EX-4.7

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2 to the financial statements, the Company changed the manner in which it classifies deferred taxes in 2015.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Assets	Dec. 31,			Dec. 31,
(millions)	2015			2014
Current assets
Cash and cash equivalents	$	23.8		$	25.4
Receivables, less allowance for uncollectibles of $2.1 and $2.1 at Dec. 31, 2015 and 2014, respectively		280.7			299.8
Inventories, at average cost
Fuel		113.4			96.4
Materials and supplies		76.8			75.4
Regulatory assets		44.8			53.6
Deferred income taxes		0.0			72.8
Prepayments and other current assets		30.8			22.6
Assets held for sale		0.0			109.6
Total current assets		570.3			755.6

Property, plant and equipment
Utility plant in service
Electric		7,270.3			7,094.8
Gas		2,113.8			1,984.6
Construction work in progress		794.7			640.0
Other property		15.9			14.5
Property, plant and equipment, at original costs		10,194.7			9,733.9
Accumulated depreciation		(2,712.9	)		(2,645.7	)
Total property, plant and equipment, net		7,481.8			7,088.2

Other assets
Regulatory assets		395.2			348.5
Goodwill	408.4			408.3
Deferred charges and other assets		105.4			65.8
Assets held for sale		0.0			59.8
Total other assets		909.0			882.4
Total assets	$	8,961.1		$	8,726.2

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

Liabilities and Capital	Dec. 31,			Dec. 31,
(millions)	2015			2014
Current liabilities
Long-term debt due within one year	$	333.3		$	274.5
Notes payable		247.0			139.0
Accounts payable		255.4			288.6
Customer deposits		182.1			176.2
Regulatory liabilities		84.8			57.0
Derivative liabilities		24.1			36.6
Interest accrued		36.2			39.9
Taxes accrued		13.2			29.9
Other		22.6			16.8
Liabilities associated with assets held for sale		0.0			39.4
Total current liabilities		1,198.7			1,097.9

Other liabilities
Deferred income taxes		570.7			519.2
Investment tax credits		10.5			9.0
Regulatory liabilities		715.8			729.0
Derivative liabilities		2.1			6.1
Deferred credits and other liabilities		387.4			370.9
Liabilities associated with assets held for sale		0.0			65.4
Long-term debt, less amount due within one year		3,516.9			3,354.0
Total other liabilities		5,203.4			5,053.6

Commitments and Contingencies (see Note 12)

Capital
Common equity (400.0 million shares authorized; par value $1; 235.3 million and 234.9 million shares outstanding at Dec. 31, 2015 and 2014, respectively)		235.3			234.9
Additional paid in capital		1,894.5			1,875.9
Retained earnings		441.4			479.6
Accumulated other comprehensive loss		(12.2	)		(15.7	)
Total TECO Energy capital		2,559.0			2,574.7
Total liabilities and capital	$	8,961.1		$	8,726.2

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

(millions, except per share amounts)
For the years ended Dec. 31,		2015			2014			2013
Revenues
Regulated electric		$	2,014.9		$	2,019.9		$	1,949.6
Regulated gas			716.8			537.4			392.9
Unregulated			11.8			9.1			12.6
Total revenues			2,743.5			2,566.4			2,355.1
Expenses
Regulated operations and maintenance
Fuel			638.6			692.3			680.2
Purchased power			78.9			71.4			64.7
Cost of natural gas sold			271.6			209.7			142.2
Other			613.2			547.8			524.4
Operation and maintenance other expense			22.7			29.5			12.5
Depreciation and amortization			349.0			315.3			291.8
Taxes, other than income			207.4			195.0			184.7
Total expenses			2,181.4			2,061.0			1,900.5
Income from operations			562.1			505.4			454.6
Other income (expense)
Allowance for other funds used during construction			17.4			10.5			6.3
Other income			3.4			0.5			1.8
Total other income			20.8			11.0			8.1
Interest charges
Interest expense		195.1			176.4				165.0
Allowance for borrowed funds used during construction			(8.7	)		(5.3	)		(3.6	)
Total interest charges			186.4			171.1			161.4
Income from continuing operations before provision for income taxes			396.5			345.3			301.3
Provision for income taxes			155.3			138.9			112.6
Net income from continuing operations			241.2			206.4			188.7
Discontinued operations
Income (loss) from discontinued operations			(106.3	)		(125.4	)		5.2
Provision (benefit) for income taxes			(38.6	)		(49.4	)		(3.8	)
Income (loss) from discontinued operations, net			(67.7	)		(76.0	)		9.0
Net income		$	173.5		$	130.4		$	197.7
Average common shares outstanding	– Basic		233.1			223.1			215.0
	– Diluted		234.5			223.7			215.5
Earnings per share from continuing operations	– Basic	$	1.03		$	0.92		$	0.88
	– Diluted	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations	– Basic	$	(0.29	)	$	(0.34	)	$	0.04
	– Diluted	$	(0.29	)	$	(0.34	)	$	0.04
Earnings per share	– Basic	$	0.74		$	0.58		$	0.92
	– Diluted	$	0.74		$	0.58		$	0.92
Dividends paid per common share outstanding		$	0.90		$	0.88		$	0.88

Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

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

(millions)
For the years ended Dec. 31,	2015			2014			2013
Cash flows from operating activities
Net income	$	173.5		$	130.4		$	197.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		350.2			341.9			329.5
Deferred income taxes and investment tax credits		117.5			89.4			110.1
Allowance for other funds used during construction		(17.4	)		(10.5	)		(6.3	)
Non-cash stock compensation		13.1			12.7			13.5
Loss (gain) on disposals of business/assets		13.2			(0.2	)		(1.6	)
Deferred recovery clauses		26.4			(15.2	)		(6.2	)
Asset impairment		78.6			115.9			0.0
Receivables, less allowance for uncollectibles		36.0			(36.6	)		(4.5	)
Inventories		(22.6	)		12.8			1.1
Prepayments and other current assets		(8.0	)		2.8			(2.2	)
Taxes accrued		(15.9	)		1.1			1.4
Interest accrued		(3.6	)		7.3			(1.3	)
Accounts payable		(61.6	)		23.4			35.9
Other		(69.8	)		(10.4	)		(8.5	)
Cash flows from operating activities		609.6			664.8			658.6
Cash flows from investing activities
Capital expenditures		(739.7	)		(703.8	)		(526.1	)
Purchase of NMGI, net of cash acquired		0.0			(751.5	)		0.0
Net proceeds from sales of business/assets		0.0			0.2			4.3
Other investments		(0.3	)		(7.9	)		0.0
Cash flows used in investing activities		(740.0	)		(1,463.0	)		(521.8	)
Cash flows from financing activities
Dividends paid		(211.7	)		(199.2	)		(191.2	)
Proceeds from the sale of common stock		7.3			302.3			6.7
Proceeds from long-term debt issuance		499.7			563.6			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(274.5	)		(83.3	)		(51.6	)
Change in short-term debt		108.0			55.0			84.0
Cash flows from/(used in) financing activities		128.8			638.4			(152.1	)
Net decrease in cash and cash equivalents		(1.6	)		(159.8	)		(15.3	)
Cash and cash equivalents at beginning of the year		25.4			185.2			200.5
Cash and cash equivalents at end of the year	$	23.8		$	25.4		$	185.2
Supplemental disclosure of cash flow information
Cash paid during the year for:
Interest	$	179.6		$	161.3		$	161.0
Income taxes paid	$	14.5		$	2.9		$	1.8
Supplemental disclosure of non-cash activities
Debt assumed in NMGI acquisition	$	0.0		$	200.0		$	0.0
Change in accrued capital expenditures	$	8.0		$	13.3		$	4.7

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

											Accumulated
					Additional						Other
			Common		Paid in			Retained			Comprehensive			Total
(millions)	Shares		Stock		Capital			Earnings			Income (Loss)			Capital
Balance, Dec. 31, 2012		216.6	$	216.6	$	1,564.5		$	541.7		$	(31.0	)	$	2,291.8
Net income									197.7						197.7
Other comprehensive income, after tax												17.8			17.8
Common stock issued		0.7		0.7		5.2									5.9
Cash dividends declared									(191.2	)					(191.2	)
Stock compensation expense						13.5									13.5
Restricted stock—dividends						1.0			0.1						1.1
Tax short fall—stock compensation						(2.9	)								(2.9	)
Balance, Dec. 31, 2013		217.3	$	217.3	$	1,581.3		$	548.3		$	(13.2	)	$	2,333.7
Net income									130.4						130.4
Other comprehensive income, after tax												(2.5	)		(2.5	)
Common stock issued		17.6		17.6		283.2									300.8
Cash dividends declared									(199.2	)					(199.2	)
Stock compensation expense						12.7									12.7
Restricted stock—dividends						1.1			0.1						1.2
Tax short fall—stock compensation						(2.4	)								(2.4	)
Balance, Dec. 31, 2014		234.9	$	234.9	$	1,875.9		$	479.6		$	(15.7	)	$	2,574.7
Net income									173.5						173.5
Other comprehensive loss, after tax												3.5			3.5
Common stock issued		0.4		0.4		4.6									5.0
Cash dividends declared									(211.7	)					(211.7	)
Stock compensation expense						13.1									13.1
Restricted stock—dividends						1.3									1.3
Tax short fall—stock compensation						(0.4	)								(0.4	)
Balance, Dec. 31, 2015		235.3	$	235.3	$	1,894.5		$	441.4		$	(12.2	)	$	2,559.0

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

TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida.

NMGC, a Delaware corporation and wholly owned subsidiary of NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico.

On Sept. 21, 2015, TECO Diversified sold all of its ownership interest in TECO Coal. TECO Coal, a Kentucky LLC, had subsidiaries which owned assets in Eastern Kentucky, Tennessee and Virginia. These entities owned mineral rights, owned or operated surface and underground mines and owned interests in coal processing and loading facilities. See Note 19 for further information.

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 21 for further information.

The consolidated financial statements include the accounts of TECO Energy and its majority-owned subsidiaries. Intercompany balances and intercompany transactions have been eliminated in consolidation.

The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Dec. 31, 2015 (see Note 21). 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 and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 19).

For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).

Through its centralized services company subsidiary, TSI, TECO Energy provides its operating subsidiaries with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to the applicable operating subsidiaries using cost-causative allocation methods. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of total operating revenues, total operating assets and net income as the basis of allocation. TSI has losses related to taxes which are not distributed to affiliate companies. The results of TECO Energy’s corporate operations, consisting of TSI tax losses and non-allocable Parent costs, are included within the “Other” reportable segment (see Note 14).

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.

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Tampa Electric, PGS and NMGC, concurrent with a planned major maintenance outage or with new construction, capitalize the cost of adding or replacing retirement units-of-property in conformity with the regulations of FERC, FPSC and NMPRC, as applicable. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

Tampa Electric, PGS and NMGC compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 3.6% for 2014 and 3.7% for 2013. Construction work in progress is not depreciated until the asset is completed or placed in service.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Total depreciation expense for the years ended Dec. 31, 2015, 2014 and 2013 was $339.1 million, $307.5 million and $285.6 million, respectively.

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate Tampa Electric’s AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. Tampa Electric’s rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. NMGC’s rate used to calculate its AFUDC in 2015 and 2014 was 4.41% and 4.92%, respectively. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $26.1 million, $15.8 million and $9.9 million, respectively.

TEC and NMGC value materials, supplies and fossil fuel inventory (coal, oil or natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

TECO Coal inventories were stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories were stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory was classified within Assets held for sale at Dec. 31, 2014.

Tampa Electric, PGS and NMGC are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).

TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Under the accounting guidance for goodwill, goodwill is subject to an annual assessment for impairment at the reporting unit level. See Note 20 for further detail.

The company sponsors a defined benefit retirement plan and other postretirement benefits. The measurement of the plans are based on several statistical and other factors, including those that attempt to anticipate future events. See Note 5 for further detail.

TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ retail businesses and the prices charged to customers are regulated by the FPSC or NMPRC, as applicable. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues for energy marketing operations at TECO EnergySource, Inc. are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. Accordingly, for the years ended Dec. 31, 2015, 2014 and 2013, total costs of $3.1 million, $4.3 million and $23.1 million, respectively, consisting primarily of natural gas purchased, were netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income.

Revenues for TECO Coal shipments, both domestic and international, were recognized when title and risk of loss transfer to the customer. They were included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.

Revenues include amounts resulting from cost recovery clauses at the regulated utilities (Tampa Electric, PGS and NMGC) which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, gas storage, interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $81.1 million and $86.6 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31, 2015, 2014 and 2013, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on the regulated utilities’ collection experience. Circumstances that could affect Tampa Electric’s, PGS’s and NMGC’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

TECO Coal’s receivables, which were classified within Assets held for sale at Dec. 31, 2014, consisted of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts was established based on TECO Coal’s collection experience. Circumstances that could have affected TECO Coal’s estimates of uncollectible receivables included customer credit issues and general economic conditions. Accounts were written off once they were determined to be uncollectible.

Tampa Electric and PGS are allowed to recover certain costs on a dollar-for-dollar basis incurred from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, 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 Statement of Income.

TECO Energy’s excise taxes were accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they were not specifically recovered through revenues. Excise taxes paid by the regulated utilities were not material and were expensed when incurred.

Deferred charges and other assets consist primarily of a contribution made by the company in order to fully fund its SERP obligation (see Note 5), unamortized debt issuance costs and assets related to NMGC’s ROW.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.

NMGC’s ROW- Gross assets related to NMGC’s ROW were $41 million at Dec. 31, 2015 and 2014. The related accumulated amortization was $9 million and $8 million at Dec. 31, 2015 and 2014, respectively. The company amortizes costs related to obtaining NMGC’s ROW to “Depreciation and amortization expense” on TECO Energy’s Consolidated Statements of Income.

Deferred credits and other liabilities primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 12), and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively.

TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period.

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 continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

In 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 will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $27.7 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet. The guidance will not affect the company’s results of operations or cash flows.

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible 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. This standard will be required for the company beginning in 2016. As early adoption is permitted, the company adopted the standard for its 2015 fiscal year and applied the presentation on a retrospective basis for all periods presented

in the pension plan assets fair value hierarchy. The guidance did not affect the company’s balance sheets, results of operations or cash flows.

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The guidance will not affect the company’s current financial statements. However, the company will assess the potential impact of the guidance on future acquisitions.

In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for the company beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, the company adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect the company’s results of operations or cash flows.

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

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

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 requirements) 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’s results for the first ten months of 2013 reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Prior to the above-mentioned stipulation and settlement agreement, Tampa Electric was accruing $8.0 million annually to a FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both Dec. 31, 2015 and 2014.

PGS’s base rates were established in May 2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.

In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately $34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on Jan. 31, 2012, revising, among other things, base rates for all service provided on or after Feb. 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately $21.5 million on a normalized annual basis. The monthly residential customer access fee increased from $9.59 to $11.50, with the remaining rate increase reflected in changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017, as reported in Note 21.

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 Dec. 31, 2015 and 2014 are presented in the following table:

In 2015, 2014 and 2013, TECO Energy recorded net tax provisions from continuing operations of $155.3 million, $138.9 million and $112.6 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes and prior year audits in 2015, 2014 and 2013 were $14.5 million, $2.9 million and $1.8 million, respectively.

(millions)
For the year ended Dec. 31,	2015			2014			2013
Continuing Operations
Current income taxes
Federal	$	(0.5	)	$	0.5		$	2.2
State		0.0			0.0			0.0
Deferred income taxes
Federal		133.2			111.0			98.8
State		21.1			27.7			11.9
Amortization of investment tax credits		1.5			(0.3	)		(0.3	)
Income tax expense from continuing operations		155.3			138.9			112.6
Discontinued Operations
Current income taxes
Federal		0.0			0.0			0.0
State		(0.3	)		(0.4	)		(3.5	)
Deferred income taxes
Federal		(34.7	)		(44.0	)		(0.3	)
State		(3.6	)		(5.0	)		0.0
Income tax expense from discontinued operations		(38.6	)		(49.4	)		(3.8	)
Total income tax expense	$	116.7		$	89.5		$	108.8

During 2015, 2014 and 2013, TECO Energy increased its net operating loss carryforward.

The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:

For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes. For 2015, the effective tax rate decreased as a result of a lower state consolidated tax adjustment, offset by a tax expense related to stock-based compensation.

As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2015 will be realized in future periods.

The major components of the company’s deferred tax assets and liabilities recognized are as follows:

At Dec. 31, 2015, the company had cumulative unused federal, Florida and New Mexico NOLs for income tax purposes of $1,728.6 million, $675.2 million and $85.8 million, respectively, expiring at various times between 2025 and 2034, with the majority expiring in 2025. The federal NOL includes $121.6 million of NOLs due to the 2014 acquisition of NMGI. In addition, the company has unused general business credits of $5.8 million expiring between 2026 and 2034. During 2015, the company’s available AMT credit carryforward decreased from $214.0 million to $213.5 million. The AMT credit may be used indefinitely to reduce federal income taxes.

The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.

The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. At Dec. 31, 2014, a $4.6 million valuation allowance had been established for state NOL carryforwards and state deferred tax assets, net of federal tax. During 2015, the valuation allowance decreased by $2.6 million. As a result of the company’s sale of its 100% interest in TECO Coal, the company released a $3.6 million valuation allowance previously recorded in 2014 related to state NOL carryforwards and deferred tax assets, net of federal tax, with a corresponding write off of the gross deferred tax assets since the likelihood that the company will ever utilize those carryforwards is remote. The TECO Coal sale also generated a federal capital loss carryforward deferred tax asset of $1.0 million for which a full valuation allowance has been established due to the uncertainty of recognizing the benefit from this loss, before it expires in 2020.

The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

The company recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2015, 2014 and 2013, the company recognized $0.0 million, $0.0 million and $(0.9) million, respectively, of pretax charges (benefits) for interest only. Additionally, the company did not have any accrued interest at Dec. 31, 2015 and 2014. No amounts have been recorded for penalties.

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state and foreign 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. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

TECO Energy has a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

TECO Coal participants ceased earning pension benefits on Sept. 21, 2015, the date of TECO Energy’s sale of TECO Coal. As a result of the sale, a curtailment loss in the Retirement Plan was recognized in the fourth quarter of 2014. See curtailment-related line items in tables below.

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (Other Benefits or Other Postretirement Benefit Plan) for most employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2013. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan.

NMGC has a separate, partially-funded other postretirement benefit plan. It is not presented separately; rather, it is presented with TECO Energy’s plan in the tables and discussion below. Since NMGC is allowed to recover its other postretirement benefit costs through rates, the regulated asset established prior to the acquisition for pre-acquisition-related prior service cost, actuarial loss, and transition obligation was maintained after the acquisition. This regulated asset will be amortized. See “unrecognized costs in regulated asset acquired in business combination” line item in the “Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets” table below.

Effective Jan. 1, 2015, the TECO Coal participants were terminated from the Other Postretirement Benefit Plan. As a result, the other postretirement benefit obligation for TECO Coal was eliminated as of Dec. 31, 2014. See curtailment-related line items in tables below.

TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC and NMGC. The results of operations are not impacted.

The following table provides a detail of the change in benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits).

At Dec. 31, the aggregate financial position for pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:

The accumulated benefit obligation for all defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.

The amounts recognized in the Consolidated Balance Sheets for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:

Unrecognized gains and losses and prior service credits and costs are recorded in accumulated other comprehensive income for the non-regulated companies and regulatory assets for the regulated companies. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:

The discount rate assumption used to determine the Dec. 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

(millions)	Pension Benefits									Other Benefits
	2015			2014			2013			2015			2014			2013

Service cost	$	20.9		$	18.3		$	18.2		$	2.2		$	2.5		$	2.5
Interest cost		30.3			32.0			28.9			8.2			10.8			9.3
Expected return on plan assets		(43.3	)		(41.8	)		(38.4	)		(1.1	)		(0.3	)		0.0
Amortization of:
Actuarial loss		15.1			13.5			20.5			0.0			0.2			1.0
Prior service (benefit) cost		(0.2	)		(0.4	)		(0.4	)		(2.4	)		(0.2	)		(0.4	)
Curtailment loss (gain)		0.0			3.9			0.0			0.0			(0.2	)		0.0
Special termination benefit		0.0			0.2			0.0			0.0			0.0			0.0
Settlement loss		0.0			0.0			1.0			0.0			0.0			0.0
Net periodic benefit cost	$	22.8		$	25.7		$	29.8		$	6.9		$	12.8		$	12.4

A curtailment loss and special termination benefits were recognized in 2014 for the Retirement Plan due to the expected sale of TECO Coal. The sale was completed in 2015. Additionally, a curtailment gain was recognized for the OPEB plan due to the termination of the TECO Coal plan effective Jan. 1, 2015.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $3.5 million and $0.1 million, respectively. The estimated prior service cost for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.5 million.

In addition, the estimated net loss for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $2.1 million prior service cost that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan. Additionally, $1.1 million of NMGC’s pre-acquisition regulated asset will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

The discount rate assumption used to determine the 2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan assets decreased approximately 3.5%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:

Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company will continue to monitor the matching of plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014.

(millions)	At Fair Value as of Dec. 31, 2015
	Level 1			Level 2			Level 3		Using NAV ⁽¹⁾		Total
Net cash
Cash	$	1.9		$	0.0		$	0.0	$	0.0	$	1.9
Accounts receivable		14.3			0.0			0.0		0.0		14.3
Accounts payable		(27.2	)		0.0			0.0		0.0		(27.2	)
Total net cash		(11.0	)		0.0			0.0		0.0		(11.0	)
Cash equivalents
Money markets		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			0.7			0.0		0.0		0.7
Short-term investment funds (STIFs) ⁽¹⁾		0.0			0.0			0.0		12.4		12.4
Total cash equivalents		0.0			0.9			0.0		12.4		13.3
Equity securities
Common stocks		90.9			0.0			0.0		0.0		90.9
American depository receipts (ADRs)		5.7			0.0			0.0		0.0		5.7
Real estate investment trusts (REITs)		4.8			0.0			0.0		0.0		4.8
Commingled fund		0.0			53.7			0.0		0.0		53.7
Mutual funds ⁽¹⁾		0.0			0.0			0.0		175.6		175.6
Total equity securities		101.4			53.7			0.0		175.6		330.7
Fixed income securities
Municipal bonds		0.0			5.0			0.0		0.0		5.0
Government bonds		0.0			56.2			0.0		0.0		56.2
Corporate bonds		0.0			32.2			0.0		0.0		32.2
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			8.7			0.0		0.0		8.7
Collateralized mortgage obligations (CMOs)		0.0			1.5			0.0		0.0		1.5
Commingled fund ⁽¹⁾		0.0			0.0			0.0		117.9		117.9
Mutual fund ⁽¹⁾		0.0			0.0			0.0		71.3		71.3
Total fixed income securities		0.0			103.9			0.0		189.2		293.1
Derivatives
Swaps		0.0			(0.9	)		0.0		0.0		(0.9	)
Purchased options (swaptions)		0.0			1.1			0.0		0.0		1.1
Written options (swaptions)		0.0			(1.0	)		0.0		0.0		(1.0	)
Total derivatives		0.0			(0.8	)		0.0		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	90.4		$	157.8		$	0.0	$	377.2	$	625.4

(millions)	At Fair Value as of Dec. 31, 2014
	Level 1			Level 2			Level 3		Using NAV ⁽¹⁾		Total
Net cash
Cash	$	0.4		$	0.0		$	0.0	$	0.0	$	0.4
Accounts receivable		1.4			0.0			0.0		0.0		1.4
Accounts payable		(5.3	)		0.0			0.0		0.0		(5.3	)
Total net cash		(3.5	)		0.0			0.0		0.0		(3.5	)
Cash equivalents
Treasury bills (T bills)		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			8.8			0.0		0.0		8.8
Short-term investment funds (STIFs) ⁽¹⁾		0.0			0.0			0.0		7.6		7.6
Total cash equivalents		0.0			9.0			0.0		7.6		16.6
Equity securities
Common stocks		98.0			0.0			0.0		0.0		98.0
American depository receipts (ADRs)		1.3			0.0			0.0		0.0		1.3
Real estate investment trusts (REITs)		2.5			0.0			0.0		0.0		2.5
Preferred stock		0.8			0.0			0.0		0.0		0.8
Commingled fund		0.0			45.6			0.0		0.0		45.6
Mutual funds ⁽¹⁾		0.0			0.0			0.0		171.3		171.3
Total equity securities		102.6			45.6			0.0		171.3		319.5
Fixed income securities
Municipal bonds		0.0			6.1			0.0		0.0		6.1
Government bonds		0.0			47.9			0.0		0.0		47.9
Corporate bonds		0.0			22.0			0.0		0.0		22.0
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			9.6			0.0		0.0		9.6
Collateralized mortgage obligations (CMOs)		0.0			2.0			0.0		0.0		2.0
Commingled fund ⁽¹⁾		0.0			0.0			0.0		129.2		129.2
Mutual fund ⁽¹⁾		0.0			0.0			0.0		98.6		98.6
Total fixed income securities		0.0			87.9			0.0		227.8		315.7
Derivatives
Short futures		0.0			(0.3	)		0.0		0.0		(0.3	)
Purchased options (swaptions)		0.0			0.7			0.0		0.0		0.7
Written options (swaptions)		0.0			(0.8	)		0.0		0.0		(0.8	)
Total derivatives		0.0			(0.4	)		0.0		0.0		(0.4	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	99.1		$	142.2		$	0.0	$	406.7	$	648.0

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

Additionally, the unqualified SERP had $43.5 million and $0.9 million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.

NMGC’s other postretirement benefits plan had $20.6 million and $18.8 million of assets as of Dec. 31, 2015 and 2014, respectively. The majority of the assets are valued at the cash surrender value of NMGC participant life insurance policies and are considered Level 2 assets. In accordance with NMPRC requirements, NMGC must fund to a trust, on an annual basis, an amount equal to the other postretirement expense allowed in its last base rate case.

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions were based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

The qualified pension plan’s actuarial value of assets, including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.

The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $55.0 million and $47.5 million of contributions to this plan in 2015 and 2014, respectively, which met the minimum funding requirements for both 2015 and 2014. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2016 to be $37.4 million and expects to make contributions from 2017 to 2020 in the range of $12.2 to $44.6 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.

The company made contributions of $43.4 million and $1.2 million to the SERP in 2015 and 2014, respectively. The company’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded

amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, the company does not expect to make significant contributions to this plan in 2016.

The company funds its other postretirement benefits periodically to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, the company expects to make contributions of about $14.3 million. This includes $3.6 million that NMGC is required to fund to its trust in accordance with NMPRC requirements. Postretirement benefit levels are substantially unrelated to salary.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective Jan. 1, 2015, employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2015, 2014 and 2013, the company and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan.

At Dec. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

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

At Dec. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 1.29% and 1.16%, respectively.

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). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as of Dec. 31, 2015. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. In addition, 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 Dec. 31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.

On Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it was the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy had no rights or obligations to borrow under the NMGC Credit Agreement, which was entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, on Sept. 2, 2014, TECO Energy designated NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon (i) NMGC became the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy ceased to be a party to the NMGC Credit Agreement and any further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) allows NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) allows NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

On Sept. 30, 2014, NMGC entered into an amendment of the NMGC Credit Agreement, which reallocated commitments among the lenders and made certain other technical changes.

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continued to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.

On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility). The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as guarantor and its wholly-owned subsidiary, TECO Finance, as borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (viii) made other technical changes.

The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. Amendment No. 1 was entered into to accommodate the acquisition of NMGI, as described in Note 21 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closed, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changed the definition of Permitted Liens to permit the acquisition of a significant subsidiary that has outstanding secured debt and made other changes matching the corresponding covenant in the Bridge Facility. TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement on June 24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders in the Bridge Facility.

On Sept. 30, 2014, the TECO Credit Facility was amended to increase total commitments to $300 million and to reallocate commitments among the lenders.

At Dec. 31, 2015, total long-term debt had a carrying amount of $3,850.2 million and an estimated fair market value of $4,061.6 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 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.

TECO Finance is a wholly owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities.

TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2016 through 2020 and thereafter are as follows:

													Total
As of Dec. 31, 2015													Long-Term
(millions)	2016		2017		2018		2019		2020		Thereafter		Debt
TECO Finance	$	250.0	$	300.0	$	250.0	$	0.0	$	300.0	$	0.0	$	1,100.0
Tampa Electric		83.3		0.0		254.2		0.0		0.0		1,666.7		2,004.2
PGS		0.0		0.0		50.0		0.0		0.0		211.7		261.7
NMGC		0.0		0.0		0.0		0.0		0.0		270.0		270.0
NMGI		0.0		0.0		0.0		50.0		0.0		150.0		200.0
Total long-term debt maturities	$	333.3	$	300.0	$	554.2	$	50.0	$	300.0	$	2,298.4	$	3,835.9

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 bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not 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.

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 of $191 million of TECO Finance notes that matured in May 2015.

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes). The TEC 2015 Notes were sold at 99.814% of par. The offering resulted in net proceeds 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 part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 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 TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). The TEC 2014 Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 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, 2043, TEC may at its option redeem the TEC 2014 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.

On Sept. 2, 2014, NMGI completed an offering of $50 million aggregate principal amount of 2.71% Series A Senior Unsecured Notes due July 30, 2019 (the NMGI Series A 2014 Notes) and $150 million aggregate principal amount of 3.64% Series B Senior Unsecured Notes due July 30, 2024 (the NMGI Series B 2014 Notes and, with the NMGI Series A 2014 Notes, the NMGI 2014 Notes). The NMGI 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGI (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $198.4 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI 2014 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGI 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the NMGI notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGI 2014 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.

On Sept. 2, 2014, NMGC completed an offering of $70 million aggregate principal amount of 3.54% Senior Unsecured Notes due July 30, 2026 (the NMGC 2014 Notes). The NMGC 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGC (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $69.3 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGC may redeem all or any part of the NMGC 2014 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the

principal amount of NMGC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGC 2014 Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933.

On Feb. 8, 2011, NMGC issued secured notes in an aggregate principal amount of $200 million (NMGC 2011 Notes), maturing Feb. 8, 2021. The NMGC 2011 Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933.

On July 16, 2014, NMGC received approvals from the noteholders of the NMGC 2011 Notes to release the collateral securing the NMGC 2011 Notes by amending the existing note purchase agreement. The amendments to the note purchase agreement were subject to the approval of the NMPRC, and on Oct. 22, 2014, NMGC received the required NMPRC approval of the amendments. On Oct. 30, 2014, the amendments became effective, the collateral securing the NMGC 2011 Notes was released and other technical changes were made to the NMGC 2011 Notes.

On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

As of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

At Dec. 31, 2015 and 2014, TECO Energy had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2015		2014
TECO Finance	Notes ⁽¹⁾⁽²⁾ : 6.75% ⁽³⁾	2015	$	0.0	$	191.2
	4.00% ⁽³⁾	2016		250.0		250.0
	6.57% ⁽³⁾	2017		300.0		300.0
	Floating rate notes	2018		250.0		0.0
	5.15% ⁽³⁾	2020		300.0		300.0
	Total long-term debt of TECO Finance			1,100.0		1,041.2
Tampa Electric	Installment contracts payable ⁽⁴⁾:
	5.65% Refunding bonds	2018		54.2		54.2
	Variable rate bonds repurchased in 2008 ⁽⁵⁾	2020		0.0		0.0
	5.15% Refunding bonds repurchased in 2013 ⁽⁶⁾	2025		0.0		0.0
	1.5% Term rate bonds repurchased in 2011⁽⁷⁾	2030		0.0		0.0
	5.0% Refunding bonds repurchased in 2012⁽⁸⁾	2034		0.0		0.0
	Notes ⁽¹⁾⁽²⁾ : 6.25%	2015-2016		83.3		166.7
	6.10%	2018		200.0		200.0
	5.40%	2021		231.7		231.7
	2.60%	2022		225.0		225.0
	6.55%	2036		250.0		250.0
	6.15%	2037		190.0		190.0
	4.10%	2042		250.0		250.0
	4.35%	2044		290.0		290.0
	4.20%	2045		230.0		0.0
	Total long-term debt of Tampa Electric			2,004.2		1,857.6
PGS	Notes ⁽²⁾⁽³⁾ : 6.10%	2018		50.0		50.0
	5.40%	2021		46.7		46.7
	2.60%	2022		25.0		25.0
	6.15%	2037		60.0		60.0
	4.10%	2042		50.0		50.0
	4.35%	2044		10.0		10.0
	4.20%	2045		20.0		0.0
	Total long-term debt of PGS			261.7		241.7
NMGI	Notes ⁽²⁾⁽³⁾ : 2.71%	2019		50.0		50.0
	3.64%	2024		150.0		150.0
	Total long-term debt of NMGI			200.0		200.0
NMGC	Notes⁽²⁾⁽³⁾ : 4.87%	2021		200.0		200.0
	3.54%	2026		70.0		70.0
	Total long-term debt of NMGC			270.0		270.0
	Total long-term debt of TECO Energy			3,835.9		3,610.5
Unamortized debt discount, net				14.3		18.0
Total carrying amount of long-term debt				3,850.2		3,628.5
Less amount due within one year				333.3		274.5
Total long-term debt			$	3,516.9	$	3,354.0

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon 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.

The Merger Agreement with Emera restricts TECO Energy and its subsidiaries, without Emera’s prior written consent, from issuing equity or equity equivalents and from paying quarterly cash dividends in excess of levels agreed upon in the Merger Agreement until the Merger occurs or the Merger Agreement is terminated.

On July 1, 2014, the company entered into an underwriting agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014.

Pursuant to the terms of the underwriting agreement, the company granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

The company used the net proceeds from the offering to fund, in part, the acquisition of NMGI and for general corporate purposes.

On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.

The 2010 Plan amended the 2004 Plan. The amendment reduced the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), removed the cap on shares available for stock grant, placed various limitations

on the terms of awards granted under the 2010 Plan, removed the ability to make awards to consultants of the company and reapproved the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.

The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest in amounts ranging between 0% and 150% of the original grant. Beginning in 2015, the total awards for performance-based restricted stock vest based on achievement of earnings growth, with the ability to earn more shares based on total return of TECO Energy common stock compared to a peer group of utility stocks. The 2015 performance-based grants can vest in amounts ranging between 0% and 200% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant. The Merger Agreement with Emera contains provisions regarding the vesting of outstanding grants which would apply upon closing of the Merger.

The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.

The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.

In 2015, 2014 and 2013, 0.7 million, 0.8 million and 0.7 million shares of restricted stock were granted, respectively, with weighted-average fair value per share of $22.96, $14.69 and $17.21, respectively. The total fair market value of awards vesting during 2015, 2014 and 2013 was $7.5 million, $3.6 million and $3.5 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2015, there was $13.2 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.

The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.

The aggregate intrinsic value of stock options exercised was $2.9 million, $2.7 million and $2.4 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. Cash received from option exercises under all share-based payment arrangements was $9.4 million, $10.8 million and $6.7 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. The income tax benefit

realized from stock option exercises was $1.1 million, $1.0 million and $0.8 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively.

In September 2014, the Direct Stock Purchase and Dividend Plan amended and restated the 1992 Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2015, 2014 and 2013, resulting in no increase in shares outstanding.

TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2015, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s benefit plans:

(millions)	Gross			Tax			Net
2015
Unrealized gain (loss) on cash flow hedges	$	4.3		$	(1.5	)	$	2.8
Reclassification from AOCI to net income ⁽¹⁾		1.4			(0.7	)		0.7
Gain (Loss) on cash flow hedges		5.7			(2.2	)		3.5
Amortization of unrecognized benefit costs and other ⁽²⁾		3.4			(1.3	)		2.1
Change in benefit obligation due to valuation ⁽³⁾		(15.5	)		5.7			(9.8	)
Recognized cost due to settlement ⁽⁴⁾		12.1			(4.4	)		7.7
Total other comprehensive income (loss)	$	5.7		$	(2.2	)	$	3.5
2014
Unrealized gain (loss) on cash flow hedges	$	(0.5	)	$	0.2		$	(0.3	)
Reclassification from AOCI to net income ⁽¹⁾		1.6			(0.6	)		1.0
Gain (Loss) on cash flow hedges		1.1			(0.4	)		0.7
Amortization of unrecognized benefit costs and other ⁽²⁾		(4.8	)		1.8			(3.0	)
Increase in unrecognized postemployment costs ⁽⁵⁾		(12.9	)		4.7			(8.2	)
Change in benefit obligation due to valuation ⁽⁶⁾		12.6			(4.6	)		8.0
Total other comprehensive income (loss)	$	(4.0	)	$	1.5		$	(2.5	)
2013
Unrealized gain (loss) on cash flow hedges	$	1.0		$	(0.4	)	$	0.6
Reclassification from AOCI to net income ⁽¹⁾		1.3			(0.5	)		0.8
Gain (Loss) on cash flow hedges		2.3			(0.9	)		1.4
Amortization of unrecognized benefit costs and other ⁽²⁾		23.6			(8.8	)		14.8
Recognized costs due to settlement		2.6			(1.0	)		1.6
Total other comprehensive income (loss)	$	28.5		$	(10.7	)	$	17.8

In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.

The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.

(millions, except per share amounts)	2015			2014			2013 ⁽¹⁾
Basic earnings per share
Net income from continuing operations	$	241.2		$	206.4		$	188.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Income before discontinued operations available to common shareholders—Basic	$	240.5		$	205.7		$	188.1
Income (loss) from discontinued operations	$	(67.7	)	$	(76.0	)	$	9.0
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0
Income (loss) from discontinued operations —Basic	$	(67.7	)	$	(76.0	)	$	9.0
Net income	$	173.5		$	130.4		$	197.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Net income available to common shareholders—Basic	$	172.8		$	129.7		$	197.1
Average common shares outstanding—Basic		233.1			223.1			215.0
Earnings per share from continuing operations available to common shareholders—Basic	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations available to common shareholders—Basic		(0.29	)		(0.34	)		0.04
Earnings per share attributable to TECO Energy available to common shareholders—Basic	$	0.74		$	0.58		$	0.92
Diluted earnings per share
Net income from continuing operations	$	241.2		$	206.4		$	188.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Income before discontinued operations available to common shareholders—Diluted	$	240.5		$	205.7		$	188.1
Income (loss) from discontinued operations	$	(67.7	)	$	(76.0	)	$	9.0
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0
Income (loss) from discontinued operations available to common shareholders—Diluted	$	(67.7	)	$	(76.0	)	$	9.0
Net income	$	173.5		$	130.4		$	197.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Net income available to common shareholders—Diluted	$	172.8		$	129.7		$	197.1
Unadjusted average common shares outstanding—Diluted		233.1			223.1			215.0
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		1.4			0.6			0.5
Average common shares outstanding—Diluted		234.5			223.7			215.5
Earnings per share from continuing operations available to common shareholders—Diluted	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations available to common shareholders—Diluted		(0.29	)		(0.34	)		0.04
Earnings per share available to common shareholders—Diluted	$	0.74		$	0.58		$	0.92
Anti-dilutive shares		0.0			0.0			0.0

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does

not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

A 36-year-old man died from mesothelioma in March 2014. His estate and his family sued 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 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.

A 33-year-old man made contact with a primary line in June 2013, suffering severe burns. He and his wife sued 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 alleged, among other things, negligence and loss of consortium. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.

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 expected in late 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.”

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Dec. 31, 2015.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgement in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgement.

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, a hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.

Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction. Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger. In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

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

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

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. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.

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 Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

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

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

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

TECO Energy has commitments for capacity payments and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Other” and “Discontinued Operations” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013 totaled $15.3 million, $13.7 million and $7.6 million, respectively. In addition, the company has other purchase obligations, including Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015:

TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2015 are as follows:

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 Dec. 31, 2015, TECO Energy and its subsidiaries were in compliance with all required financial covenants.

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2015, 2014 and 2013. No material balances were payable as of Dec. 31, 2015 or 2014.

TECO Energy is primarily an electric and gas utility holding company. Its diversified activities have been classified as discontinued operations. 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 segment’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. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TECO Energy, but are included in determining reportable segments.

Tampa Electric provides retail electric utility services to almost 719,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida. NMGC is engaged in the purchase and distribution of natural gas for more than 516,000 residential, commercial, industrial customers in the State of New Mexico.

	Tampa						TECO											TECO
(millions)	Electric		PGS		NMGC ⁽⁴⁾		Coal ⁽²⁾				Other ^(4),(5)			Eliminations ⁽⁵⁾				Energy
2015
Revenues—external	$	2,014.9	$	401.5	$	316.5	$	0.0			$	10.6		$	0.0			$	2,743.5
Sales to affiliates		3.4		6.0		0.0		0.0				0.1			(9.5	)			0.0
Total revenues		2,018.3		407.5		316.5		0.0				10.7			(9.5	)			2,743.5
Depreciation and amortization		256.7		56.8		33.8		0.0				1.7			0.0				349.0
Total interest charges ⁽¹⁾		95.1		14.5		13.0		0.0				65.1			(1.3	)			186.4
Internally allocated interest ⁽¹⁾		0.0		0.0		0.0		0.0				1.3			(1.3	)			0.0
Provision for income taxes		143.6		21.9		15.4		0.0				(25.6	)		0.0				155.3
Net income from continuing operations		241.0		35.3		24.1		0.0				(59.2	)		0.0				241.2
Discontinued operations, net of tax		0.0		0.0		0.0		(69.6	)			1.9			0.0				(67.7	)
Net income		241.0		35.3		24.1		(69.6	)			(57.3	)		0.0				173.5
Goodwill		0.0		0.0		408.4		0.0				0.0			0.0				408.4
Total assets		7,020.7		1,137.4		1,231.3		0.0		⁽³⁾		1,947.9			(2,376.2	)	⁽⁶⁾		8,961.1
Capital expenditures		592.6		94.0		48.7		3.7				0.7			0.0				739.7
2014
Revenues—external	$	2,019.9	$	398.5	$	137.5	$	0.0			$	10.5		$	0.0			$	2,566.4
Sales to affiliates		1.1		1.1		0.0		0.0				0.2			(2.4	)			0.0
Total revenues		2,021.0		399.6		137.5		0.0				10.7			(2.4	)			2,566.4
Depreciation and amortization		248.6		54.0		11.0		0.0				1.7			0.0				315.3
Total interest charges ⁽¹⁾		92.8		13.8		4.2		0.0				66.1			(5.8	)			171.1
Internally allocated interest ⁽¹⁾		0.0		0.0		0.0		0.0				5.8			(5.8	)			0.0
Provision for income taxes		133.2		22.7		7.1		0.0				(24.1	)		0.0				138.9
Net income from continuing operations		224.5		35.8		10.5		0.0				(64.4	)		0.0				206.4
Discontinued operations, net of tax		0.0		0.0		0.0		(82.0	)			6.0			0.0				(76.0	)
Net income		224.5		35.8		10.5		(82.0	)			(58.4	)		0.0				130.4
Goodwill		0.0		0.0		408.3		0.0				0.0			0.0				408.3
Total assets		6,565.4		1,082.8		1,237.2		227.7		⁽³⁾		1,611.6			(1,998.5	)	⁽⁶⁾		8,726.2
Capital expenditures		582.1		88.9		18.2		14.6				0.0			0.0				703.8
2013
Revenues—external	$	1,949.6	$	392.7	$	0.0	$	0.0			$	12.8		$	0.0			$	2,355.1
Sales to affiliates		0.9		0.8		0.0		0.0				0.5			(2.2	)			0.0
Total revenues		1,950.5		393.5		0.0		0.0				13.3			(2.2	)			2,355.1
Depreciation and amortization		238.8		51.5		0.0		0.0				1.5			0.0				291.8
Total interest charges ⁽¹⁾		91.8		13.5		0.0		0.0				63.9			(7.8	)			161.4
Internally allocated interest ⁽¹⁾		0.0		0.0		0.0		0.0				7.8			(7.8	)			0.0
Provision for income taxes		116.9		21.9		0.0		0.0				(26.2	)		0.0				112.6
Net income from continuing operations		190.9		34.7		0.0		0.0				(36.9	)		0.0				188.7
Discontinued operations, net of tax		0.0		0.0		0.0		9.0				0.0			0.0				9.0
Net income		190.9		34.7		0.0		9.0				(36.9	)		0.0				197.7
Total assets		6,126.9		1,021.2		0.0		316.3		⁽³⁾		1,739.2			(1,755.6	)	⁽⁶⁾		7,448.0
Capital expenditures		422.3		79.0		0.0		22.4				2.4			0.0				526.1

TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

Prior to the sale of TECO Coal on Sept. 21, 2015, TECO Energy had recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations were related to environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2014, these obligations totaled $22.5 million and were classified as Liabilities Associated with Assets Held for Sale on TECO Energy’s Consolidated Balance Sheet.

TECO Energy’s regulated utilities must file depreciation and dismantlement studies periodically and receive approval from the FPSC or NMPRC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric, PGS and NMGC, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2015 and 2014, these obligations totaled $6.8 million and $6.1 million, respectively.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

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 17). 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 of natural gas for its regulated companies. 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 Dec. 31, 2015, all of the company’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Dec. 31, 2015 and 2014 are reflected on the company’s Consolidated 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 $0.2 and $0.0 million as of Dec. 31, 2015 and 2014, respectively, and are included in “Prepayments and other current assets” on the Consolidated Balance Sheet. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at Dec. 31, 2015 and 2014 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 Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at Dec. 31, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The Dec. 31, 2015 and 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 10.

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 years ended Dec. 31, 2015, 2014 and 2013, 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 years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 10. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in “Interest expense” for TEC and “Income (loss) from discontinued operations” for TECO Coal.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017 fiscal years:

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Dec. 31, 2015, 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:

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 Dec. 31, 2015 and 2014. 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.

The natural gas derivatives are OTC swap and option instruments. Fair values of swaps and options are estimated utilizing the market and income approach, respectively. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. 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 and option positions to determine the fair value (see Note 16).

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 Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

See Notes 5, 7 and 19 for information regarding the fair value of the company’s pension plan investments, long-term debt, and asset impairment charge, respectively.

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

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 2013, 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 Balance Sheets, Statements of Income or Cash Flows.

In 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in the fourth quarter of 2013 on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that were recoverable; therefore, no impairment charge was deemed necessary in 2013. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.

In September 2014, the Board of Directors of 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. 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.

In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value based on the price specified in an agreement of sale entered into in October 2014, which agreement had conditions to closing that were not satisfied, less estimated costs of the transaction. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded, which included the estimated selling costs associated with the transaction completed in September 2015. The fair value measurements were considered Level 2 measurements since the market is not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis). None of these impairments had cash flow impacts. The asset impairment charges are recorded in the “Income (loss) from discontinued operations” line item in the Consolidated Statements of Income and the “Asset impairment” line item in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2014 and 2015.

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into the SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian. The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 12). The company recorded a loss on sale of $10.0 million pretax, which is reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income, primarily to write off an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations previously recorded in AOCI. Transaction-related costs of $12.3 million pretax, comprised of $2.5 million of legal and other consultant costs and $9.8 million of severance and other employee costs, were accrued at June 30, 2015 and reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income. The transaction-related costs were paid in 2015, with the exception of a minor amount of severance payments.

Since the closing of the sale, TECO Energy has not and will 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.

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 12). 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 TECO Coal and TECO Guatemala:

The following table presents the changes in the carrying amount of goodwill for the years ended Dec. 31, 2015, 2014 and 2013.

The goodwill on the company’s balance sheet related to the NMGC segment was recorded upon acquisition of NMGI on Sept. 2, 2014 (see Note 21). Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. Since NMGC is the lowest level of identifiable cash flows, this is the level at which goodwill is tested. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. TECO Energy reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit.

The fair value for NMGC was determined in the fourth quarter using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of NMGC’s projected cash flows. It includes an estimate of NMGC’s terminal value based on these expected cash flows using the Gordon Growth Formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash

flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to EBITDA of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then applied to the last-twelve-months EBITDA of the subject company. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the terminal value.

The company determined the fair value of NMGC exceeds the book value and related goodwill carrying amounts at Dec. 31, 2015 and 2014, resulting in no impairment charge. Adverse changes in assumptions described above could result in a future material impairment of NMGC’s goodwill.

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, was obtained on Jan. 20, 2016) (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.

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.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. 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), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

During the year ended Dec. 31, 2015, TECO Energy incurred approximately $17.0 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

On Sept. 2, 2014, the company completed the acquisition of NMGI contemplated by the acquisition agreement dated May 25, 2013 by and among the company, NMGI and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI is the parent company of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments.

On the acquisition date, NMGC, with approximately 720 employees, served more than 513,000 customers, predominately residential, in New Mexico with the majority located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company served approximately 60 percent of the state’s population with customers in 23 of New Mexico’s 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines.

NMGC is a rate-regulated natural gas utility subject to the regulation of the NMPRC, including with respect to its rates, service standards, accounting, securities issuances, construction of major new transmission and distribution facilities and other matters affecting, directly or indirectly, the provision of natural gas sales and transportation services to NMGC’s customers.

In May 2014, TECO Energy reached a settlement with the New Mexico Industrial Energy Consumers (which represents large customers), the New Mexico Attorney General’s office (which represents the New Mexico residential and small business customers) and the U.S. Department of Energy. As part of this settlement of the application for approval of the acquisition by the NMPRC, TECO Energy agreed, among other things, to:

On Aug. 13, 2014, the NMPRC approved the acquisition with the conditions set forth in the settlement agreements described above. The transaction closed on Sept. 2, 2014.

The majority of NMGI’s assets acquired and liabilities assumed relate to deferred income taxes associated with its NOL. These were recorded in accordance with the applicable accounting guidance. Additionally, the company paid off the existing outstanding debt at NMGI and issued $200 million of new NMGI debt at closing. Since the refinancing took place at closing, face value approximated fair value.

The majority of NMGC’s operations are subject to the rate-setting authority of the NMPRC and are accounted for pursuant to U.S. GAAP, including the accounting guidance for regulated operations. Rate-setting and cost recovery provisions currently in place for NMGC’s regulated operations provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. Except for long-term debt, the ARO, derivatives, OPEB plans, and deferred taxes, fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any net adjustments related to these amounts. The difference between fair value and pre-merger carrying amounts for long-term debt, derivatives, and the OPEB plan for regulated operations were recorded as regulatory assets or liabilities.

The excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth, synergies and an improved risk profile. Goodwill resulting from the acquisition was allocated entirely to the NMGC segment. Goodwill of $146.1 million related to the formation of NMGC in 2009 is tax deductible. The incremental goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes were recorded related to this portion of the goodwill.

The final purchase price allocation of the acquisition of NMGI and NMGC was as follows:

The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $316.5 million and $137.5 million, respectively. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $19.6 million and $8.2 million, respectively.

The following unaudited pro forma financial information reflects the consolidated results of operations of the company and reflects the amortization of purchase accounting adjustments assuming the acquisition had taken place on Jan. 1, 2013. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the company.

Pro forma earnings presented below include adjustments related to non-recurring acquisition consummation, integration and other costs incurred by the company during the period. After-tax non-recurring acquisition consummation, integration and other costs incurred by the company were $8.6 million and $6.2 million for the years ended Dec. 31, 2014 and 2013, respectively.

The following after-tax transaction and integration charges were recognized in connection with the acquisition and are included in the TECO Energy Consolidated Statement of Income for the years ended Dec. 31, 2015 and 2014.

The company has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

In conjunction with the acquisition, in September 2014, TECO Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the severance plan began in the third quarter of 2014, and substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Dec. 31, 2015 and 2014, the obligations associated with the severance benefits costs were $0.7 million and $2.6 million, respectively.

(millions, except per share amounts)
Quarter ended	Dec. 31		Sept. 30		June 30		Mar. 31
2015
Revenues	$	676.1	$	693.8	$	680.6	$	693.0
Income from operations		126.0		146.6		143.3		146.2
Net income from continuing operations		51.0		64.9		61.5		63.8
Net income		50.5		53.2		11.8		58.0
EPS—Basic
Net income from continuing operations	$	0.22	$	0.28	$	0.26	$	0.27
Net income		0.21		0.23		0.05		0.25
EPS—Diluted
Net income from continuing operations	$	0.22	$	0.28	$	0.26	$	0.27
Net income		0.21		0.23		0.05		0.25
Dividends paid per common share outstanding	$	0.225	$	0.225	$	0.225	$	0.225

Quarter ended	Dec. 31		Sept. 30		June 30		Mar. 31
2014
Revenues	$	695.5	$	687.2	$	605.7	$	578.0
Income from operations		112.1		145.7		132.0		115.6
Net income from continuing operations		27.4		73.0		57.6		48.4
Net income		10.8		11.1		58.4		50.1
EPS—Basic
Net income from continuing operations	$	0.11	$	0.32	$	0.27	$	0.22
Net income		0.04		0.04		0.27		0.23
EPS—Diluted
Net income from continuing operations	$	0.11	$	0.32	$	0.27	$	0.22
Net income		0.04		0.04		0.27		0.23
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220

Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

On Feb. 24, 2016, TECO Energy and TECO Finance entered into Amendment No. 3 to its Fourth Amended and Restated Credit Agreement (the TECO Credit Facility) with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders named therein. The amendment provides that the closing of the Merger will not constitute an event of default under the TECO Credit Facility.

In February 2016, TECO Energy (as guarantor) and TECO Finance (as borrower) secured commitments for a $400 million one-year term loan facility, the terms of which provide for closing and funding on Mar. 14, 2016. The proceeds of the facility are to be used to repay at maturity the $250 million aggregate principal amount of TECO Finance 4.00% Notes due Mar. 15, 2016, repay a portion of the drawings under the TECO Credit Facility and for general corporate purposes.

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements, the Company changed the manner in which it classifies deferred taxes in 2015.

Assets	Dec. 31,			Dec. 31,
(millions)	2015			2014
Property, plant and equipment
Utility plant in service
Electric	$	7,270.3		$	7,094.8
Gas		1,398.6			1,308.9
Construction work in progress		771.1			624.2
Utility plant in service, at original costs		9,440.0			9,027.9
Accumulated depreciation		(2,676.8	)		(2,633.8	)
Utility plant in service, net		6,763.2			6,394.1
Other property		9.7			8.6
Total property, plant and equipment, net		6,772.9			6,402.7

Current assets
Cash and cash equivalents		9.1			10.4
Receivables, less allowance for uncollectibles of $1.5 and $1.4 at Dec. 31, 2015 and 2014, respectively		230.2			227.2
Inventories, at average cost
Fuel		105.6			85.2
Materials and supplies		73.1			72.2
Regulatory assets		44.3			52.1
Taxes receivable from affiliate		61.3			43.3
Deferred income taxes		0.0			24.8
Prepayments and other current assets		21.5			17.4
Total current assets		545.1			532.6

Deferred debits
Unamortized debt expense		18.1			16.8
Regulatory assets		373.8			319.6
Other		16.8			2.6
Total deferred debits		408.7			339.0
Total assets	$	7,726.7		$	7,274.3

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

Liabilities and Capital	Dec. 31,			Dec. 31,
(millions)	2015			2014
Capitalization
Common stock	$	2,305.4		$	2,130.4
Accumulated other comprehensive loss		(3.6	)		(7.1	)
Retained earnings		313.7			305.8
Total capital		2,615.5			2,429.1
Long-term debt, less amount due within one year		2,179.8			2,013.8
Total capital		4,795.3			4,442.9

Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		61.0			58.0
Accounts payable		221.6			242.3
Customer deposits		176.3			170.4
Regulatory liabilities		83.2			54.7
Derivative liabilities		24.1			36.6
Interest accrued		16.9			17.0
Taxes accrued		13.2			12.4
Other		10.2			10.0
Total current liabilities		689.8			684.7

Deferred credits
Deferred income taxes		1,308.8			1,209.1
Investment tax credits		10.5			9.0
Derivative liabilities		2.1			6.1
Regulatory liabilities		603.5			623.4
Deferred credits and other liabilities		316.7			299.1
Total deferred credits		2,241.6			2,146.7

Commitments and Contingencies (see Note 9)

Total liabilities and capital	$	7,726.7		$	7,274.3

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

(millions)
For the years ended Dec. 31,	2015			2014			2013
Revenues
Electric	$	2,017.7		$	2,020.5		$	1,950.1
Gas		401.5			398.5			392.7
Total revenues		2,419.2			2,419.0			2,342.8
Expenses
Regulated operations & maintenance
Fuel		638.6			692.3			680.2
Purchased power		78.9			71.4			64.7
Cost of natural gas sold		135.5			137.0			142.6
Other		528.9			518.4			523.6
Depreciation and amortization		313.5			302.6			290.3
Taxes, other than income		192.0			189.8			183.1
Total expenses		1,887.4			1,911.5			1,884.5
Income from operations		531.8			507.5			458.3
Other income
Allowance for other funds used during construction		17.2			10.5			6.3
Other income, net		2.4			4.8			5.1
Total other income		19.6			15.3			11.4
Interest charges
Interest expense		117.9			111.7			108.9
Allowance for borrowed funds used during construction		(8.3	)		(5.1	)		(3.6	)
Total interest charges		109.6			106.6			105.3
Income before provision for income taxes		441.8			416.2			364.4
Provision for income taxes		165.5			155.9			138.8
Net income		276.3			260.3			225.6
Other comprehensive income, net of tax
Gain on cash flow hedges		3.5			0.7			0.9
Total other comprehensive income, net of tax		3.5			0.7			0.9
Comprehensive income	$	279.8		$	261.0		$	226.5

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

(millions)
For the years ended Dec. 31,	2015			2014			2013
Cash flows from operating activities
Net income	$	276.3		$	260.3		$	225.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		313.5			302.6			290.3
Deferred income taxes and investment tax credits		118.9			92.2			118.1
Allowance for other funds used during construction		(17.2	)		(10.5	)		(6.3	)
Loss on disposal of assets, pretax		3.1			0.0			0.0
Deferred recovery clauses		26.5			(16.2	)		(6.2	)
Receivables, less allowance for uncollectibles		(3.0	)		0.4			(13.8	)
Inventories		(21.3	)		13.1			(9.0	)
Prepayments and other deposits		(4.0	)		1.5			0.0
Taxes accrued		(17.2	)		11.8			(34.3	)
Interest accrued		(0.1	)		0.6			(0.9	)
Accounts payable		(26.8	)		5.9			34.8
Other		(40.8	)		(14.5	)		(2.8	)
Cash flows from operating activities		607.9			647.2			595.5
Cash flows from investing activities
Capital expenditures		(686.6	)		(671.0	)		(501.3	)
Net proceeds from sale of assets		0.0			0.0			0.1
Cash flows used in investing activities		(686.6	)		(671.0	)		(501.2	)
Cash flows from financing activities
Common stock		175.0			100.0			60.0
Proceeds from long-term debt issuance		251.1			296.3			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(83.3	)		(83.3	)		(51.6	)
Net change in short-term debt		3.0			(26.0	)		84.0
Dividends paid		(268.4	)		(262.6	)		(222.1	)
Cash flows from/(used in) financing activities		77.4			24.4			(129.7	)
Net increase (decrease) in cash and cash equivalents		(1.3	)		0.6			(35.4	)
Cash and cash equivalents at beginning of the year		10.4			9.8			45.2
Cash and cash equivalents at end of the year	$	9.1		$	10.4		$	9.8

Supplemental disclosure of cash flow information
Cash paid (received) during the year for:
Interest	$	106.2		$	102.5		$	102.4
Income taxes	$	63.7		$	52.6		$	56.4
Supplemental disclosure of cash flow information
Change in accrued capital expenditures	$	6.9		$	14.3		$	4.7

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

Long-Term Debt
(millions)		Due	2015			2014
Tampa Electric	Installment contracts payable ⁽¹⁾ :
	5.65% Refunding bonds	2018	$	54.2		$	54.2
	Variable rate bonds repurchased in 2008 ⁽²⁾	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 ⁽³⁾	2025		0.0			0.0
	1.5% Term rate bonds repurchased in 2011 ⁽⁴⁾	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 ⁽⁵⁾	2034		0.0			0.0
	Notes ⁽⁶⁾⁽⁷⁾ : 6.25%	2015-2016		83.3			166.7
	6.10%	2018		200.0			200.0
	5.40%	2021		231.7			231.7
	2.60%	2022		225.0			225.0
	6.55%	2036		250.0			250.0
	6.15%	2037		190.0			190.0
	4.10%	2042		250.0			250.0
	4.35%	2044		290.0			290.0
	4.20%	2045		230.0			0.0
	Total long-term debt of Tampa Electric			2,004.2			1,857.6
PGS	Notes ⁽⁶⁾⁽⁷⁾: 6.10%	2018		50.0			50.0
	5.40%	2021		46.7			46.7
	2.60%	2022		25.0			25.0
	6.15%	2037		60.0			60.0
	4.10%	2042		50.0			50.0
	4.35%	2044		10.0			10.0
	4.20%	2045		20.0			0.0
	Total long-term debt of PGS			261.7			241.7
Total long-term debt of TEC				2,265.9			2,099.3
Unamortized debt discount, net				(2.8	)		(2.2	)
Total carrying amount of long-term debt				2,263.1			2,097.1
Less amount due within one year				83.3			83.3
Total long-term debt			$	2,179.8		$	2,013.8

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

At Dec. 31, 2015, total long-term debt had a carrying amount of $2,263.1 million and an estimated fair market value of $2,433.3 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2 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.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt for the years 2016 through 2020 and thereafter are as follows:

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

TEC has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. TEC’s significant accounting policies are as follows:

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects.

The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance (see Note 3 for additional details).

TEC’s retail and wholesale businesses are regulated by the FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. Intercompany balances and intercompany transactions have been eliminated in consolidation. 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.

For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

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

Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 2014 and 2013. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2015, 2014 and 2013 was $306.0 million, $295.8 million and $284.2 million, respectively.

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $25.5 million, $15.6 million and $9.9 million, respectively.

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline

capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $53.7 million and $49.3 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

TEC is allowed to recover certain costs on a dollar-for-dollar basis incurred from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), and medical and general liability claims incurred but not reported. TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively.

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income in any period.

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 continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

In 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 will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $18.1 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet. The guidance will not affect TEC’s results of operations or cash flows.

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible 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, in which TEC participates, has such investments as disclosed in Note 5. This standard will be required for TEC beginning in 2016. As early adoption is permitted, TEC adopted the standard for its 2015 fiscal year and applied the presentation on a retrospective basis for all periods presented in the pension plan assets fair value hierarchy. The guidance did not affect TEC’s balance sheets, results of operations or cash flows.

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for TEC beginning in 2016 and will be applied prospectively. The guidance will not affect TEC’s current financial statements. However, TEC will assess the potential impact of the guidance on future acquisitions.

In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for TEC beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, TEC adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect TEC’s results of operations or cash flows.

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

permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

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 Dec. 31, 2015 and 2014 are presented in the following table:

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. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income taxes.

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

At Dec. 31, 2015, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $194.1 million and $268.5 million, respectively, expiring in 2033. In addition, TEC has unused general business credits of $1.9 million, expiring between 2028 and 2035.

TEC accounts for uncertain tax positions as required by FASB accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

As of Dec. 31, 2015 and 2014, TEC does not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2016. As of Dec. 31, 2015 and 2014, TEC does not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and onward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. 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 within the next 12 months.

TEC is a participant in the comprehensive retirement plans of TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (Other Benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company implemented an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan.

TEC recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted.

The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits).

At Dec. 31, the aggregate financial position for TECO Energy pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.

The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:

Unrecognized gains and losses and prior service credits and costs are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:

TECO Energy	Pension Benefits									Other Benefits
	2015			2014			2013			2015			2014			2013
(millions)
Service cost	$	20.9		$	18.3		$	18.2		$	2.2		$	2.5		$	2.5
Interest cost		30.3			32.0			28.9			8.2			10.8			9.3
Expected return on plan assets		(43.3	)		(41.8	)		(38.4	)		(1.1	)		(0.3	)		0.0
Amortization of:
Actuarial loss		15.1			13.5			20.5			0.0			0.2			1.0
Prior service (benefit) cost		(0.2	)		(0.4	)		(0.4	)		(2.4	)		(0.2	)		(0.4	)
Curtailment loss (gain)		0.0			3.9			0.0			0.0			(0.2	)		0.0
Special termination benefit		0.0			0.2			0.0			0.0			0.0			0.0
Settlement loss		0.0			0.0			1.0			0.0			0.0			0.0
Net periodic benefit cost	$	22.8		$	25.7		$	29.8		$	6.9		$	12.8		$	12.4

TEC’s portion of the net periodic benefit costs for pension benefits was $13.5 million, $14.8 million and $21.7 million for 2015, 2014 and 2013, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $5.7 million, $10.4 million and $10.0 million for 2015, 2014 and 2013, respectively.

The estimated net loss for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $1.9 million prior service credit that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets.

Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan’s assets decreased approximately 3.5%.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:

Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take additional steps to more closely match plan assets with plan liabilities.

(millions)	At Fair Value as of Dec. 31, 2015
	Level 1			Level 2			Level 3		Using NAV ⁽¹⁾		Total
Net cash
Cash	$	1.9		$	0.0		$	0.0	$	0.0	$	1.9
Accounts receivable		14.3			0.0			0.0		0.0		14.3
Accounts payable		(27.2	)		0.0			0.0		0.0		(27.2	)
Total net cash		(11.0	)		0.0			0.0		0.0		(11.0	)
Cash equivalents
Money markets		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			0.7			0.0		0.0		0.7
Short-term investment funds (STIFs) ⁽¹⁾		0.0			0.0			0.0		12.4		12.4
Total cash equivalents		0.0			0.9			0.0		12.4		13.3
Equity securities
Common stocks		90.9			0.0			0.0		0.0		90.9
American depository receipts (ADRs)		5.7			0.0			0.0		0.0		5.7
Real estate investment trusts (REITs)		4.8			0.0			0.0		0.0		4.8
Commingled fund		0.0			53.7			0.0		0.0		53.7
Mutual funds ⁽¹⁾		0.0			0.0			0.0		175.6		175.6
Total equity securities		101.4			53.7			0.0		175.6		330.7
Fixed income securities
Municipal bonds		0.0			5.0			0.0		0.0		5.0
Government bonds		0.0			56.2			0.0		0.0		56.2
Corporate bonds		0.0			32.2			0.0		0.0		32.2
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			8.7			0.0		0.0		8.7
Collateralized mortgage obligations (CMOs)		0.0			1.5			0.0		0.0		1.5
Commingled fund ⁽¹⁾		0.0			0.0			0.0		117.9		117.9
Mutual fund ⁽¹⁾		0.0			0.0			0.0		71.3		71.3
Total fixed income securities		0.0			103.9			0.0		189.2		293.1
Derivatives
Swaps		0.0			(0.9	)		0.0		0.0		(0.9	)
Purchased options (swaptions)		0.0			1.1			0.0		0.0		1.1
Written options (swaptions)		0.0			(1.0	)		0.0		0.0		(1.0	)
Total derivatives		0.0			(0.8	)		0.0		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	90.4		$	157.8		$	0.0	$	377.2	$	625.4

(millions)	At Fair Value as of Dec. 31, 2014
	Level 1			Level 2			Level 3		Using NAV ⁽¹⁾		Total
Net cash
Cash	$	0.4		$	0.0		$	0.0	$	0.0	$	0.4
Accounts receivable		1.4			0.0			0.0		0.0		1.4
Accounts payable		(5.3	)		0.0			0.0		0.0		(5.3	)
Total net cash		(3.5	)		0.0			0.0		0.0		(3.5	)
Cash equivalents
Treasury bills (T bills)		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			8.8			0.0		0.0		8.8
Short-term investment funds (STIFs) ⁽¹⁾		0.0			0.0			0.0		7.6		7.6
Total cash equivalents		0.0			9.0			0.0		7.6		16.6
Equity securities
Common stocks		98.0			0.0			0.0		0.0		98.0
American depository receipts (ADRs)		1.3			0.0			0.0		0.0		1.3
Real estate investment trusts (REITs)		2.5			0.0			0.0		0.0		2.5
Preferred stock		0.8			0.0			0.0		0.0		0.8
Commingled fund		0.0			45.6			0.0		0.0		45.6
Mutual funds ⁽¹⁾		0.0			0.0			0.0		171.3		171.3
Total equity securities		102.6			45.6			0.0		171.3		319.5
Fixed income securities
Municipal bonds		0.0			6.1			0.0		0.0		6.1
Government bonds		0.0			47.9			0.0		0.0		47.9
Corporate bonds		0.0			22.0			0.0		0.0		22.0
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			9.6			0.0		0.0		9.6
Collateralized mortgage obligations (CMOs)		0.0			2.0			0.0		0.0		2.0
Commingled fund ⁽¹⁾		0.0			0.0			0.0		129.20		129.2
Mutual fund ⁽¹⁾		0.0			0.0			0.0		98.6		98.6
Total fixed income securities		0.0			87.9			0.0		227.8		315.7
Derivatives
Short futures		0.0			(0.3	)		0.0		0.0		(0.3	)
Purchased options (swaptions)		0.0			0.7			0.0		0.0		0.7
Written options (swaptions)		0.0			(0.8	)		0.0		0.0		(0.8	)
Total derivatives		0.0			(0.4	)		0.0		0.0		(0.4	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	99.1		$	142.2		$	0.0	$	406.7	$	648.0

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

There are no assets associated with TECO Energy’s other postretirement benefits plan. Asset amounts shown in the tables above relate to a separate NMGC other postretirement benefit plan.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $55.0 million of contributions to this plan in 2015 and $47.5 million in 2014, which met the minimum funding requirements for both 2015 and 2014. TEC’s portion of the contribution in 2015 was $43.9 million and in 2014 was $38.2 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2016 to be $37.4 million, with TEC’s portion being $30.9 million. TECO Energy estimates it will make annual contributions from 2017 to 2020 ranging from $12.2 to $44.6 million per year based on current assumptions, with TEC’s portion to range from $8.0 million to $35.0 million. These amounts are in excess of the minimum funding required under ERISA guidelines.

TECO Energy made contributions of $43.4 million and $1.2 million to the SERP in 2015 and 2014, respectively. TEC’s portion of the contributions in 2015 and 2014 were $14.9 million and $0.8 million, respectively. TECO Energy’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera.

The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2016.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, TECO Energy expects to make a contribution of about $14.3 million. TEC’s portion of the expected contribution is $9.3 million. Postretirement benefit levels are substantially unrelated to salary.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective Jan. 1, 2015, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions with additional incentive match of up to 40%. For the years ended Dec. 31, 2015, 2014 and 2013, TECO Energy and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $7.5 million, $10.2 million and $9.1 million for 2015, 2014 and 2013, respectively.

At Dec. 31, 2015 and 2014, the following credit facilities and related borrowings existed:

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.

underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 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, 2043, TEC may at its option redeem the TEC 2014 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.

As of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

TEC reported the following OCI (loss) for the years ended Dec. 31, 2015, 2014 and 2013, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

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

TEC has commitments for capacity payments and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013, totaled $3.8 million, $4.1 million and $2.3 million, respectively. In addition, Tampa Electric has other purchase obligations, including its outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015:

At Dec. 31, 2015, TEC was not obligated under guarantees, but had the following letters of credit outstanding.

In order to utilize their respective bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2015, TEC was in compliance with all required financial covenants.

TEC had certain transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TEC, until his retirement from the Board in May 2013) was an employee.

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 719,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations			TEC
2015
Revenues - external	$	2,017.7	$	401.5	$	0.0		$	2,419.2
Sales to affiliates		0.6		6.0		(6.6	)		0.0
Total revenues		2,018.3		407.5		(6.6	)		2,419.2
Depreciation and amortization		256.7		56.8		0.0			313.5
Total interest charges		95.1		14.5		0.0			109.6
Provision for income taxes		143.6		21.9		0.0			165.5
Net income		241.0		35.3		0.0			276.3
Total assets		6,637.1		1,099.0		(9.4	)		7,726.7
Capital expenditures		592.6		94.0		0.0			686.6
2014
Revenues - external	$	2,020.5	$	398.5	$	0.0		$	2,419.0
Sales to affiliates		0.5		1.1		(1.6	)		0.0
Total revenues		2,021.0		399.6		(1.6	)		2,419.0
Depreciation and amortization		248.6		54.0		0.0			302.6
Total interest charges		92.8		13.8		0.0			106.6
Provision for income taxes		133.2		22.7		0.0			155.9
Net income		224.5		35.8		0.0			260.3
Total assets		6,234.4		1,047.0		(7.1	)		7,274.3
Capital expenditures		582.1		88.9		0.0			671.0
2013
Revenues - external	$	1,950.1	$	392.7	$	0.0		$	2,342.8
Sales to affiliates		0.4		0.8		(1.2	)		0.0
Total revenues		1,950.5		393.5		(1.2	)		2,342.8
Depreciation and amortization		238.8		51.5		0.0			290.3
Total interest charges		91.8		13.5		0.0			105.3
Provision for income taxes		116.9		21.9		0.0			138.8
Net income		190.9		34.7		0.0			225.6
Total assets		5,895.4		989.3		(8.9	)		6,875.8
Capital expenditures		422.3		79.0		0.0			501.3

TEC accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

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 14). 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 Dec. 31, 2015, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Dec. 31, 2015 and 2014 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative assets as of Dec. 31, 2015 and 2014. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at Dec. 31, 2015 and 2014 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 Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at Dec. 31, 2015, net pretax losses of $24.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The Dec. 31, 2015 and 2014 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 years ended Dec. 31, 2015, 2014 and 2013, 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 years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 8. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017 fiscal years:

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Dec. 31, 2015, 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.

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

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

The following table sets 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 Dec. 31, 2015 and 2014. 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.

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 13).

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 Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

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 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.

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, was obtained on Jan. 20, 2016), (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.

Asset		Estimated Useful Lives
Building and improvements		40 years

Office equipment and furniture		4 - 7 years

Computer software		3 - 15 years

(millions)
As of Dec. 31,	2015			2014
Deferred tax liabilities ⁽¹⁾
Property related	$	1,519.3		$	1,391.3
Pension		86.6			62.3
Total deferred tax liabilities		1,605.9			1,453.6
Deferred tax assets ⁽¹⁾
Alternative minimum tax credit carryforward		213.5			214.0
Loss and credit carryforwards ⁽²⁾		637.5			566.7
Other postretirement benefits		69.5			71.5
Other		117.5			159.6
Total deferred tax assets		1,038.0			1,011.8
Valuation allowance ⁽³⁾		(2.0	)		(4.6	)
Total deferred tax assets, net of valuation allowance		1,036.0			1,007.2
Total deferred tax liability, net		569.9			446.4
Less: Current portion of deferred tax asset		0.0			(72.8	)
Less: Long term portion of deferred tax asset		(0.8	)		0.0
Long-term portion of deferred tax liability, net	$	570.7		$	519.2

Funded Status	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Benefit obligation (PBO/APBO)	$	732.9		$	728.9		$	195.2		$	201.5
Less: Fair value of plan assets		625.4			648.0			20.6			18.8
Funded status at end of year	$	(107.5	)	$	(80.9	)	$	(174.6	)	$	(182.7	)

Amounts recognized in balance sheet	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Regulatory assets	$	208.2		$	167.4		$	32.4		$	26.6
Accrued benefit costs and other current liabilities		(10.5	)		(4.9	)		(10.7	)		(10.7	)
Deferred credits and other liabilities		(97.0	)		(76.0	)		(163.9	)		(172.0	)
Accumulated other comprehensive loss (income), pretax		55.7			36.3			(41.6	)		(34.6	)
Net amount recognized at end of year	$	156.4		$	122.8		$	(183.8	)	$	(190.7	)

	Pension Benefits						Other Benefits
	2015			2014			2015			2014
Discount rate		4.688	%		4.258	%		4.669	%		4.211	%
Rate of compensation increase—weighted		3.87	%		3.87	%		2.50	%		3.86	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				7.05	%		7.09	%
Ultimate rate	n/a			n/a				4.50	%		4.57	%
Year rate reaches ultimate	n/a			n/a			2038			2025

Fuel Inventory	Dec. 31,		Dec. 31,
(millions)	2015		2014
TEC	$	105.6	$	85.2
NMGC		7.8		11.2
Total	$	113.4	$	96.4

Obligations and Plan Assets	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Change in benefit obligation
Net benefit obligation at beginning of year	$	728.9		$	666.0		$	201.5		$	208.1
Service cost		20.9			18.3			2.2			2.5
Interest cost		30.3			32.0			8.2			10.8
Plan participants’ contributions		0.0			0.0			2.0			2.8
Plan amendments		0.0			0.0			(3.7	)		(23.2	)
Actuarial loss (gain)		5.8			48.3			(0.4	)		1.5
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Transfer in due to the effect of business combination		0.0			0.0			0.0			26.7
Plan curtailment		0.0			4.0			0.0			(11.7	)
Special termination benefit		0.0			0.2			0.0			0.0
Net benefit obligation at end of year	$	732.9		$	728.9		$	195.2		$	201.5

Change in plan assets
Fair value of plan assets at beginning of year	$	648.0		$	593.0		$	18.8		$	0.0
Actual return on plan assets		(25.5	)		46.4			(0.6	)		0.1
Employer contributions		55.0			47.5			1.5			(1.0	)
Employer direct benefit payments		0.9			1.0			13.5			16.0
Plan participants’ contributions		0.0			0.0			2.0			2.8
Transfer in due to acquisition		0.0			0.0			0.0			16.9
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Fair value of plan assets at end of year ⁽¹⁾	$	625.4		$	648.0		$	20.6			18.8

Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets	Pension Benefits				Other Benefits
(millions)	2015		2014		2015			2014
Net actuarial loss	$	263.6	$	203.7	$	10.9		$	9.6
Prior service cost (credit)		0.3		0.0		(25.0	)		(23.6	)
Unrecognized costs in regulated asset acquired in business combination		0.0		0.0		4.9			6.0
Amount recognized, pretax	$	263.9	$	203.7	$	(9.2	)	$	(8.0	)

		1%		1%
(millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	9.0	$	(7.7	)

New prior service cost	$	0.0		$	0.0		$	0.0		$	(3.7	)	$	(23.6	)	$	0.0
Net loss (gain) arising during the year		74.5			44.1			(75.7	)		1.3			(9.9	)		(15.6	)
Unrecognized costs in regulated asset acquired in business combination		0.0			0.0			0.0			0.0			6.4			0.0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)		(15.1	)		(13.5	)		(21.5	)		0.0			(0.2	)		(1.0	)
Amortization of prior service (benefit) cost		0.2		0.4				0.4			2.4			0.2			0.3
Total recognized in OCI and regulatory assets	$	59.6		$	31.0		$	(96.8	)	$	0.0		$	(27.1	)	$	(16.3	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	82.4		$	56.7		$	(67.0	)	$	6.9		$	(14.3	)	$	(3.9	)

	Target Allocation			Actual Allocation, End of Year
Asset Category				2015			2014
Equity securities	47%-53%				53	%		50	%
Fixed income securities	47%-53%				47	%		50	%
Total		100	%		100	%		100	%

			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2016	$	77.8	$	11.5
2017		49.5		11.9
2018		52.7		12.5
2019		59.2		13.0
2020		54.9		13.3
2021-2025		299.1		68.6

Assumptions	2015			2014			2013
Assumptions applicable to performance-based restricted stock
Risk-free interest rate		0.83	%		0.68	%		0.41	%
Expected lives (in years)		3			3			3
Expected stock volatility		14.78	%		17.36	%		19.04	%
Dividend yield		3.98	%		5.13	%		4.83	%

	Time-Based Restricted					Performance-Based
	Stock ⁽¹⁾					Restricted Stock ⁽¹⁾
				Weighted -					Weighted-
				Avg. Grant					Avg. Grant
	Number of			Date		Number of			Date
	Shares			Fair Value		Shares			Fair Value
	(thousands)			(per share)		(thousands)			(per share)
Nonvested balance at Dec. 31, 2014		668		$	17.56		1,515		$	15.44
Granted		213		$	21.34		445		$	23.72
Vested		(273	)	$	17.96		(626	)	$	15.94
Forfeited		(19	)	$	17.78		(43	)	$	16.05
Nonvested balance at Dec. 31, 2015		589		$	18.74		1,291		$	18.06

						Weighted-Avg.		Aggregate
	Number of			Weighted-Avg.		Remaining		Intrinsic
	Shares			Option Price		Contractual		Value
	(thousands)			(per share)		Term (years)		(millions)
Outstanding balance at Dec. 31, 2014		840		$	16.32
Granted		0		$	0.00
Exercised		(580	)	$	16.30
Cancelled		(6	)	$	18.87
Outstanding balance at Dec. 31, 2015 ⁽¹⁾		254		$	16.30		1	$	2.6
Exercisable at Dec. 31, 2015 ⁽¹⁾		254		$	16.30		1	$	2.6
Available for future grant at Dec. 31, 2015		2,429

(millions) Dec. 31,	2015			2014
Unamortized pension losses and prior service credits ⁽¹⁾	$	(34.2	)	$	(22.5	)
Unamortized other benefit gains, prior service costs and transition obligations ⁽²⁾		25.6			13.9
Net unrealized losses from cash flow hedges ⁽³⁾		(3.6	)		(7.1	)
Total accumulated other comprehensive loss	$	(12.2	)	$	(15.7	)

	Capacity		Operating		Net Purchase
(millions)	Payments		Leases⁽¹⁾		Obligations/Commitments ⁽¹⁾		Total
Year ended Dec. 31:
2016	$	14.6	$	7.7	$	222.5	$	244.8
2017		9.9		7.1		21.5		38.5
2018		10.1		6.4		9.6		26.1
2019		0.0		5.7		9.7		15.4
2020		0.0		5.4		4.7		10.1
Thereafter		0.0		18.6		20.0		38.6
Total future minimum payments	$	34.6	$	50.9	$	288.0	$	373.5

(millions)	Year of Expiration						Maximum
					After ⁽¹⁾		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Dec. 31, 2015
TECO Energy
Fuel sales and transportation⁽²⁾	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits⁽³⁾		90.0		0.0		0.0		90.0		0.0
	$	90.0	$	0.0	$	92.9	$	182.9	$	0.0

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		38.4
2017		0.0		5.1
Total		0.0		43.5

Components of income from discontinued operations
(millions)	2015			2014			2013
Revenues—TECO Coal	$	200.4		$	443.6		$	496.2
Income (loss) from operations—TECO Coal		(16.9	)		(13.9	)		5.4
Income (loss) from operations—TECO Guatemala		(0.8	)		4.4			(0.2	)
Loss on impairment—TECO Coal		(78.6	)		(115.9	)		0.0
Loss on sale—TECO Coal		(10.0	)		0.0			0.0
Income (loss) from discontinued operations—TECO Coal		(105.5	)		(129.8	)		5.4
Income (loss) from discontinued operations—TECO Guatemala		(0.8	)		4.4			(0.2	)
Income (loss) from discontinued operations		(106.3	)		(125.4	)		5.2
Provision (benefit) for income taxes		(38.6	)		(49.4	)		(3.8	)
Income (loss) from discontinued operations, net	$	(67.7	)	$	(76.0	)	$	9.0

(millions)
Cash paid to seller	$	530.1
Cash paid to settle long-term debt, including accrued interest and fees		219.9
Long-term debt assumed		200.0
Total consideration transferred, excluding cash and working capital adjustments	$	950.0

Purchase Price Allocation
(millions)
Current assets ⁽¹⁾	$	48.7
Property, plant and equipment		616.4
OPEB regulatory asset		6.4
Debt-related regulatory asset		23.9
Goodwill		408.4
Deferred tax assets		52.8
Other assets		29.3
Total assets	$	1,185.9
Current liabilities	$	(38.2	)
Long-term debt fair value adjustment and interest assumed		(22.7	)
Cost of removal regulatory liability		(100.6	)
Deferred tax liabilities		(60.8	)
OPEB liability		(9.8	)
Deferred credits and other liabilities		(3.8	)
Total liabilities	$	(235.9	)
Total purchase price allocation, excluding cash and working capital adjustments	$	950.0

Pro Forma Impact of Acquisition	For the year ended Dec. 31,
(millions, except per share amounts)	2014		2013
Revenues	$	2,806.6	$	2,704.0
Net income from continuing operations		223.8		216.8
Basic and diluted EPS from continuing operations		0.96		0.93

Transaction and Integration Costs	For the year ended Dec. 31,
(millions)	2015		2014
Legal and other consultants	$	0.5	$	8.0
Bridge loan costs		0.0		3.3
Severance and relocation costs		1.0		2.8
Other costs and tax benefit		0.4		(5.5	)
Total accounting charges	$	1.9	$	8.6

		Capital Stock Outstanding			Cash Dividends
	Current	Dec. 31,			Paid ⁽¹⁾
	Redemption				Per
(millions, except share amounts)	Price	Shares	Amount		Share			Amount
Common stock - without par value
25 million shares authorized
2015 ⁽³⁾	N/A	10	$	2,305.4		(2	)	$	268.4
2014 ⁽³⁾	N/A	10	$	2,130.4		(2	)	$	262.6

(millions)
For the year ending Dec. 31,	2015		2014			2013
Current income taxes
Federal	$	38.2	$	54.8		$	19.4
State		8.4		8.9			1.3
Deferred income taxes
Federal		102.9		79.0			99.8
State		14.5		13.5			18.6
Amortization of investment tax credits		1.5		(0.3	)		(0.3	)
Total income tax expense	$	165.5	$	155.9		$	138.8

Tampa Electric Company	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2015			2014			2015			2014
Regulatory assets	$	208.2		$	167.4		$	30.2		$	20.4
Accrued benefit costs and other current liabilities		(0.6	)		(0.6	)		(9.2	)		(9.1	)
Deferred credits and other liabilities		(69.3	)		(53.5	)		(142.3	)		(137.1	)
	$	138.3		$	113.3		$	(121.3	)	$	(125.8	)

Amounts recognized in regulatory assets	Pension Benefits					Other Benefits
(millions)	2015		2014			2015			2014
Net actuarial loss (gain)	$	208.2	$	167.7		$	47.2		$	39.5
Prior service cost (credit)		0.0		(0.3	)		(17.0	)		(19.1	)
Amount recognized	$	208.2	$	167.4		$	30.2		$	20.4

(millions)		1% Increase				1 % Decrease
Effect on postretirement benefit obligation		$	6.1			$	(5.2	)

(millions)		1% Increase				1% Decrease
Effect on periodic cost		$	0.2			$	(0.2	)

(including projected service and net of employee contributions)			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2016	$	77.8	$	11.5
2017		49.5		11.9
2018		52.7		12.5
2019		59.2		13.0
2020		54.9		13.3
2021-2025		299.1		68.6

(millions) As of Dec. 31,	2015			2014
Net unrealized losses from cash flow hedges ⁽¹⁾	$	(3.6	)	$	(7.1	)
Total accumulated other comprehensive loss	$	(3.6	)	$	(7.1	)