015	77,701	$	18.95		0	$	0

	TECO ENERGY, INC.
	(Registrant)

Date: ~~August~~May 5, ~~2015~~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~~May 5, ~~2015~~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)

Exhibit
No.	Description
~~2.1~~	Amendment No. 4 dated as of April 17, 2015 to the Securities Purchase Agreement dated as of October 17, 2014, by and between TECO Diversified, Inc. as Seller, and Cambrian Coal Corporation, as Purchaser.

3.1	Amended and Restated Articles of Incorporation of TECO Energy, Inc., as filed on May 3, 2012 (Exhibit 3.1, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*

3.2	Bylaws of TECO Energy, Inc., as amended effective May 3, 2012 (Exhibit 3.2, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*

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

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

~~4.1~~10.1	~~Fourth Supplemental Indenture~~Credit Agreement dated as of ~~April 10, 2015,~~Mar. 14, 2016, among TECO Finance, Inc., as ~~issuer,~~Borrower, TECO Energy, Inc., as ~~guarantor, and The~~Guarantor, JPMorgan Chase Bank, ~~of New York Mellon Trust Company,~~ N.A., as ~~trustee~~Administrative Agent, and ~~calculation agent, supplementing~~ the ~~Indenture dated as of December 21, 2007 (including the form of Floating Rate Notes due 2018)~~Lenders party thereto (Exhibit ~~4.22,~~10.1, Form 8-K dated ~~April 10, 2015~~Mar. 14, 2016 of TECO Energy, Inc.).	*

~~4.2~~10.2	~~Twelfth Supplemental Indenture dated~~Form of Restricted Stock Unit Award Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan, as of May 20, 2015, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.20% Notes due 2045) (Exhibit 4.24, Form 8-K dated May 20, 2015 of Tampa Electric Company).amended.	*

10.3	Form of Performance-Based Restricted Stock Unit Award Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan, as amended.

12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.

12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.

31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽¹⁾

32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽¹⁾

95	~~Mine Safety Disclosure~~

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