TECO Energy 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	350,563
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,494,800
Entity Public Float			$ 4,100
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	96,271
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Entity Public Float			$ 0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 23.8	$ 25.4
Receivables, less allowance for uncollectibles	280.7	299.8
Inventories, at average cost
Regulatory assets	44.8	53.6
Deferred income taxes	0	72.8
Prepayments and other current assets	30.8	22.6
Assets held for sale	0	109.6
Total current assets	570.3	755.6
Property, plant and equipment
Construction work in progress	794.7	640
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	59.8
Total other assets	909	882.4
Total assets	8,961.1	8,726.2
Current liabilities
Long-term debt due within one year	333.3	274.5
Notes payable	247	139
Accounts payable	255.4	288.6
Customer deposits	182.1	176.2
Regulatory liabilities	84.8	57
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	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
Regulatory liabilities	715.8	729
Derivative liabilities	2.1	6.1
Deferred credits and other liabilities	387.4	370.9
Liabilities associated with assets held for sale	0	65.4
Long-term debt, less amount due within one year	3,516.9	3,354
Total other liabilities	$ 5,203.4	$ 5,053.6
Commitments and Contingencies
Capital
Common equity	$ 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 capital	2,559	2,574.7
Total liabilities and capital	8,961.1	8,726.2
Long-term debt, less amount due within one year	3,516.9	3,354
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	9.1	10.4
Receivables, less allowance for uncollectibles	230.2	227.2
Inventories, at average cost
Taxes receivable from affiliate	61.3	43.3
Regulatory assets	44.3	52.1
Deferred income taxes	0	24.8
Prepayments and other current assets	21.5	17.4
Total current assets	545.1	532.6
Property, plant and equipment
Construction work in progress	771.1	624.2
Utility plant in service, at original costs	9,440	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
Other assets
Unamortized debt expense	18.1	16.8
Regulatory assets	373.8	319.6
Deferred charges and other assets	408.7	339
Other	16.8	2.6
Total assets	7,726.7	7,274.3
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	61	58
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
Taxes accrued	13.2	12.4
Other	10.2	10
Total current liabilities	689.8	684.7
Other liabilities
Deferred income taxes	1,308.8	1,209.1
Investment tax credits	10.5	9
Regulatory liabilities	603.5	623.4
Derivative liabilities	2.1	6.1
Deferred credits and other liabilities	316.7	299.1
Long-term debt, less amount due within one year	2,179.8	2,013.8
Total deferred credits	$ 2,241.6	$ 2,146.7
Commitments and Contingencies
Capital
Common equity	$ 2,305.4	$ 2,130.4
Retained earnings	313.7	305.8
Accumulated other comprehensive loss	(3.6)	(7.1)
Total capital	2,615.5	2,429.1
Total liabilities and capital	7,726.7	7,274.3
Long-term debt, less amount due within one year	2,179.8	2,013.8
Total capital	4,795.3	4,442.9
Fuel [Member]
Inventories, at average cost
Utility inventories	113.4	96.4
Fuel [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	105.6	85.2
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	76.8	75.4
Materials and Supplies [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	73.1	72.2
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,270.3	7,094.8
Electric [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,270.3	7,094.8
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	2,113.8	1,984.6
Gas [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,398.6	$ 1,308.9

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Allowance for uncollectibles	$ 2.1	$ 2.1
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	235,300,000	234,900,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 1.5	$ 1.4
Common equity, shares authorized	25,000,000	25,000,000
Common equity, shares outstanding	10	10

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 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
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	315.3	291.8
Taxes, other than income	207.4	195	184.7
Total expenses	2,181.4	2,061	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	8.1
Interest charges
Interest expense	195.1	176.4	165
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)	9
Net income	$ 173.5	$ 130.4	$ 197.7
Average common shares outstanding - Basic	233.1	223.1	215
Average common shares outstanding - Diluted	234.5	223.7	215.5
Earnings per share from continuing operations - Basic	$ 1.03	$ 0.92	$ 0.88
Earnings per share from continuing operations - Diluted	1.03	0.92	0.88
Earnings per share from discontinued operations - Basic	(0.29)	(0.34)	0.04
Earnings per share from discontinued operations - Diluted	(0.29)	(0.34)	0.04
Earnings per share - Basic	0.74	0.58	0.92
Earnings per share - Diluted	0.74	0.58	0.92
Dividends paid per common share outstanding	$ 0.90	$ 0.88	$ 0.88

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net income		$ 173.5		$ 130.4		$ 197.7
Other comprehensive income (loss), net of tax
Gain on cash flow hedges		3.5		0.7		1.4
Amortization of unrecognized benefit costs and other	[1]	2.1		(3)		14.8
Change in benefit obligation due to valuation		(9.8)		8		0
Increase in unrecognized postemployment costs		0		(8.2)	[2]	0
Recognized benefit costs due to settlement		7.7	[3]	0		1.6
Other comprehensive income (loss), net of tax		3.5		(2.5)		17.8
Comprehensive income		$ 177		$ 127.9		$ 215.5
[1]	Related to postretirement and postemployment benefits. See Note 5 for additional information.
[2]	Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability.
[3]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Note 19 for additional information.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 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
Depreciation and amortization	349	315.3	291.8
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, pretax	13.2	(0.2)	(1.6)
Deferred recovery clauses	26.4	(15.2)	(6.2)
Asset impairment	78.6	115.9	0
Receivables, less allowance for uncollectibles	36	(36.6)	(4.5)
Inventories	(22.6)	12.8	1.1
Prepayments and other current assets/deposits	(8)	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	(751.5)	0
Net proceeds from sales of business/assets	0	0.2	4.3
Other investments	(0.3)	(7.9)	0
Cash flows used in investing activities	(740)	(1,463)	(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
Repayment of long-term debt/Purchase in lieu of redemption	(274.5)	(83.3)	(51.6)
Net change in short-term debt	108	55	84
Cash flows from/(used in) financing activities	128.8	638.4	(152.1)
Net increase (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
Interest	179.6	161.3	161
Income taxes paid	14.5	2.9	1.8
Supplemental disclosure of non-cash activities
Debt assumed in NMGI acquisition	0	200	0
Change in accrued capital expenditures	8	13.3	4.7
Tampa Electric Company [Member]
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 (gain) on disposals of business/assets, pretax	3.1	0	0
Deferred recovery clauses	26.5	(16.2)	(6.2)
Receivables, less allowance for uncollectibles	(3)	0.4	(13.8)
Inventories	(21.3)	13.1	(9)
Prepayments and other current assets/deposits	(4)	1.5	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)	(501.3)
Net proceeds from sale of assets	0	0	0.1
Cash flows used in investing activities	(686.6)	(671)	(501.2)
Cash flows from financing activities
Dividends paid	(268.4)	(262.6)	(222.1)
Proceeds from the sale of common stock	175	100	60
Proceeds from long-term debt issuance	251.1	296.3	0
Repayment of long-term debt/Purchase in lieu of redemption	(83.3)	(83.3)	(51.6)
Net change in short-term debt	3	(26)	84
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
Interest	106.2	102.5	102.4
Income taxes paid	63.7	52.6	56.4
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ 6.9	$ 14.3	$ 4.7

Consolidated Statements of Capi

Consolidated Statements of Capital - USD ($) shares in Millions, $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Beginning Balance		$ 2,574.7		$ 2,333.7	$ 2,574.7	$ 2,333.7	$ 2,291.8
Net income	$ 50.5	58	$ 10.8	50.1	173.5	130.4	197.7
Other comprehensive income (loss), after tax					3.5	(2.5)	17.8
Common stock issued					5	300.8	5.9
Cash dividends declared					(211.7)	(199.2)	(191.2)
Stock compensation expense					13.1	12.7	13.5
Restricted stock—dividends					1.3	1.2	1.1
Tax short fall—stock compensation					(0.4)	(2.4)	(2.9)
Ending Balance	2,559		2,574.7		2,559	2,574.7	2,333.7
Common Stock [Member]
Beginning Balance		$ 234.9		$ 217.3	$ 234.9	$ 217.3	$ 216.6
Beginning Balance, shares		234.9		217.3	234.9	217.3	216.6
Common stock issued					$ 0.4	$ 17.6	$ 0.7
Common stock issued, shares					0.4	17.6	0.7
Ending Balance	$ 235.3		$ 234.9		$ 235.3	$ 234.9	$ 217.3
Ending Balance, shares	235.3		234.9		235.3	234.9	217.3
Additional Paid-in Capital [Member]
Beginning Balance		$ 1,875.9		$ 1,581.3	$ 1,875.9	$ 1,581.3	$ 1,564.5
Common stock issued					4.6	283.2	5.2
Stock compensation expense					13.1	12.7	13.5
Restricted stock—dividends					1.3	1.1	1
Tax short fall—stock compensation					(0.4)	(2.4)	(2.9)
Ending Balance	$ 1,894.5		$ 1,875.9		1,894.5	1,875.9	1,581.3
Retained Earnings [Member]
Beginning Balance		479.6		548.3	479.6	548.3	541.7
Net income					173.5	130.4	197.7
Cash dividends declared					(211.7)	(199.2)	(191.2)
Restricted stock—dividends						0.1	0.1
Ending Balance	441.4		479.6		441.4	479.6	548.3
Accumulated Other Comprehensive Income (Loss) [Member]
Beginning Balance		$ (15.7)		$ (13.2)	(15.7)	(13.2)	(31)
Other comprehensive income (loss), after tax					3.5	(2.5)	17.8
Ending Balance	$ (12.2)		$ (15.7)		$ (12.2)	$ (15.7)	$ (13.2)

Consolidated Statements of Inc8

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Total revenues	$ 2,743.5	$ 2,566.4	$ 2,355.1
Expenses
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
Depreciation and amortization	349	315.3	291.8
Taxes, other than income	207.4	195	184.7
Total expenses	2,181.4	2,061	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	8.1
Interest charges
Interest expense	195.1	176.4	165
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	173.5	130.4	197.7
Other comprehensive income, net of tax
Gain on cash flow hedges	3.5	0.7	1.4
Other comprehensive income (loss), net of tax	3.5	(2.5)	17.8
Comprehensive income	177	127.9	215.5
Tampa Electric Company [Member]
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	2,342.8
Expenses
Fuel	638.6	692.3	680.2
Purchased power	78.9	71.4	64.7
Cost of natural gas sold	135.5	137	142.6
Other	528.9	518.4	523.6
Depreciation and amortization	313.5	302.6	290.3
Taxes, other than income	192	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 (expense)
Allowance for other funds used during construction	17.2	10.5	6.3
Other income	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 from continuing operations 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
Other comprehensive income (loss), net of tax	3.5	0.7	0.9
Comprehensive income	$ 279.8	$ 261	$ 226.5

Consolidated Statements of Reta

Consolidated Statements of Retained Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Beginning Balance	$ 479.6
Add: Net income	173.5	$ 130.4	$ 197.7
Deduct: Cash dividends on capital stock—common	211.7	199.2	191.2
Ending Balance	441.4	479.6
Tampa Electric Company [Member]
Beginning Balance	305.8	308.1	304.6
Add: Net income	276.3	260.3	225.6
Retained Earning, Gross	582.1	568.4	530.2
Deduct: Cash dividends on capital stock—common	268.4	262.6	222.1
Ending Balance	$ 313.7	$ 305.8	$ 308.1

Consolidated Statements of Ca10

Consolidated Statements of Capitalization - Capital Stock (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Common equity, shares authorized	400,000,000	400,000,000	400,000,000	400,000,000
Capital Stock Outstanding December 31, Shares	235,300,000	234,900,000	235,300,000	234,900,000
Cash Dividends Paid Per Share	$ 0.225	$ 0.220	$ 0.90	$ 0.88
Cash Dividends Paid			$ 211.7	$ 199.2
Tampa Electric Company [Member]
Common equity, shares authorized	25,000,000	25,000,000	25,000,000	25,000,000
Capital Stock Outstanding December 31, Shares	10	10	10	10
Capital Stock Outstanding December 31, Amount	$ 2,305.4	$ 2,130.4	$ 2,305.4	$ 2,130.4
Cash Dividends Paid			$ 268.4	$ 262.6

Consolidated Statements of Ca11

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Preferred stock - par value	$ 1
Equity contributions made by TECO Energy	$ 175	$ 100
Preferred Stock Par Value [Member]
Preferred stock, shares authorized	10,000,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member]
Preferred stock - par value	$ 100
Preferred stock, no par value
Tampa Electric Company [Member] | Preferred Stock Par Value [Member]
Preferred stock, shares authorized	1,500,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preferred Stock No Par Value [Member]
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preference Stock No Par Value [Member]
Preferred stock, no par value
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

Consolidated Statements of Ca12

Consolidated Statements of Capitalization - Long-Term Debt (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, total	$ 3,835.9	$ 3,610.5
Unamortized debt discount, net	14.3	18
Long-term debt, carrying amount	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
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	261.7	241.7
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,265.9	2,099.3
Unamortized debt discount, net	(2.8)	(2.2)
Long-term debt, carrying amount	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
Long-term debt, fair value	2,433.3	2,372.2
Tampa Electric Company [Member] | Carrying Amount [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	2,263.1	2,097.1
Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,004.2	1,857.6
Long-term debt, carrying amount	$ 2,004.2
Tampa Electric Company [Member] | Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 54.2	54.2
Tampa Electric Company [Member] | Tampa Electric [Member] | Variable rate bonds repurchased in 2008 Due To 2020 [Member]
Debt Instrument [Line Items]
Due	2,020
Long-term debt, total	$ 0	0
Tampa Electric Company [Member] | Tampa Electric [Member] | 5.15% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2,025
Long-term debt, total	$ 0	0
Tampa Electric Company [Member] | Tampa Electric [Member] | 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Due	2,030
Long-term debt, total	$ 0	0
Tampa Electric Company [Member] | Tampa Electric [Member] | 5.0% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2,034
Long-term debt, total	$ 0	0
Tampa Electric Company [Member] | Tampa Electric [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Maturity range end	2,016
Maturity range start	2,015
Long-term debt, total	$ 83.3	166.7
Tampa Electric Company [Member] | Tampa Electric [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 200	200
Tampa Electric Company [Member] | Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2,021
Long-term debt, total	$ 231.7	231.7
Tampa Electric Company [Member] | Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2,022
Long-term debt, total	$ 225	225
Tampa Electric Company [Member] | Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Due	2,036
Long-term debt, total	$ 250	250
Tampa Electric Company [Member] | Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2,037
Long-term debt, total	$ 190	190
Tampa Electric Company [Member] | Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,042
Long-term debt, total	$ 250	250
Tampa Electric Company [Member] | Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2,044
Long-term debt, total	$ 290	290
Tampa Electric Company [Member] | Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2,045
Long-term debt, total	$ 230	0
Tampa Electric Company [Member] | PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	261.7	241.7
Long-term debt, carrying amount	$ 261.7
Tampa Electric Company [Member] | PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 50	50
Tampa Electric Company [Member] | PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2,021
Long-term debt, total	$ 46.7	46.7
Tampa Electric Company [Member] | PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2,022
Long-term debt, total	$ 25	25
Tampa Electric Company [Member] | PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2,037
Long-term debt, total	$ 60	60
Tampa Electric Company [Member] | PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,042
Long-term debt, total	$ 50	50
Tampa Electric Company [Member] | PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2,044
Long-term debt, total	$ 10	10
Tampa Electric Company [Member] | PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2,045
Long-term debt, total	$ 20	$ 0

Consolidated Statements of Ca13

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) (Detail) - Tampa Electric Company [Member] - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2013	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2008
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.65%
Tampa Electric [Member] | 5.15% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.15%
Variable rate bonds, par amounts		$ 51.6
Tampa Electric [Member] | 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Stated interest rate	1.50%
Variable rate bonds, par amounts				$ 75
Tampa Electric [Member] | 5.0% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
Tampa Electric [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.25%
Tampa Electric [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.55%
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
Tampa Electric [Member] | Variable rate bonds repurchased in 2008 Due To 2020 [Member]
Debt Instrument [Line Items]
Variable rate bonds, par amounts					$ 20
Tampa Electric [Member] | Variable Rate Bonds
Debt Instrument [Line Items]
Variable rate bonds, par amounts			$ 86
PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%

Consolidated Statements of Ca14

Consolidated Statements of Capitalization - Long-term Debt Maturities (Detail) $ in Millions	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Total long-term debt maturities	$ 3,850.2
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Total long-term debt maturities	2,263.1
Tampa Electric Company [Member] | Long Term Debt Maturities
Debt Instrument [Line Items]
2,016	83.3
2,017	0
2,018	304.2
2,019	0
2,020	0
Thereafter	1,878.4
Total long-term debt maturities	2,265.9
Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
2,016	83.3
2,017	0
2,018	254.2
2,019	0
2,020	0
Thereafter	1,666.7
Total long-term debt maturities	2,004.2
Tampa Electric Company [Member] | PGS [Member]
Debt Instrument [Line Items]
2,016	0
2,017	0
2,018	50
2,019	0
2,020	0
Thereafter	211.7
Total long-term debt maturities	$ 261.7

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies	1. Significant Accounting Policies Description of the Business 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 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 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 The company’s significant accounting policies are as follows: Principles of Consolidation and Basis of Presentation 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 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 Use of Estimates 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 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 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. Depreciation 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 group remaining life method, approved by the FPSC or NMPRC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; — the amortizable life method, approved by the FPSC or NMPRC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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: Asset Estimated Useful Lives Building and improvements 40 years Office equipment and furniture 4 - 7 years Computer software 3 - 15 years 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. Allowance for Funds Used During Construction 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. Inventory 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. Fuel Inventory Dec. 31, Dec. 31, (millions) 2015 2014 TEC $ 105.6 $ 85.2 NMGC 7.8 11.2 Total $ 113.4 $ 96.4 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. Regulatory Assets and Liabilities Tampa Electric, PGS and NMGC are subject to accounting guidance for the effects of certain types of regulation (see Note 3 Deferred Income Taxes 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 Investment Tax Credits 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 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 Employee Postretirement Benefits 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 Revenue Recognition 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 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 and Cost Recovery 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 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 and Allowance for Uncollectible Accounts 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. Accounting for Excise Taxes, Franchise Fees and Gross Receipts 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 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 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 Deferred credits and other liabilities primarily include the accrued postretirement and pension liabilities (see Note 5 Note 12 Stock-Based Compensation 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 Cash Flows Related to Derivatives and Hedging Activities 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. Reclassifications 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.
Tampa Electric Company [Member]
Significant Accounting Policies	1. Significant Accounting Policies TEC has two business segments. Its Tampa Electric Basis of Accounting 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 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. Principles of Consolidation 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 Cash Equivalents 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 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. 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. Depreciation 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 group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; · the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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. 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. Allowance for Funds Used During Construction 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. Inventory 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. Deferred Income Taxes 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. Investment Tax Credits 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. Revenue Recognition 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 Revenues and Cost Recovery 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 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 and Allowance for Uncollectible Accounts 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. Accounting for Excise Taxes, Franchise Fees and Gross Receipts 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. Deferred Credits and Other Liabilities Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5 Note 9 Cash Flows Related to Derivatives and Hedging Activities 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. Reclassifications 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.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements	2. New Accounting Pronouncements Revenue from Contracts with Customers 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. Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an 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. Disclosure of Investments Using Net Asset Value 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 Measurement Period Adjustments in Business Combinations 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. Balance Sheet Classification of Deferred Taxes 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. Recognition and Measurement of Financial Assets and Financial Liabilities 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. Leases 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 Company [Member]
New Accounting Pronouncements	2. New Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is 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. Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an 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. Disclosure of Investments Using Net Asset Value 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 Measurement Period Adjustments in Business Combinations 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. Balance Sheet Classification of Deferred Taxes 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. Recognition and Measurement of Financial Assets and Financial Liabilities 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. Leases 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 TEC beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Regulatory

Regulatory	12 Months Ended
	Dec. 31, 2015
Regulatory	3. Regulatory 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. Base Rates-Tampa Electric 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. Tampa Electric Storm Damage Cost Recovery 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. Base Rates-PGS 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. Base Rates-NMGC 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. Regulatory Assets and Liabilities Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table: Dec. 31, Dec. 31, (millions) 2015 2014 Regulatory assets: Regulatory tax asset (1) $ 74.7 $ 69.2 Cost-recovery clauses - deferred balances (2) 5.5 1.9 Cost-recovery clauses - offsets to derivative liabilities (2) 26.5 43.2 Environmental remediation (3) 54.0 53.1 Postretirement benefits (4) 240.6 194.0 Deferred bond refinancing costs (5) 6.5 7.2 Debt basis adjustment (6) 17.5 20.9 Competitive rate adjustment (2) 2.6 2.8 Other 12.1 9.8 Total regulatory assets 440.0 402.1 Less: Current portion 44.8 53.6 Long-term regulatory assets $ 395.2 $ 348.5 Regulatory liabilities: Regulatory tax liability $ 7.9 $ 6.9 Cost-recovery clauses (2) 55.9 25.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (7) 679.9 695.2 Other 0.8 1.9 Total regulatory liabilities 800.6 786.0 Less: Current portion 84.8 57.0 Long-term regulatory liabilities $ 715.8 $ 729.0 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.
Tampa Electric Company [Member]
Regulatory	3. Regulatory 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. Base Rates-Tampa Electric 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. Storm Damage Cost Recovery 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. Base Rates-PGS 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. Regulatory Assets and Liabilities Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table: Regulatory Assets and Liabilities Dec. 31, Dec. 31, (millions) 2015 2014 Regulatory assets: Regulatory tax asset (1) $ 74.6 $ 69.2 Cost-recovery clauses - deferred balances (2) 5.2 0.9 Cost-recovery clauses - offsets to derivative liabilities (2) 26.2 42.7 Environmental remediation (3) 54.0 53.1 Postretirement benefits (4) 238.3 187.8 Deferred bond refinancing costs (5) 6.5 7.2 Competitive rate adjustment (2) 2.6 2.8 Other 10.7 8.0 Total regulatory assets 418.1 371.7 Less: Current portion 44.3 52.1 Long-term regulatory assets $ 373.8 $ 319.6 Regulatory liabilities: Regulatory tax liability $ 5.7 $ 5.1 Cost-recovery clauses (2) 54.2 23.5 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (6) 570.0 591.5 Other 0.7 1.9 Total regulatory liabilities 686.7 678.1 Less: Current portion 83.2 54.7 Long-term regulatory liabilities $ 603.5 $ 623.4 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes	4. Income Taxes Income Tax Expense 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. Income tax expense consists of the following: Income Tax Expense (Benefit) (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: Effective Income Tax Rate (millions) For the year ended Dec. 31, 2015 2014 2013 Income tax expense at the federal statutory rate of 35% $ 138.8 $ 120.9 $ 105.5 Increase (decrease) due to: State income tax, net of federal income tax 13.6 17.0 7.5 Valuation allowance 0.1 0.9 0.0 Other 2.8 0.1 (0.4 ) Total income tax expense from continuing operations $ 155.3 $ 138.9 $ 112.6 Income tax expense as a percent of income from continuing operations, before income taxes 39.2 % 40.2 % 37.4 % 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 Deferred Income Taxes The major components of the company’s deferred tax assets and liabilities recognized are as follows: (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 (1) Certain property related assets and liabilities have been netted. (2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2015 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $2.6 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized. (3) During 2015, the valuation allowance related to discontinued operations decreased from $3.6 million to $1.0 million. 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. Unrecognized Tax Benefits 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: (millions) 2015 2014 2013 Balance at Jan. 1, $ 0.0 $ 0.0 $ 2.9 Decreases due to expiration of statute of limitations 0.0 0.0 (2.9 ) Balance at Dec. 31 $ 0.0 $ 0.0 $ 0.0 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.
Tampa Electric Company [Member]
Income Taxes	4. Income Taxes Income Tax Expense 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. Income tax expense consists of the following components: Income Tax Expense (Benefit) (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 The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows: Effective Income Tax Rate (millions) For the years ended Dec. 31, 2015 2014 2013 Income tax expense at the federal statutory rate of 35% $ 154.6 $ 145.7 $ 127.5 Increase (decrease) due to State income tax, net of federal income tax 14.8 14.5 13.0 Other (3.9 ) (4.3 ) (1.7 ) Total income tax expense on consolidated statements of income $ 165.5 $ 155.9 $ 138.8 Income tax expense as a percent of income from continuing operations, before income taxes 37.5 % 37.5 % 38.1 % Deferred Income Taxes 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: (millions) As of Dec. 31, 2015 2014 Deferred tax liabilities (1) Property related $ 1,431.9 $ 1,328.8 Pension and postretirement benefits 92.0 72.5 Pension 71.1 51.8 Total deferred tax liabilities 1,595.0 1,453.1 Deferred tax assets (1) Loss and credit carryforwards 80.0 77.7 Medical benefits 47.7 51.0 Insurance reserves 27.6 29.0 Pension and postretirement benefits 92.0 72.5 Capitalized energy conservation assistance costs 21.4 20.3 Other 17.5 18.3 Total deferred tax assets 286.2 268.8 Total deferred tax liability, net 1,308.8 1,184.3 Less: Current portion of deferred tax asset 0.0 (24.8 ) Long-term portion of deferred tax liability, net $ 1,308.8 $ 1,209.1 (1) Certain property related assets and liabilities have been netted. 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. Unrecognized Tax Benefits 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.

Employee Postretirement Benefit

Employee Postretirement Benefits	12 Months Ended
	Dec. 31, 2015
Employee Postretirement Benefits	5. Employee Postretirement Benefits Pension Benefits 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. Other Postretirement Benefits 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. Obligations and Funded Status 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). 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 (1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years. 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: 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 ) 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: 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 ) 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. 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 ) Assumptions used to determine benefit obligations at Dec. 31: 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 A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation: 1% 1% (millions) Increase Decrease Effect on postretirement benefit obligation $ 9.0 $ (7.7 ) 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. Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets (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 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 ) 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: Pension Benefits Other Benefits 2015 2014 (1) 2013 2015 2014 2013 Discount rate 4.258 % 5.118%/4.277%/4.331% 4.196 % 4.211 % 5.096 % 4.180 % Expected long-term return on plan assets 7.00 % 7.25%/7.00%/7.00% 7.50 % 5.75 5.75 n/a Rate of compensation increase 3.87 % 3.73 % 3.76 % 3.86 % 3.71 % 3.74 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.09 % 7.25 % 7.50 % Ultimate rate n/a n/a n/a 4.57 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2025 2025 2025 (1) TECO Energy performed a valuation as of Jan. 1, 2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs. 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: 1% 1% (millions) Increase Decrease Effect on periodic cost $ 0.4 $ (0.3 ) Pension Plan Assets 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. 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 % 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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. (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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. The following list details the pricing inputs and methodologies used to value the investments in the pension plan: — The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. — The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System. The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis. — The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost. — The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. — Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. — Swaps are valued using benchmark yields, swap curves, and cash flow analyses. — Options are valued using the bid-ask spread and the last price. — The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. — The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. — The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. — The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15 th th 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. Other Postretirement Benefit Plan Assets 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. Contributions 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. Benefit Payments The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Expected Benefit Payments (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 Defined Contribution Plan 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.
Tampa Electric Company [Member]
Employee Postretirement Benefits	5. Employee Postretirement Benefits Pension Benefits 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. Other Postretirement Benefits 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. 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 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. 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 reduced 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, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued 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 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. Obligations and Funded Status 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). TECO Energy Pension Benefits Other Benefits Obligations and Funded Status (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 (1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years. 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: 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 ) 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: 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 ) 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. 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 Assumptions used to determine benefit obligations at Dec. 31: Pension Benefits Other Benefits 2015 2014 2015 2014 Discount rate 4.688 % 4.258 % 4.669 % 4.211 % Rate of compensation increase-weighted average 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 A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation: (millions) 1% Increase 1 % Decrease Effect on postretirement benefit obligation $ 6.1 $ (5.2 ) 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. Amounts recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets 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 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 ) 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: Pension Benefits Other Benefits 2015 2014 (1) 2013 2015 2014 2013 Discount rate 4.258 % 5.118%/4.277%/4.331% 4.196 % 4.211 % 5.096 % 4.180 % Expected long-term return on plan assets 7.00 % 7.25%/7.00%/7.00% 7.50 % 5.75 5.75 n/a Rate of compensation increase 3.87 % 3.73 % 3.76 % 3.86 % 3.71 % 3.74 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.09 % 7.25 % 7.50 % Ultimate rate n/a n/a n/a 4.57 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2025 2025 2025 (1) 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. 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%. 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 TEC’s expense: (millions) 1% Increase 1% Decrease Effect on periodic cost $ 0.2 $ (0.2 ) Pension Plan Assets 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. Target Allocation Actual Asset Category 2015 2014 Equity securities 47%-53% 53 % 50 % Fixed income securities 47%-53% 47 % 50 % Total 100% 100 % 100 % 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. 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. Pension Plan Investments (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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. (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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. The following list details the pricing inputs and methodologies used to value the investments in the pension plan: — The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. — The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System. The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis. — The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost. — The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. — Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. — Swaps are valued using benchmark yields, swap curves, and cash flow analyses. — Options are valued using the bid-ask spread and the last price. — The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. — The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. — The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. — The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15 th th 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. Other Postretirement Benefit Plan Assets 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. Contributions 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 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. 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. 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. Benefit Payments The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Expected Benefit Payments—TECO Energy (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 Defined Contribution Plan 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.

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2015
Short-Term Debt	6. Short-Term Debt At Dec. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities 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 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. ( 4 ) TECO Finance is the borrower and TECO Energy is the guarantor of this facility. 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. Tampa Electric Company Accounts Receivable Facility 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. TECO Energy Credit Agreement Assigned to and Assumed by NMGC 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. Amendment of Tampa Electric Company Credit Facility 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) 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. Amendments of TECO Energy/TECO Finance Credit Facility 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 On Sept. 30, 2014, the TECO Credit Facility was amended to increase total commitments to $300 million and to reallocate commitments among the lenders.
Tampa Electric Company [Member]
Short-Term Debt	6. Short-Term Debt At Dec. 31, 2015 and 2014, the following credit facilities and related borrowings existed: Credit Facilities 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 Total $ 475.0 $ 61.0 $ 0.5 $ 475.0 $ 58.0 $ 0.6 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. 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 0.89% and 0.7%, respectively. Tampa Electric Company Accounts Receivable Facility 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. Amendment of Tampa Electric Company Credit Facility 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) 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.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-Term Debt	7. Long-Term Debt 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. 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. TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2016 through 2020 and thereafter are as follows: Long-Term Debt Maturities 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 Issuance of TECO Finance Floating Rate Notes due 2018 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 . Issuance of Tampa Electric Company 4.20% Notes due 2045 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. Issuance of Tampa Electric Company 4.35% Notes due 2044 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. Issuance of New Mexico Gas Intermediate Senior Unsecured Notes 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. Issuance of New Mexico Gas Company Senior Unsecured 3.54 % Notes due 2026 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. Amendment of New Mexico Gas Company 4.87 % Notes due 2021 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. Purchase in Lieu of Redemption of Revenue Refunding Bonds 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) (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) 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) 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) 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) 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 (1) Guaranteed by TECO Energy. (2) These long-term debt agreements contain various restrictive financial covenants. (3) These securities are subject to redemption in whole or in part, at any time, at the option of the issuer. (4) Tax-exempt securities. (5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020. (6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025. (7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030. (8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.
Tampa Electric Company [Member]
Long-Term Debt	7. Long-Term Debt 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. Issuance of Tampa Electric Company 4.20% Notes due 2045 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. Issuance of Tampa Electric Company 4.35% Notes due 2044 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. Purchase in Lieu of Redemption of Revenue Refunding Bonds 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.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Preferred Stock	8. Preferred Stock Preferred stock of TECO Energy – $1 par 10 million shares authorized, none outstanding. Preference stock (subordinated preferred stock) of Tampa Electric – no par 2.5 million shares authorized, none outstanding. Preferred stock of Tampa Electric – no par 2.5 million shares authorized, none outstanding. Preferred stock of Tampa Electric – $100 par 1.5 million shares authorized, none outstanding.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Common Stock	9. Common Stock Pending Merger with Emera 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. See Note 21 Public Offering of 15.5 million in Common Shares 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. Stock-Based Compensation 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. 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 % 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. (millions) 2015 2014 2013 Compensation costs (1) $ 13.1 $ 12.7 $ 13.5 Income tax benefits (1) 5.1 4.9 5.2 Excess tax benefits (2) 0.0 0.4 0.0 (1) Reflected on the Consolidated Statements of Income. (2) Reflected as financing activities on the Consolidated Statements of Cash Flows. 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. A summary of non-vested shares of restricted stock is shown as follows: Nonvested Restricted Stock 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 (1) The weighted-average remaining contractual term of restricted stock is two years. Stock option transactions are summarized as follows: Stock Options 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 (1) Option prices are $16.30 per share. Direct Stock Purchase and Dividend Reinvestment Plan 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.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Other Comprehensive Income	10. Other Comprehensive Income 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 (1) Related to interest rate contracts in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations. (2) Related to postretirement and postemployment benefits. See Note 5 (3) Related to the transfer of employees and their associated postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI. (4) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Note 19 (5 ) Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability. ( 6 ) Includes an adjustment to eliminate TECO Coal’s OPEB liability. See Note 5 Accumulated Other Comprehensive Loss (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 ) ( 1 ) Net of tax benefit of $21.5 million and $13.8 million as of Dec. 31, 2015 and 2014, respectively. ( 2 ) Net of tax expense of $16.1 million and $8.3 million as of Dec. 31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5 ( 3 ) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	8. Other Comprehensive Income 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: Other Comprehensive Income (millions) Gross Tax Net 2015 Unrealized gain (loss) on cash flow hedges $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 1.4 (0.7 ) 0.7 Gain (Loss) on cash flow hedges 5.7 (2.2 ) 3.5 Total other comprehensive income (loss) $ 5.7 $ (2.2 ) $ 3.5 2014 Unrealized gain (loss) on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.1 (0.4 ) 0.7 Gain (Loss) on cash flow hedges 1.1 (0.4 ) 0.7 Total other comprehensive income (loss) $ 1.1 $ (0.4 ) $ 0.7 2013 Unrealized gain (loss) on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.4 (0.5 ) 0.9 Gain (Loss) on cash flow hedges 1.4 (0.5 ) 0.9 Total other comprehensive income (loss) $ 1.4 $ (0.5 ) $ 0.9 Accumulated Other Comprehensive Loss (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 ) (1) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	11. Earnings Per Share 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 (1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 19

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies	12. Commitments and Contingencies Legal Contingencies From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. 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. Tampa Electric Legal Proceedings 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. Peoples Gas Legal Proceedings In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, 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. New Mexico Gas Company Legal Proceedings In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business). In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.” In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. 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. TECO Guatemala Holdings, LLC v. The Republic of Guatemala On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. 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. Proceedings in connection with the Pending Merger with Emera Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction. Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger. 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. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of 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. Long-Term Commitments 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: 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 (1) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. The table above excludes payment obligations under contractual agreements of Tampa Electric, PGS and NMGC for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses. Guarantees and Letters of Credit 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: — Initial recognition and initial measurement of a liability, and/or — Disclosure of specific details of the guarantee. 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: (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 (millions) Year of Expiration Maximum After (1) Theoretical Liabilities Recognized Letter of Credit for the Benefit of: 2016 2017-2020 2020 Obligation at Dec. 31, 2015 (4) TEC $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 NMGC $ 0.0 $ 0.0 $ 1.7 $ 1.7 $ 0.0 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Dec. 31, 2015. See Note 16 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 19 (4) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims. Financial Covenants 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.
Tampa Electric Company [Member]
Commitments and Contingencies	9. Commitments and Contingencies Legal Contingencies From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. 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. Tampa Electric Legal Proceedings 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 TEC’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 TEC’s financial position as of Dec. 31, 2015. Peoples Gas Legal Proceedings In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, 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. 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. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of 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. Long-Term Commitments 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: Capacity Operating Net Purchase (millions) Payments Leases (1) Obligations/Commitments (1) Total Year ended Dec. 31: 2016 $ 14.6 $ 5.7 $ 218.3 $ 238.6 2017 9.9 5.2 21.5 36.6 2018 10.1 4.7 9.6 24.4 2019 0.0 4.4 9.7 14.1 2020 0.0 4.1 4.7 8.8 Thereafter 0.0 14.5 20.0 34.5 Total future minimum payments $ 34.6 $ 38.6 $ 283.8 $ 357.0 (1) Excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually. Guarantees and Letters of Credit At Dec. 31, 2015, TEC was not obligated under guarantees, but had the following letters of credit outstanding. (millions) Year of Expiration Maximum After (1) Theoretical Liabilities Recognized Letter of Credit for the Benefit of: 2016 2017-2020 2020 Obligation at Dec. 31, 2015 (2) TEC $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims . Financial Covenants 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions	13. Related Party Transactions 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.
Tampa Electric Company [Member]
Related Party Transactions	10. Related Party Transactions A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2015 2014 2013 Natural gas sales, net $ 0.8 $ 0.3 $ 18.3 Administrative and general, net (1) $ 69.4 $ 22.5 $ 27.2 (1) The 2015 increase in transactions with affiliates is attributable to shared services being provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning in Jan. 1, 2015. Amounts due from or to affiliates at Dec. 31, (millions) 2015 2014 Accounts receivable (1) $ 2.3 $ 2.4 Accounts payable (1) 15.9 9.7 Taxes receivable (2) 61.3 43.3 Taxes payable (2) 1.0 0.0 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) Taxes receivable are due from, and taxes payable are due to, TECO Energy. 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.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Information	14. Segment Information 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 (1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2015, 2014 and 2013 were at a pretax rate of 6.00%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure. (2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Other, including Parent and TECO Diversified, that directly relate to TECO Coal or TECO Guatemala. See Note 19 (3) The carrying value of mineral rights as of Dec. 31, 2015, 2014 and 2013 was $0.0 million, $10.9 million and $12.1 million, respectively. (4) NMGI is included in the Other segment. (5) Certain prior year amounts have been reclassified to conform to current year presentation. (6) Amounts primarily relate to consolidated tax eliminations.
Tampa Electric Company [Member]
Segment Information	11. Segment Information 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

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations	15. Asset Retirement Obligations 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: Dec. 31, (millions) 2015 2014 Beginning balance $ 6.1 $ 28.6 Additional liabilities 0.9 0.1 Revisions to estimated cash flows (0.5 ) 0.2 Acquisition of NMGC 0.0 0.8 Reclassification to liabilities associated with assets held for sale 0.0 (22.5 ) Other (1) 0.3 (1.1 ) Ending balance $ 6.8 $ 6.1 (1) 2015 includes $0.3 million accretion recorded as a deferred regulatory asset. 2014 includes $(1.3) million of activity associated with TECO Coal and classified as discontinued operations and $0.2 million accretion recorded as a deferred regulatory asset.
Tampa Electric Company [Member]
Asset Retirement Obligations	12. Asset Retirement Obligations 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. 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. 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: Dec. 31, (millions) 2015 2014 Beginning balance $ 5.3 $ 4.8 Additional liabilities 0.9 0.1 Revisions to estimated cash flows (0.5 ) 0.2 Other (1) 0.3 0.2 Ending balance $ 6.0 $ 5.3 (1) Accretion recorded as a deferred regulatory asset.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2015
Accounting for Derivative Instruments and Hedging Activities	16. Accounting for Derivative Instruments and Hedging Activities From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes: · To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; and · To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates. TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 17 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 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: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 38.4 2017 0.0 5.1 Total 0.0 43.5 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.
Tampa Electric Company [Member]
Accounting for Derivative Instruments and Hedging Activities	13. Accounting for Derivative Instruments and Hedging Activities From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes: · To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and · To limit the exposure to interest rate fluctuations on debt securities. TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 14 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 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: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 27.6 2017 0.0 5.0 Total 0.0 32.6 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements	17. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance: (A) Market approach : Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; (B) Cost approach Amount that would be required to replace the service capacity of an asset (replacement cost); and (C) Income approach Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). The fair value of financial instruments is determined by using various market data and other valuation techniques. The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as 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. Recurring Fair Value Measures As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.2 $ 0.0 $ 26.2 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas derivatives $ 0.0 $ 42.7 $ 0.0 $ 42.7 The natural gas derivatives are OTC swap 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
Tampa Electric Company [Member]
Fair Value Measurements	14. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance: (A) Market approach : Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; (B) Cost approach Amount that would be required to replace the service capacity of an asset (replacement cost); and (C) Income approach Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). The fair value of financial instruments is determined by using various market data and other valuation techniques. The following 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. Recurring Derivative Fair Value Measures As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 42.7 $ 0.0 $ 42.7 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.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities	18. Variable Interest Entities The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 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.
Tampa Electric Company [Member]
Variable Interest Entities	15. Variable Interest Entities The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 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. 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.

Discontinued Operations, Assets

Discontinued Operations, Assets Held for Sale and Asset Impairments	12 Months Ended
	Dec. 31, 2015
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations, Assets Held for Sale and Asset Impairments	19. Discontinued Operations, Assets Held for Sale and Asset Impairments TECO Coal 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 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: Assets held for sale (millions) Dec. 31, 2014 Current assets $ 109.6 Property, plant and equipment, net and other long-term assets 59.8 Total assets held for sale $ 169.4 Liabilities associated with assets held for sale (millions) Current liabilities $ 39.4 Long-term liabilities 65.4 Total liabilities associated with assets held for sale $ 104.8 TECO Guatemala In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 12 Combined components of income from discontinued operations The following table provides selected components of discontinued operations related to TECO Coal and TECO Guatemala: 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

Goodwill and Asset Impairments

Goodwill and Asset Impairments	12 Months Ended
	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	20. Goodwill The following table presents the changes in the carrying amount of goodwill for the years ended Dec. 31, 2015, 2014 and 2013. (millions) NMGC Total Balance as of Dec. 31, 2013 $ 0.0 $ 0.0 Acquisition of NMGC 408.3 408.3 Balance as of Dec. 31, 2014 408.3 408.3 Measurement period adjustments (1) 0.1 0.1 Balance as of Dec. 31, 2015 $ 408.4 $ 408.4 (1) Due to immateriality, the measurement period adjustment was not applied retrospectively to the opening balance sheet. 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 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.

Mergers and Acquisitions

Mergers and Acquisitions	12 Months Ended
	Dec. 31, 2015
Mergers and Acquisitions	21. Mergers and Acquisitions Pending Merger with Emera Inc. 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. Acquisition of New Mexico Gas Company Description of Transaction 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. Description of NMGC 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. Strategic Rationale for Acquisition · A transformative transaction that immediately added more than 513,000 customers in a single state. · Provides an opportunity for TECO Energy’s experienced management team to share marketing expertise to a new and growing service territory, and for both companies to share best practices to support growth. · Diversifies TECO Energy’s operating footprint. · Provides immediate to near-term shareholder and customer benefits through organic growth opportunities. Acquisition-Related Regulatory Matters 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: · freeze rates for NMGC customers until the end of 2017, · credit NMGC customers with a $2 million rate credit to customer bills in 2015, increasing to $4 million per year in 2016 and each year after 2016 until NMGC’s next rate case, · cap job losses in New Mexico at 99 over three years, many of which will be through attrition, · maintain the NMGC name and headquarters in Albuquerque, · support new economic development opportunities designed to attract new businesses to New Mexico through maintaining good service and reasonable customer rates, · maintain or increase NMGC’s current level of community involvement and support, and · own NMGC for at least 10 years. 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. Purchase Price The total consideration in the acquisition was as follows: Consideration Transferred (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 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: 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 (1) Includes accounts receivables with fair value of $18.9 million, gross contract value of $19.6 million, and $0.7 million of contractual receivables not expected to be collected. Impact of Acquisition 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. Pro Forma Impact of the Acquisition 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. 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 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. 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 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.
Tampa Electric Company [Member]
Mergers and Acquisitions	16. Mergers and Acquisitions Pending Merger with Emera Inc. 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 (of which TEC’s portion of debt was $2.3 billion). 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. 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.

Quarterly Data (unaudited)

Quarterly Data (unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Data (unaudited)	22. Quarterly Data (unaudited) Financial data by quarter is as follows: (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

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	23. Subsequent Events Amendment of TECO Energy/TECO Finance Credit Facility 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. TECO Energy/TECO Finance One-Year Term Loan 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.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts and Reserves	12 Months Ended
	Dec. 31, 2015
Valuation And Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts and Reserves	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES TECO ENERGY, INC. VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended Dec. 31, 2015, 2014 and 2013 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions Period Allowance for Uncollectible Accounts: 2015 $ 2.1 $ 2.7 $ 0.0 $ 2.7 (1) $ 2.1 2014 $ 4.7 $ 1.4 $ 0.7 $ 4.7 (1) $ 2.1 2013 $ 4.2 $ 3.3 $ 0.0 $ 2.8 (1) $ 4.7 Deferred Tax Valuation Allowance: 2015 $ 4.6 $ 1.0 $ 0.0 $ 3.6 (2) $ 2.0 2014 $ 0.0 $ 4.6 $ 0.0 $ 0.0 $ 4.6 2013 $ 3.0 $ 0.0 $ 0.0 $ 3.0 (2) $ 0.0 (1) Write-off of individual bad debt accounts (2) Release of valuation allowance SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES TAMPA ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended Dec. 31, 2015, 2014 and 2013 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions (1) Period Allowance for Uncollectible Accounts: 2015 $ 1.4 $ 2.7 $ 0.0 $ 2.6 $ 1.5 2014 $ 2.0 $ 2.7 $ 0.0 $ 3.3 $ 1.4 2013 $ 1.5 $ 3.3 $ 0.0 $ 2.8 $ 2.0 (1) Write-off of individual bad debt accounts

Significant Accounting Polici39

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation 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 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
Use of Estimates	Use of Estimates 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	Cash Equivalents 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	Property, Plant and Equipment 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.
Depreciation	Depreciation 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 group remaining life method, approved by the FPSC or NMPRC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; — the amortizable life method, approved by the FPSC or NMPRC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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: Asset Estimated Useful Lives Building and improvements 40 years Office equipment and furniture 4 - 7 years Computer software 3 - 15 years 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.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction 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.
Inventory	Inventory 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. Fuel Inventory Dec. 31, Dec. 31, (millions) 2015 2014 TEC $ 105.6 $ 85.2 NMGC 7.8 11.2 Total $ 113.4 $ 96.4 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.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Tampa Electric, PGS and NMGC are subject to accounting guidance for the effects of certain types of regulation (see Note 3
Deferred Income Taxes	Deferred Income Taxes 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
Investment Tax Credits	Investment Tax Credits 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	Goodwill 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
Employee Postretirement Benefits	Employee Postretirement Benefits 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
Revenue Recognition	Revenue Recognition 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 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 and Cost Recovery	Revenues and Cost Recovery 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 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 and Allowance for Uncollectible Accounts	Receivables and Allowance for Uncollectible Accounts 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.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts	Accounting for Excise Taxes, Franchise Fees and Gross Receipts 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	Deferred Charges and Other Assets 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 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	Deferred Credits and Other Liabilities Deferred credits and other liabilities primarily include the accrued postretirement and pension liabilities (see Note 5 Note 12
Stock-Based Compensation	Stock-Based Compensation 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
Cash Flows Related to Derivatives and Hedging Activities	Cash Flows Related to Derivatives and Hedging Activities 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.
Reclassifications	Reclassifications 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.
Tampa Electric Company [Member]
Cash Equivalents	Cash Equivalents 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	Property, Plant and Equipment 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. 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.
Depreciation	Depreciation 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 group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; · the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 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. 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.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction 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.
Inventory	Inventory 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.
Deferred Income Taxes	Deferred Income Taxes 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.
Investment Tax Credits	Investment Tax Credits 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.
Revenue Recognition	Revenue Recognition 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
Revenues and Cost Recovery	Revenues and Cost Recovery 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 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 and Allowance for Uncollectible Accounts	Receivables and Allowance for Uncollectible Accounts 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.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts	Accounting for Excise Taxes, Franchise Fees and Gross Receipts 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.
Deferred Credits and Other Liabilities	Deferred Credits and Other Liabilities Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5 Note 9
Cash Flows Related to Derivatives and Hedging Activities	Cash Flows Related to Derivatives and Hedging Activities 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.
Reclassifications	Reclassifications 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.
Basis of Accounting	Basis of Accounting 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 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.
Principles of Consolidation	Principles of Consolidation 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

Significant Accounting Polici40

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Estimated Useful Lives of Depreciable Property	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: Asset Estimated Useful Lives Building and improvements 40 years Office equipment and furniture 4 - 7 years Computer software 3 - 15 years
Schedule of Fuel Inventory	Fuel Inventory Dec. 31, Dec. 31, (millions) 2015 2014 TEC $ 105.6 $ 85.2 NMGC 7.8 11.2 Total $ 113.4 $ 96.4

Regulatory (Tables)

Regulatory (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table: Dec. 31, Dec. 31, (millions) 2015 2014 Regulatory assets: Regulatory tax asset (1) $ 74.7 $ 69.2 Cost-recovery clauses - deferred balances (2) 5.5 1.9 Cost-recovery clauses - offsets to derivative liabilities (2) 26.5 43.2 Environmental remediation (3) 54.0 53.1 Postretirement benefits (4) 240.6 194.0 Deferred bond refinancing costs (5) 6.5 7.2 Debt basis adjustment (6) 17.5 20.9 Competitive rate adjustment (2) 2.6 2.8 Other 12.1 9.8 Total regulatory assets 440.0 402.1 Less: Current portion 44.8 53.6 Long-term regulatory assets $ 395.2 $ 348.5 Regulatory liabilities: Regulatory tax liability $ 7.9 $ 6.9 Cost-recovery clauses (2) 55.9 25.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (7) 679.9 695.2 Other 0.8 1.9 Total regulatory liabilities 800.6 786.0 Less: Current portion 84.8 57.0 Long-term regulatory liabilities $ 715.8 $ 729.0 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.
Tampa Electric Company [Member]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table: Regulatory Assets and Liabilities Dec. 31, Dec. 31, (millions) 2015 2014 Regulatory assets: Regulatory tax asset (1) $ 74.6 $ 69.2 Cost-recovery clauses - deferred balances (2) 5.2 0.9 Cost-recovery clauses - offsets to derivative liabilities (2) 26.2 42.7 Environmental remediation (3) 54.0 53.1 Postretirement benefits (4) 238.3 187.8 Deferred bond refinancing costs (5) 6.5 7.2 Competitive rate adjustment (2) 2.6 2.8 Other 10.7 8.0 Total regulatory assets 418.1 371.7 Less: Current portion 44.3 52.1 Long-term regulatory assets $ 373.8 $ 319.6 Regulatory liabilities: Regulatory tax liability $ 5.7 $ 5.1 Cost-recovery clauses (2) 54.2 23.5 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (6) 570.0 591.5 Other 0.7 1.9 Total regulatory liabilities 686.7 678.1 Less: Current portion 83.2 54.7 Long-term regulatory liabilities $ 603.5 $ 623.4 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Income Tax Expense	Income tax expense consists of the following: Income Tax Expense (Benefit) (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
Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes	The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows: Effective Income Tax Rate (millions) For the year ended Dec. 31, 2015 2014 2013 Income tax expense at the federal statutory rate of 35% $ 138.8 $ 120.9 $ 105.5 Increase (decrease) due to: State income tax, net of federal income tax 13.6 17.0 7.5 Valuation allowance 0.1 0.9 0.0 Other 2.8 0.1 (0.4 ) Total income tax expense from continuing operations $ 155.3 $ 138.9 $ 112.6 Income tax expense as a percent of income from continuing operations, before income taxes 39.2 % 40.2 % 37.4 %
Schedule of Deferred Tax Assets and Liabilities	The major components of the company’s deferred tax assets and liabilities recognized are as follows: (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 (1) Certain property related assets and liabilities have been netted. (2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2015 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $2.6 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized. (3) During 2015, the valuation allowance related to discontinued operations decreased from $3.6 million to $1.0 million.
Schedule of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (millions) 2015 2014 2013 Balance at Jan. 1, $ 0.0 $ 0.0 $ 2.9 Decreases due to expiration of statute of limitations 0.0 0.0 (2.9 ) Balance at Dec. 31 $ 0.0 $ 0.0 $ 0.0
Tampa Electric Company [Member]
Schedule of Income Tax Expense	Income tax expense consists of the following components: (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
Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for 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: (millions) For the years ended Dec. 31, 2015 2014 2013 Income tax expense at the federal statutory rate of 35% $ 154.6 $ 145.7 $ 127.5 Increase (decrease) due to State income tax, net of federal income tax 14.8 14.5 13.0 Other (3.9 ) (4.3 ) (1.7 ) Total income tax expense on consolidated statements of income $ 165.5 $ 155.9 $ 138.8 Income tax expense as a percent of income from continuing operations, before income taxes 37.5 % 37.5 % 38.1 %
Schedule of Deferred Tax Assets and Liabilities	The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows: (millions) As of Dec. 31, 2015 2014 Deferred tax liabilities (1) Property related $ 1,431.9 $ 1,328.8 Pension and postretirement benefits 92.0 72.5 Pension 71.1 51.8 Total deferred tax liabilities 1,595.0 1,453.1 Deferred tax assets (1) Loss and credit carryforwards 80.0 77.7 Medical benefits 47.7 51.0 Insurance reserves 27.6 29.0 Pension and postretirement benefits 92.0 72.5 Capitalized energy conservation assistance costs 21.4 20.3 Other 17.5 18.3 Total deferred tax assets 286.2 268.8 Total deferred tax liability, net 1,308.8 1,184.3 Less: Current portion of deferred tax asset 0.0 (24.8 ) Long-term portion of deferred tax liability, net $ 1,308.8 $ 1,209.1 (1) Certain property related assets and liabilities have been netted.

Employee Postretirement Benef43

Employee Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Change in Benefit Obligation	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
Schedule of Change in Plan Assets	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
Schedule of Funded status	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: 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 )
Schedule of Amount Recognized in Balance Sheet	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: 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 )
Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets	The following table provides a detail of the unrecognized gains and losses and prior service credits and costs. 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 )
Schedule of Net Periodic Benefit Cost	(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
Schedule of Amounts Recognized in OCI and Regulatory Assets	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 )
Schedule of Pension Plan Assets	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. 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 %
Schedule of Fair Value Hierarchy Plan's Investments	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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. (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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. The following list details the pricing inputs and methodologies used to value the investments in the pension plan: — The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. — The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System. The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis. — The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost. — The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. — Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. — Swaps are valued using benchmark yields, swap curves, and cash flow analyses. — Options are valued using the bid-ask spread and the last price. — The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. — The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. — The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. — The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15 th th
Schedule of Benefit Payments	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Expected Benefit Payments (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
TECO Energy [Member]
Schedule of Change in Benefit Obligation	TECO Energy Pension Benefits Other Benefits Obligations and Funded Status (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
Schedule of Change in Plan Assets	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
Schedule of Funded status	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: 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 )
Schedule of Net Periodic Benefit Cost	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
Schedule of Amounts Recognized in OCI and Regulatory Assets	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 )
Schedule of Pension Plan Assets	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. Target Allocation Actual Asset Category 2015 2014 Equity securities 47%-53% 53 % 50 % Fixed income securities 47%-53% 47 % 50 % Total 100% 100 % 100 %
Schedule of Fair Value Hierarchy Plan's Investments	The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014. Pension Plan Investments (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 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. (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: — The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. — The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System. The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis. — The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost. — The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. — Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. — Swaps are valued using benchmark yields, swap curves, and cash flow analyses. — Options are valued using the bid-ask spread and the last price. — The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. — The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. — The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. — The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15 th th
Schedule of Benefit Payments	Expected Benefit Payments—TECO Energy (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
Tampa Electric Company [Member]
Schedule of Amount Recognized in Balance Sheet	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: 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 )
Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets	The following table provides a detail of the unrecognized gains and losses and prior service credits and costs. 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
Benefit Obligations [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at Dec. 31: 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
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation: 1% 1% (millions) Increase Decrease Effect on postretirement benefit obligation $ 9.0 $ (7.7 )
Benefit Obligations [Member] | Tampa Electric Company [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at Dec. 31: Pension Benefits Other Benefits 2015 2014 2015 2014 Discount rate 4.688 % 4.258 % 4.669 % 4.211 % Rate of compensation increase-weighted average 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
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation: (millions) 1% Increase 1 % Decrease Effect on postretirement benefit obligation $ 6.1 $ (5.2 )
Net Periodic Benefit Cost [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine net periodic benefit cost for years ended Dec. 31: Pension Benefits Other Benefits 2015 2014 (1) 2013 2015 2014 2013 Discount rate 4.258 % 5.118%/4.277%/4.331% 4.196 % 4.211 % 5.096 % 4.180 % Expected long-term return on plan assets 7.00 % 7.25%/7.00%/7.00% 7.50 % 5.75 5.75 n/a Rate of compensation increase 3.87 % 3.73 % 3.76 % 3.86 % 3.71 % 3.74 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.09 % 7.25 % 7.50 % Ultimate rate n/a n/a n/a 4.57 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2025 2025 2025
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense: 1% 1% (millions) Increase Decrease Effect on periodic cost $ 0.4 $ (0.3 )
Net Periodic Benefit Cost [Member] | Tampa Electric Company [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine net periodic benefit cost for years ended Dec. 31: Pension Benefits Other Benefits 2015 2014 (1) 2013 2015 2014 2013 Discount rate 4.258 % 5.118%/4.277%/4.331% 4.196 % 4.211 % 5.096 % 4.180 % Expected long-term return on plan assets 7.00 % 7.25%/7.00%/7.00% 7.50 % 5.75 5.75 n/a Rate of compensation increase 3.87 % 3.73 % 3.76 % 3.86 % 3.71 % 3.74 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.09 % 7.25 % 7.50 % Ultimate rate n/a n/a n/a 4.57 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2025 2025 2025 (1)
Effect on Expenses [Member] | Tampa Electric Company [Member]
Schedule of One-Percentage-Point Change in Assumed Health Care Cost	A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense: (millions) 1% Increase 1% Decrease Effect on periodic cost $ 0.2 $ (0.2 )

Short-Term Debt (Tables)

Short-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Short-Term Debt Credit Facilities	At Dec. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities 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 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. ( 4 ) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
Tampa Electric Company [Member]
Short-Term Debt Credit Facilities	At Dec. 31, 2015 and 2014, the following credit facilities and related borrowings existed: Credit Facilities 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 Total $ 475.0 $ 61.0 $ 0.5 $ 475.0 $ 58.0 $ 0.6 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Maturities of Long-Term Debt	TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2016 through 2020 and thereafter are as follows: Long-Term Debt Maturities 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
Schedule of Long-Term Debt Outstanding	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) (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) 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) 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) 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) 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 (1) Guaranteed by TECO Energy. (2) These long-term debt agreements contain various restrictive financial covenants. (3) These securities are subject to redemption in whole or in part, at any time, at the option of the issuer. (4) Tax-exempt securities. (5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020. (6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025. (7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030. (8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule of Assumptions Used to Determine Fair Value	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 %
Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards	The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards. (millions) 2015 2014 2013 Compensation costs (1) $ 13.1 $ 12.7 $ 13.5 Income tax benefits (1) 5.1 4.9 5.2 Excess tax benefits (2) 0.0 0.4 0.0 (1) Reflected on the Consolidated Statements of Income. (2) Reflected as financing activities on the Consolidated Statements of Cash Flows.
Summary of Non-Vested Shares of Restricted Stock	A summary of non-vested shares of restricted stock is shown as follows: Nonvested Restricted Stock 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 (1) The weighted-average remaining contractual term of restricted stock is two years.
Summary of Stock Option Transactions	Stock option transactions are summarized as follows: Stock Options 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 (1) Option prices are $16.30 per share.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
Other Comprehensive Income	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 (1) Related to interest rate contracts in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations. (2) Related to postretirement and postemployment benefits. See Note 5 (3) Related to the transfer of employees and their associated postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI. (4) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Note 19 (5 ) Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability. ( 6 ) Includes an adjustment to eliminate TECO Coal’s OPEB liability. See Note 5
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (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 ) ( 1 ) Net of tax benefit of $21.5 million and $13.8 million as of Dec. 31, 2015 and 2014, respectively. ( 2 ) Net of tax expense of $16.1 million and $8.3 million as of Dec. 31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5 ( 3 ) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	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: Other Comprehensive Income (millions) Gross Tax Net 2015 Unrealized gain (loss) on cash flow hedges $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 1.4 (0.7 ) 0.7 Gain (Loss) on cash flow hedges 5.7 (2.2 ) 3.5 Total other comprehensive income (loss) $ 5.7 $ (2.2 ) $ 3.5 2014 Unrealized gain (loss) on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.1 (0.4 ) 0.7 Gain (Loss) on cash flow hedges 1.1 (0.4 ) 0.7 Total other comprehensive income (loss) $ 1.1 $ (0.4 ) $ 0.7 2013 Unrealized gain (loss) on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.4 (0.5 ) 0.9 Gain (Loss) on cash flow hedges 1.4 (0.5 ) 0.9 Total other comprehensive income (loss) $ 1.4 $ (0.5 ) $ 0.9
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (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 ) (1) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share	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 (1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 19

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Long-term Commitments	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: 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 (1) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. The table above excludes payment obligations under contractual agreements of Tampa Electric, PGS and NMGC for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses.
Letters of Credit and Guarantees	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: (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 (millions) Year of Expiration Maximum After (1) Theoretical Liabilities Recognized Letter of Credit for the Benefit of: 2016 2017-2020 2020 Obligation at Dec. 31, 2015 (4) TEC $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 NMGC $ 0.0 $ 0.0 $ 1.7 $ 1.7 $ 0.0 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Dec. 31, 2015. See Note 16 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 19 (4) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.
Tampa Electric Company [Member]
Schedule of Long-term Commitments	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: Capacity Operating Net Purchase (millions) Payments Leases (1) Obligations/Commitments (1) Total Year ended Dec. 31: 2016 $ 14.6 $ 5.7 $ 218.3 $ 238.6 2017 9.9 5.2 21.5 36.6 2018 10.1 4.7 9.6 24.4 2019 0.0 4.4 9.7 14.1 2020 0.0 4.1 4.7 8.8 Thereafter 0.0 14.5 20.0 34.5 Total future minimum payments $ 34.6 $ 38.6 $ 283.8 $ 357.0 (1) Excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually.
Letters of Credit and Guarantees	At Dec. 31, 2015, TEC was not obligated under guarantees, but had the following letters of credit outstanding. (millions) Year of Expiration Maximum After (1) Theoretical Liabilities Recognized Letter of Credit for the Benefit of: 2016 2017-2020 2020 Obligation at Dec. 31, 2015 (2) TEC $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. (2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims .

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Segment Information	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 (1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2015, 2014 and 2013 were at a pretax rate of 6.00%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure. (2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Other, including Parent and TECO Diversified, that directly relate to TECO Coal or TECO Guatemala. See Note 19 (3) The carrying value of mineral rights as of Dec. 31, 2015, 2014 and 2013 was $0.0 million, $10.9 million and $12.1 million, respectively. (4) NMGI is included in the Other segment. (5) Certain prior year amounts have been reclassified to conform to current year presentation. (6) Amounts primarily relate to consolidated tax eliminations.
Tampa Electric Company [Member]
Schedule of Segment Information	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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Asset Retirement Obligations	Reconciliation of beginning and ending carrying amount of asset retirement obligations: Dec. 31, (millions) 2015 2014 Beginning balance $ 6.1 $ 28.6 Additional liabilities 0.9 0.1 Revisions to estimated cash flows (0.5 ) 0.2 Acquisition of NMGC 0.0 0.8 Reclassification to liabilities associated with assets held for sale 0.0 (22.5 ) Other (1) 0.3 (1.1 ) Ending balance $ 6.8 $ 6.1 (1) 2015 includes $0.3 million accretion recorded as a deferred regulatory asset. 2014 includes $(1.3) million of activity associated with TECO Coal and classified as discontinued operations and $0.2 million accretion recorded as a deferred regulatory asset.
Tampa Electric Company [Member]
Schedule of Asset Retirement Obligations	Reconciliation of beginning and ending carrying amount of asset retirement obligations: Dec. 31, (millions) 2015 2014 Beginning balance $ 5.3 $ 4.8 Additional liabilities 0.9 0.1 Revisions to estimated cash flows (0.5 ) 0.2 Other (1) 0.3 0.2 Ending balance $ 6.0 $ 5.3 (1) Accretion recorded as a deferred regulatory asset.

Accounting for Derivative Ins52

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Volumes Expected to Settle	The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to 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: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 38.4 2017 0.0 5.1 Total 0.0 43.5
Tampa Electric Company [Member]
Derivative Volumes Expected to Settle	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: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2016 0.0 27.6 2017 0.0 5.0 Total 0.0 32.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Recurring Fair Value Measurements	Recurring Fair Value Measures As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.2 $ 0.0 $ 26.2 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas derivatives $ 0.0 $ 42.7 $ 0.0 $ 42.7
Tampa Electric Company [Member]
Schedule of Recurring Fair Value Measurements	Recurring Derivative Fair Value Measures As of Dec. 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 42.7 $ 0.0 $ 42.7

Discontinued Operations, Asse54

Discontinued Operations, Assets Held for Sale and Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
TECO Coal [Member]
Components of Discontinued Operations	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: Assets held for sale (millions) Dec. 31, 2014 Current assets $ 109.6 Property, plant and equipment, net and other long-term assets 59.8 Total assets held for sale $ 169.4 Liabilities associated with assets held for sale (millions) Current liabilities $ 39.4 Long-term liabilities 65.4 Total liabilities associated with assets held for sale $ 104.8
TECO Coal and TECO Guatemala [Member]
Components of Discontinued Operations	The following table provides selected components of discontinued operations related to TECO Coal and TECO Guatemala: 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

Goodwill and Asset Impairments

Goodwill and Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Changes in Carrying Amount of Goodwill	The following table presents the changes in the carrying amount of goodwill for the years ended Dec. 31, 2015, 2014 and 2013. (millions) NMGC Total Balance as of Dec. 31, 2013 $ 0.0 $ 0.0 Acquisition of NMGC 408.3 408.3 Balance as of Dec. 31, 2014 408.3 408.3 Measurement period adjustments (1) 0.1 0.1 Balance as of Dec. 31, 2015 $ 408.4 $ 408.4 (1) Due to immateriality, the measurement period adjustment was not applied retrospectively to the opening balance sheet.

Mergers and Acquisitions (Table

Mergers and Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Pro Forma Financial Information	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
After-tax transaction and integration charges recognized in connection with the acquisition	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. 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
NMGI [Member]
Consideration in Acquisition	The total consideration in the acquisition was as follows: Consideration Transferred (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
NMGI and NMGC [Member]
Purchase Price Allocation	The final purchase price allocation of the acquisition of NMGI and NMGC was as follows: 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 (1) Includes accounts receivables with fair value of $18.9 million, gross contract value of $19.6 million, and $0.7 million of contractual receivables not expected to be collected.

Quarterly Data (unaudited) (Tab

Quarterly Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Financial Data by Quarter	Financial data by quarter is as follows: (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

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Tampa Electric Company [Member]
Schedule of Related Party Transactions	A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2015 2014 2013 Natural gas sales, net $ 0.8 $ 0.3 $ 18.3 Administrative and general, net (1) $ 69.4 $ 22.5 $ 27.2 (1) The 2015 increase in transactions with affiliates is attributable to shared services being provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning in Jan. 1, 2015. Amounts due from or to affiliates at Dec. 31, (millions) 2015 2014 Accounts receivable (1) $ 2.3 $ 2.4 Accounts payable (1) 15.9 9.7 Taxes receivable (2) 61.3 43.3 Taxes payable (2) 1.0 0.0 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) Taxes receivable are due from, and taxes payable are due to, TECO Energy.

Significant Accounting Polici59

Significant Accounting Policies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Summary Of Significant Accounting Policies [Line Items]
Equity method investment information	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
Equity method investment, Ownership percentage	50.00%
Percentage of original cost of depreciable property	3.70%	3.60%	3.70%
Depreciation expense	$ 339.1	$ 307.5	$ 285.6
Allowance for funds used during construction	26.1	15.8	9.9
Unbilled revenues	81.1	86.6
Purchased power	78.9	71.4	64.7
Franchise fees and gross receipts taxes	$ 116.9	$ 113.9	$ 108.5
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.92%	2.71%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	4.00%	4.00%
Computer Software [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	3 years
Computer Software [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	15 years
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of business segments | Segment	2
Equity method investment information	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
Equity method investment, Ownership percentage	50.00%
Percentage of original cost of depreciable property	3.70%	3.70%	3.70%
Depreciation expense	$ 306	$ 295.8	$ 284.2
Allowance for funds used during construction rate	6.46%	6.46%	8.16%
Allowance for funds used during construction	$ 25.5	$ 15.6	$ 9.9
Unbilled revenues	53.7	49.3
Purchased power	78.9	71.4	64.7
Franchise fees and gross receipts taxes	$ 116.9	$ 113.9	108.5
Tampa Electric Company [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.92%	2.71%
Tampa Electric Company [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	4.00%	4.00%
Tampa Electric Company [Member] | Computer Software [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	15 years	15 years
NMGC [Member]
Summary Of Significant Accounting Policies [Line Items]
Allowance for funds used during construction rate	4.41%	4.92%
Rights of way	$ 41	$ 41
Rights of way, accumulated amortization	9	8
TECO Energy Source, Inc [Member]
Summary Of Significant Accounting Policies [Line Items]
Costs netted against revenues	$ 3.1	$ 4.3	$ 23.1

Significant Accounting Polici60

Significant Accounting Policies - Estimated Useful Lives of Depreciable Property (Detail)	12 Months Ended
	Dec. 31, 2015
Building and Improvements [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	40 years
Minimum [Member] | Office Equipment and Furniture [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	4 years
Minimum [Member] | Computer Software [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	3 years
Maximum [Member] | Office Equipment and Furniture [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	7 years
Maximum [Member] | Computer Software [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	15 years

Significant Accounting Polici61

Significant Accounting Policies - Schedule of Fuel Inventory (Detail) - Fuel [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory [Line Items]
Fuel inventory	$ 113.4	$ 96.4
Tampa Electric Company [Member]
Inventory [Line Items]
Fuel inventory	105.6	85.2
NMGC [Member]
Inventory [Line Items]
Fuel inventory	$ 7.8	$ 11.2

New Accounting Pronouncements -

New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	$ 18.1	$ 16.8
Deferred Charges And Other Assets [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	27.7
Deferred Charges And Other Assets [Member] | Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	$ 18.1

Regulatory - Additional Informa

Regulatory - Additional Information (Detail) - USD ($)	Feb. 01, 2012	Mar. 31, 2011	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Percentage of ROE			10.75%
Allowed equity in the capital structure			54.70%
Regulatory matters allowed rate base			$ 560,800,000
PGS Rates [Member]
Percentage of ROE			10.75%
Allowed equity in the capital structure			54.70%
Regulatory matters allowed rate base			$ 560,800,000
Minimum [Member]
Return on equity			9.75%
Minimum [Member] | PGS Rates [Member]
Return on equity			9.75%
Maximum [Member]
Return on equity			11.75%
Maximum [Member] | PGS Rates [Member]
Return on equity			11.75%
Tampa Electric Company [Member]
Higher Revenue Requirements			$ 104,000,000
Percentage of ROE			10.25%	11.25%
Allowed equity in the capital structure				54.00%
Period of average rate base				13 months
Revenue due to average rate base				$ 3,400,000,000
Increase in revenue by modification in base rate				33,500,000
Return on equity range			Range of plus or minus 1%
Potential increase in ROE			10.50%
Amortization period of Regulatory Asset			12 years
Annual accrual storm damage reserve				$ 8,000,000
Storm damage reserve			$ 56,100,000		$ 56,100,000
Storm damage cost recovery period			12-month period or longer
Application to increase base rate on normalized annual basis		$ 34,500,000
Increased Base Rate on Normalized Annual Basis	$ 21,500,000
Previous monthly residential access fee	9.59
Monthly residential customer access fee increased	$ 11.50
Tampa Electric Company [Member] | November 1, 2013 [Member]
Additional Revenue generated from increase in service charge			$ 57,500,000
Tampa Electric Company [Member] | November 1, 2014 [Member]
Additional Revenue generated from increase in service charge			7,500,000
Tampa Electric Company [Member] | November 1, 2015 [Member]
Additional Revenue generated from increase in service charge			5,000,000
Tampa Electric Company [Member] | January 1,2017 [Member]
Additional Revenue generated from increase in service charge			$ 110,000,000
Tampa Electric Company [Member] | Condition One [Member]
ROE lower range limit			9.25%
ROE upper range limit			11.25%
Tampa Electric Company [Member] | Condition Two [Member]
ROE lower range limit			9.50%
ROE upper range limit			11.50%
Tampa Electric Company [Member] | Computer Software [Member]
Amortization period of Regulatory Asset			15 years

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory assets:
Regulatory assets	$ 440	$ 402.1
Less: Current portion	44.8	53.6
Long-term regulatory assets	395.2	348.5
Regulatory liabilities:
Regulatory liabilities	800.6	786
Less: Current portion	84.8	57
Long-term regulatory liabilities	715.8	729
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	418.1	371.7
Less: Current portion	44.3	52.1
Long-term regulatory assets	373.8	319.6
Regulatory liabilities:
Regulatory liabilities	686.7	678.1
Less: Current portion	83.2	54.7
Long-term regulatory liabilities	603.5	623.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	74.7	69.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	74.6	69.2
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	5.5	1.9
Cost-Recovery Clauses - Deferred Balances [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	5.2	0.9
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	26.5	43.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	26.2	42.7
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	54	53.1
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	54	53.1
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	240.6	194
Postretirement Benefit Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	238.3	187.8
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	6.5	7.2
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	6.5	7.2
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	17.5	20.9
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.6	2.8
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.6	2.8
Other [Member]
Regulatory assets:
Regulatory assets	12.1	9.8
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	10.7	8
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	7.9	6.9
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.7	5.1
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	55.9	25.9
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	54.2	23.5
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	679.9	695.2
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	570	591.5
Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	1.9
Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$ 0.7	$ 1.9

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Income tax expense from continuing operations	$ 155,300,000	$ 138,900,000	$ 112,600,000
Cash paid for income taxes	$ 14,500,000	$ 2,900,000	$ 1,800,000
Effective tax rate	35.00%	35.00%	35.00%
Deferred tax assets expiration date	2025 and 2034, with the majority expiring in 2025
General business credit	$ 5,800,000
Deferred tax general business credits expiration date	2026 and 2034
Tax credit carry forwards	$ 213,500,000	$ 214,000,000
Valuation allowance	2,000,000	4,600,000
Decrease of valuation allowance	$ 2,600,000
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%
Pretax charges (benefits)	$ 0	0	$ (900,000)
Interest accrued	0	0
Penalties	$ 0
Income tax examination period	1 year
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations	4 years
Federal [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	$ 1,728,600,000
Florida [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	675,200,000
New Mexico [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	85,800,000
NMGI [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	121,600,000
TECO Coal [Member] | Discontinued Operations [Member]
Income Taxes [Line Items]
Valuation allowance	$ 1,000,000	3,600,000
Deferred tax assets expiration date	2,020
TECO Coal [Member] | Federal [Member] | Discontinued Operations [Member]
Income Taxes [Line Items]
Capital loss carryforward deferred tax asset	$ 1,000,000
Tampa Electric Company [Member]
Income Taxes [Line Items]
Income tax expense from continuing operations	165,500,000	155,900,000	138,800,000
Cash paid for income taxes	$ 63,700,000	$ 52,600,000	$ 56,400,000
Effective tax rate	35.00%	35.00%	35.00%
Deferred tax assets expiration date	2,033
General business credit	$ 1,900,000
Deferred tax general business credits expiration date	2028 and 2035
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%
Statutes of limitations	3 years
Income tax examination period	1 year
Tampa Electric Company [Member] | Federal [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	$ 194,100,000
Tampa Electric Company [Member] | Florida [Member]
Income Taxes [Line Items]
Federal, Florida and New Mexico net operating losses (NOL's) carry forward	$ 268,500,000

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Income tax expense from continuing operations	$ 155.3	$ 138.9	$ 112.6
Total income tax expense	116.7	89.5	108.8
Tampa Electric Company [Member]
Income Taxes [Line Items]
Current income taxes, Federal	38.2	54.8	19.4
Current income taxes, State	8.4	8.9	1.3
Deferred income taxes, Federal	102.9	79	99.8
Deferred income taxes, State	14.5	13.5	18.6
Amortization of investment tax credits	1.5	(0.3)	(0.3)
Income tax expense from continuing operations	165.5	155.9	138.8
Continuing Operations [Member]
Income Taxes [Line Items]
Current income taxes, Federal	(0.5)	0.5	2.2
Current income taxes, State	0	0	0
Deferred income taxes, Federal	133.2	111	98.8
Deferred income taxes, 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 [Member]
Income Taxes [Line Items]
Current income taxes, Federal	0	0	0
Current income taxes, State	(0.3)	(0.4)	(3.5)
Deferred income taxes, Federal	(34.7)	(44)	(0.3)
Deferred income taxes, State	(3.6)	(5)	0
Income tax expense from discontinued operations	$ (38.6)	$ (49.4)	$ (3.8)

Income Taxes - Schedule of In67

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Income tax expense at the federal statutory rate of 35%	$ 138.8	$ 120.9	$ 105.5
State income tax, net of federal income tax	13.6	17	7.5
Valuation allowance	0.1	0.9	0
Other	2.8	0.1	(0.4)
Income tax expense from continuing operations	$ 155.3	$ 138.9	$ 112.6
Income tax expense as a percent of income from continuing operations, before income taxes	39.20%	40.20%	37.40%
Tampa Electric Company [Member]
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Income tax expense at the federal statutory rate of 35%	$ 154.6	$ 145.7	$ 127.5
State income tax, net of federal income tax	14.8	14.5	13
Other	(3.9)	(4.3)	(1.7)
Income tax expense from continuing operations	$ 165.5	$ 155.9	$ 138.8
Income tax expense as a percent of income from continuing operations, before income taxes	37.50%	37.50%	38.10%

Income Taxes - Schedule of In68

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Effective tax rate	35.00%	35.00%	35.00%
Tampa Electric Company [Member]
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Effective tax rate	35.00%	35.00%	35.00%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities
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
Alternative minimum tax credit carryforward	213.5	214
Loss and credit carryforwards	637.5	566.7
Other postretirement benefits	69.5	71.5
Other	117.5	159.6
Total deferred tax assets	1,038	1,011.8
Valuation allowance	(2)	(4.6)
Total deferred tax assets, net of valuation allowance	1,036	1,007.2
Total deferred tax liability, net	569.9	446.4
Less: Current portion of deferred tax asset	0	(72.8)
Less: Long term portion of deferred tax asset	(0.8)	0
Long-term portion of deferred tax liability, net	570.7	519.2
Tampa Electric Company [Member]
Deferred tax liabilities
Property related	1,431.9	1,328.8
Pension and postretirement benefits	92	72.5
Pension	71.1	51.8
Total deferred tax liabilities	1,595	1,453.1
Deferred tax assets
Loss and credit carryforwards	80	77.7
Medical benefits	47.7	51
Insurance reserves	27.6	29
Pension and postretirement benefits	92	72.5
Capitalized energy conservation assistance costs	21.4	20.3
Other	17.5	18.3
Total deferred tax assets	286.2	268.8
Total deferred tax liability, net	1,308.8	1,184.3
Less: Current portion of deferred tax asset	0	(24.8)
Long-term portion of deferred tax liability, net	$ 1,308.8	$ 1,209.1

Income Taxes - Schedule of De70

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Components Of Deferred Tax Assets And Liabilities [Line Items]
Stockholder's equity increment	$ 2.6
Valuation allowance	2	$ 4.6
TECO Coal [Member] | Discontinued Operations [Member]
Components Of Deferred Tax Assets And Liabilities [Line Items]
Valuation allowance	$ 1	$ 3.6

Income Taxes - Schedule of Unre

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Beginning Balance	$ 0	$ 0	$ 2.9
Decreases due to expiration of statute of limitations	0	0	(2.9)
Ending Balance	$ 0	$ 0	$ 0

Employee Postretirement Benef72

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended			21 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Percentage of tax-free subsidy under prescription drug programs	28.00%
Tax of premiums paid for retiree medical benefits plan	40.00%
Accumulated benefit obligation of defined benefit pension plans	$ 686.9	$ 685		$ 685
Percentage of defined benefit plan assets decreased	3.50%
Plan assets	$ 625.4	$ 648		$ 648
Primary provisions for pension benefits	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%.
Percentage of qualified pension plan's actuarial value of assets		120.10%		120.10%
Estimated percentage of qualified pension plan's actuarial value of assets	114.10%
Employer contributions	$ 55	$ 47.5
Employer contributions in next fiscal year	$ 37.4
Defined contribution plan, maximum employer match percentage	6.00%
Description of defined contribution plan	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%.
Defined contribution plan cost recognized	$ 11.1	13.1	$ 11.3
Employer matching contribution percentage of eligible participant contribution	70.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	30.00%
Effective date of employer matching contribution increase	Jan. 1, 2015
Pre Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution	60.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%
Post Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution				65.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer				35.00%
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	$ 12.2
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	44.6
Unqualified SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assets	43.5	0.9		$ 0.9
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss amortization from AOCI into net periodic benefit cost related to defined benefit plan	3.5
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.1
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	9.8
Defined benefit plan, assets	208.2	167.4		167.4
Plan assets	625.4	648	593	648
Employer contributions	55	47.5
Net periodic benefit cost	22.8	25.7	29.8
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.5
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	2.1
Defined benefit plan, assets	32.4	26.6		26.6
Plan assets	20.6	18.8	0	18.8
Employer contributions	1.5	(1)
Employer contributions in next fiscal year	14.3
Net periodic benefit cost	6.9	12.8	12.4
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 43.4	1.2
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of tax-free subsidy under prescription drug programs	28.00%
Amortization period of Regulatory Asset	12 years
Plan assets	$ 625.4	$ 648		$ 648
Primary provisions for pension benefits	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%.
Percentage of qualified pension plan's actuarial value of assets		120.10%		120.10%
Estimated percentage of qualified pension plan's actuarial value of assets	114.10%
Employer contributions	$ 43.9	$ 38.2
Employer contributions in next fiscal year	$ 30.9
Description of defined contribution plan	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%.
Defined contribution plan cost recognized	$ 7.5	10.2	9.1
Employer matching contribution percentage of eligible participant contribution	70.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	30.00%
Tampa Electric Company [Member] | Pre Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution	60.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%
Tampa Electric Company [Member] | Post Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution				65.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer				35.00%
Tampa Electric Company [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	$ 8
Tampa Electric Company [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	35
Tampa Electric Company [Member] | Unqualified SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assets	43.5	0.9		$ 0.9
Tampa Electric Company [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	9.8
Defined benefit plan, assets	208.2	167.4		167.4
Net periodic benefit cost	13.5	14.8	21.7
Tampa Electric Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	1.9
Defined benefit plan, assets	30.2	20.4		20.4
Employer contributions in next fiscal year	9.3
Net periodic benefit cost	5.7	10.4	10
Tampa Electric Company [Member] | SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	14.9	0.8
NMGC [Member]
Defined Benefit Plan Disclosure [Line Items]
Pre-acquisition regulated asset that will be amortized from regulatory assets in next fiscal year	1.1
NMGC [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions in next fiscal year	3.6
NMGC [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets	$ 20.6	18.8		18.8
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of defined benefit plan assets decreased	3.50%
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets	$ 625.4	648	593	648
Employer contributions	55	47.5
Net periodic benefit cost	22.8	25.7	29.8
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	0
Plan assets	20.6	18.8	0	$ 18.8
Employer contributions	1.5	(1)
Net periodic benefit cost	$ 6.9	$ 12.8	$ 12.4

Employee Postretirement Benef73

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	$ 728.9	$ 666
Service cost	20.9	18.3	$ 18.2
Interest cost	30.3	32	28.9
Plan participants’ contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	5.8	48.3
Benefits paid	(53)	(39.9)
Transfer in due to the effect of business combination	0	0
Plan curtailment	0	4
Special termination benefit	0	0.2
Net benefit obligation at end of year	732.9	728.9	666
Pension Benefits [Member] | TECO Energy [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	728.9	666
Service cost	20.9	18.3	18.2
Interest cost	30.3	32	28.9
Plan participants’ contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	5.8	48.3
Benefits paid	(53)	(39.9)
Transfer in due to the effect of business combination	0	0
Plan curtailment	0	4
Special termination benefit	0	0.2
Net benefit obligation at end of year	732.9	728.9	666
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	201.5	208.1
Service cost	2.2	2.5	2.5
Interest cost	8.2	10.8	9.3
Plan participants’ contributions	2	2.8
Plan amendments	(3.7)	(23.2)
Actuarial loss (gain)	(0.4)	1.5
Benefits paid	(14.6)	(16)
Transfer in due to the effect of business combination	0	26.7
Plan curtailment	0	(11.7)
Special termination benefit	0	0
Net benefit obligation at end of year	195.2	201.5	208.1
Other Postretirement Benefits [Member] | TECO Energy [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	201.5	208.1
Service cost	2.2	2.5	2.5
Interest cost	8.2	10.8	9.3
Plan participants’ contributions	2	2.8
Plan amendments	(3.7)	(23.2)
Actuarial loss (gain)	(0.4)	1.5
Benefits paid	(14.6)	(16)
Transfer in due to the effect of business combination	0	26.7
Plan curtailment	0	(11.7)
Special termination benefit	0	0
Net benefit obligation at end of year	$ 195.2	$ 201.5	$ 208.1

Employee Postretirement Benef74

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Change in plan assets
Fair value of plan assets at beginning of year	$ 648
Employer contributions	55	$ 47.5
Fair value of plan assets at end of year	625.4	648
Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	648	593
Actual return on plan assets	(25.5)	46.4
Employer contributions	55	47.5
Employer direct benefit payments	0.9	1
Plan participants’ contributions	0	0
Transfer in due to acquisition	0	0
Benefits paid	(53)	(39.9)
Fair value of plan assets at end of year	625.4	648
Pension Benefits [Member] | TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year	648	593
Actual return on plan assets	(25.5)	46.4
Employer contributions	55	47.5
Employer direct benefit payments	0.9	1
Plan participants’ contributions	0	0
Benefits paid	(53)	(39.9)
Fair value of plan assets at end of year	625.4	648
Transfer in due to acquisition	0	0
Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	18.8	0
Actual return on plan assets	(0.6)	0.1
Employer contributions	1.5	(1)
Employer direct benefit payments	13.5	16
Plan participants’ contributions	2	2.8
Transfer in due to acquisition	0	16.9
Benefits paid	(14.6)	(16)
Fair value of plan assets at end of year	20.6	18.8
Other Postretirement Benefits [Member] | TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year	18.8	0
Actual return on plan assets	(0.6)	0.1
Employer contributions	1.5	(1)
Employer direct benefit payments	13.5	16
Plan participants’ contributions	2	2.8
Benefits paid	(14.6)	(16)
Fair value of plan assets at end of year	20.6	18.8
Transfer in due to acquisition	$ 0	$ 16.9

Employee Postretirement Benef75

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years

Employee Postretirement Benef76

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 625.4	$ 648
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	732.9	728.9	$ 666
Fair value of plan assets	625.4	648	593
Funded status at end of year	(107.5)	(80.9)
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	732.9	728.9	666
Fair value of plan assets	625.4	648	593
Funded status at end of year	(107.5)	(80.9)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	195.2	201.5	208.1
Fair value of plan assets	20.6	18.8	0
Funded status at end of year	(174.6)	(182.7)
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	195.2	201.5	208.1
Fair value of plan assets	20.6	18.8	$ 0
Funded status at end of year	$ (174.6)	$ (182.7)

Employee Postretirement Benef77

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 208.2	$ 167.4
Accrued benefit costs and other current liabilities	(10.5)	(4.9)
Deferred credits and other liabilities	(97)	(76)
Accumulated other comprehensive loss (income), pretax	55.7	36.3
Net amount recognized at end of year	156.4	122.8
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	208.2	167.4
Accrued benefit costs and other current liabilities	(0.6)	(0.6)
Deferred credits and other liabilities	(69.3)	(53.5)
Net amount recognized at end of year	138.3	113.3
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	32.4	26.6
Accrued benefit costs and other current liabilities	(10.7)	(10.7)
Deferred credits and other liabilities	(163.9)	(172)
Accumulated other comprehensive loss (income), pretax	(41.6)	(34.6)
Net amount recognized at end of year	(183.8)	(190.7)
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	30.2	20.4
Accrued benefit costs and other current liabilities	(9.2)	(9.1)
Deferred credits and other liabilities	(142.3)	(137.1)
Net amount recognized at end of year	$ (121.3)	$ (125.8)

Employee Postretirement Benef78

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 263.6	$ 203.7
Prior service cost (credit)	0.3	0
Unrecognized costs in regulated asset acquired in business combination	0	0
Amount recognized, pretax	263.9	203.7
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	208.2	167.7
Prior service cost (credit)	0	(0.3)
Amount recognized	208.2	167.4
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	10.9	9.6
Prior service cost (credit)	(25)	(23.6)
Unrecognized costs in regulated asset acquired in business combination	4.9	6
Amount recognized, pretax	(9.2)	(8)
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	47.2	39.5
Prior service cost (credit)	(17)	(19.1)
Amount recognized	$ 30.2	$ 20.4

Employee Postretirement Benef79

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	2 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2014	Oct. 30, 2014	Sep. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.258%			4.688%	4.258%
Rate of compensation increase—weighted	3.87%			3.87%	3.87%
Discount rate	4.331%	4.277%	5.118%	4.258%		4.196%
Expected long-term return on plan assets	7.00%	7.00%	7.25%	7.00%		7.50%
Rate of compensation increase	3.73%			3.87%		3.76%
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.258%			4.688%	4.258%
Rate of compensation increase—weighted	3.87%			3.87%	3.87%
Discount rate	4.331%	4.277%	5.118%	4.258%		4.196%
Expected long-term return on plan assets	7.00%	7.00%	7.25%	7.00%		7.50%
Rate of compensation increase				3.87%	3.73%	3.76%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.211%			4.669%	4.211%
Rate of compensation increase—weighted	3.86%			2.50%	3.86%
Healthcare cost trend rate
Immediate rate	7.09%			7.05%	7.09%
Ultimate rate	4.57%			4.50%	4.57%
Year rate reaches ultimate	2,025			2,038	2,025
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.211%			4.669%	4.211%
Rate of compensation increase—weighted	3.86%			2.50%	3.86%
Healthcare cost trend rate
Immediate rate	7.09%			7.05%	7.09%
Ultimate rate	4.57%			4.50%	4.57%
Year rate reaches ultimate	2,025			2,038	2,025
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate				4.211%	5.096%	4.18%
Expected long-term return on plan assets				5.75%	5.75%
Rate of compensation increase				3.86%	3.71%	3.74%
Healthcare cost trend rate
Immediate rate				7.09%	7.25%	7.50%
Ultimate rate				4.57%	4.50%	4.50%
Year rate reaches ultimate	2,025			2,025	2,025	2,025
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate				4.211%	5.096%	4.18%
Expected long-term return on plan assets				5.75%	5.75%
Rate of compensation increase				3.86%	3.71%	3.74%
Healthcare cost trend rate
Immediate rate				7.09%	7.25%	7.50%
Ultimate rate				4.57%	4.50%	4.50%
Year rate reaches ultimate	2,025			2,025	2,025	2,025

Employee Postretirement Benef80

Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	$ 0.4
Effect on periodic cost - Decrease	(0.3)
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	0.2
Effect on periodic cost - Decrease	(0.2)
Assumed One-percentage-point Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	9
Effect on postretirement benefit obligation - Decrease	(7.7)
Assumed One-percentage-point Change [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	6.1
Effect on postretirement benefit obligation - Decrease	$ (5.2)

Employee Postretirement Benef81

Employee Postretirement Benefits - Schedule of Amounts Recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 20.9	$ 18.3	$ 18.2
Interest cost	30.3	32	28.9
Expected return on plan assets	(43.3)	(41.8)	(38.4)
Amortization of:
Actuarial loss	15.1	13.5	20.5
Prior service (benefit) cost	(0.2)	(0.4)	(0.4)
Curtailment loss (gain)	0	3.9	0
Special termination benefit	0	0.2	0
Settlement loss	0	0	1
Net periodic benefit cost	22.8	25.7	29.8
New prior service cost	0	0	0
Net loss (gain) arising during the year	74.5	44.1	(75.7)
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)	(15.1)	(13.5)	(21.5)
Amortization of prior service (benefit) cost	0.2	0.4	0.4
Total recognized in OCI and regulatory assets	59.6	31	(96.8)
Total recognized in net periodic benefit cost, OCI and regulatory assets	82.4	56.7	(67)
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	20.9	18.3	18.2
Interest cost	30.3	32	28.9
Expected return on plan assets	(43.3)	(41.8)	(38.4)
Amortization of:
Actuarial loss	15.1	13.5	20.5
Prior service (benefit) cost	(0.2)	(0.4)	(0.4)
Curtailment loss (gain)	0	3.9	0
Special termination benefit	0	0.2	0
Settlement loss	0	0	1
Net periodic benefit cost	22.8	25.7	29.8
New prior service cost	0	0	0
Net loss (gain) arising during the year	74.5	44.1	(75.7)
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)	(15.1)	(13.5)	(21.5)
Amortization of prior service (benefit) cost	0.2	0.4	0.4
Total recognized in OCI and regulatory assets	59.6	31	(96.8)
Total recognized in net periodic benefit cost, OCI and regulatory assets	82.4	56.7	(67)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.2	2.5	2.5
Interest cost	8.2	10.8	9.3
Expected return on plan assets	(1.1)	(0.3)	0
Amortization of:
Actuarial loss	0	0.2	1
Prior service (benefit) cost	(2.4)	(0.2)	(0.4)
Curtailment loss (gain)	0	(0.2)	0
Special termination benefit	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	6.9	12.8	12.4
New prior service cost	(3.7)	(23.6)	0
Net loss (gain) arising during the year	1.3	(9.9)	(15.6)
Unrecognized costs in regulated asset acquired in business combination	0	6.4	0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)	0	(0.2)	(1)
Amortization of prior service (benefit) cost	2.4	0.2	0.3
Total recognized in OCI and regulatory assets	0	(27.1)	(16.3)
Total recognized in net periodic benefit cost, OCI and regulatory assets	6.9	(14.3)	(3.9)
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.2	2.5	2.5
Interest cost	8.2	10.8	9.3
Expected return on plan assets	(1.1)	(0.3)	0
Amortization of:
Actuarial loss	0	0.2	1
Prior service (benefit) cost	(2.4)	(0.2)	(0.4)
Curtailment loss (gain)	0	(0.2)	0
Special termination benefit	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	6.9	12.8	12.4
New prior service cost	(3.7)	(23.6)	0
Net loss (gain) arising during the year	1.3	(9.9)	(15.6)
Unrecognized costs in regulated asset acquired in business combination	0	6.4	0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)	0	(0.2)	(1)
Amortization of prior service (benefit) cost	2.4	0.2	0.3
Total recognized in OCI and regulatory assets	0	(27.1)	(16.3)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ 6.9	$ (14.3)	$ (3.9)

Employee Postretirement Benef82

Employee Postretirement Benefits - Schedule of Pension Plan Assets (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Target Allocation [Member]
Asset Category
Target Allocation	100.00%
Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	100.00%	100.00%
Equity Securities [Member] | Target Allocation [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Equity Securities [Member] | Target Allocation [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%
Equity Securities [Member] | Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	53.00%	50.00%
Fixed Income Securities [Member] | Target Allocation [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Fixed Income Securities [Member] | Target Allocation [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%
Fixed Income Securities [Member] | Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	47.00%	50.00%

Employee Postretirement Benef83

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 625,400	$ 648,000
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	625,400	648,000
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,900	400
Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,900	400
Net Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(11,000)	(3,500)
Net Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(11,000)	(3,500)
Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	377,200	406,700
Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	377,200	406,700
Using NAV [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Using NAV [Member] | Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Using NAV [Member] | Net Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Using NAV [Member] | Net Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14,300	1,400
Accounts Receivable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14,300	1,400
Accounts Receivable [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(27,200)	(5,300)
Accounts Payable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(27,200)	(5,300)
Accounts Payable [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,400	99,100
Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,400	99,100
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,900	400
Level 1 [Member] | Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,900	400
Level 1 [Member] | Net Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(11,000)	(3,500)
Level 1 [Member] | Net Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(11,000)	(3,500)
Level 1 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14,300	1,400
Level 1 [Member] | Accounts Receivable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14,300	1,400
Level 1 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(27,200)	(5,300)
Level 1 [Member] | Accounts Payable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(27,200)	(5,300)
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	157,800	142,200
Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	157,800	142,200
Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Net Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Net Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Receivable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Payable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Net Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Net Cash [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Receivable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Payable [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13,300	16,600
Cash Equivalents [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13,300	16,600
Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200
Cash Equivalents [Member] | Money Markets [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200
Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200
Cash Equivalents [Member] | Treasury Bills (T bills) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200
Cash Equivalents [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	700	8,800
Cash Equivalents [Member] | Discounted Notes [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	700	8,800
Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Using NAV [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Using NAV [Member] | Money Markets [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Using NAV [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Using NAV [Member] | Treasury Bills (T bills) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Using NAV [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Using NAV [Member] | Discounted Notes [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Using NAV [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Using NAV [Member] | Short Term Investment Fund (STIF) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,400	7,600
Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 1 [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Level 1 [Member] | Money Markets [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Level 1 [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Level 1 [Member] | Treasury Bills (T bills) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Level 1 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 1 [Member] | Discounted Notes [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 1 [Member] | Short Term Investment Fund (STIF) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	900	9,000
Cash Equivalents [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	900	9,000
Cash Equivalents [Member] | Level 2 [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200
Cash Equivalents [Member] | Level 2 [Member] | Money Markets [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200
Cash Equivalents [Member] | Level 2 [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200
Cash Equivalents [Member] | Level 2 [Member] | Treasury Bills (T bills) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		200
Cash Equivalents [Member] | Level 2 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	700	8,800
Cash Equivalents [Member] | Level 2 [Member] | Discounted Notes [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	700	8,800
Cash Equivalents [Member] | Level 2 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 2 [Member] | Short Term Investment Fund (STIF) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Level 3 [Member] | Money Markets [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Cash Equivalents [Member] | Level 3 [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Level 3 [Member] | Treasury Bills (T bills) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] | Level 3 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member] | Discounted Notes [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash Equivalents [Member] | Level 3 [Member] | Short Term Investment Fund (STIF) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	330,700	319,500
Equity Securities [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	330,700	319,500
Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,900	98,000
Equity Securities [Member] | Common Stock [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,900	98,000
Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,700	1,300
Equity Securities [Member] | American Depository Receipt (ADR) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,700	1,300
Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,800	2,500
Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,800	2,500
Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		800
Equity Securities [Member] | Preferred Stocks [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		800
Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Equity Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Using NAV [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Common Stock [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | American Depository Receipt (ADR) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Real Estate Investment Trust (REIT) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Using NAV [Member] | Preferred Stocks [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Using NAV [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Using NAV [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Using NAV [Member] | Equity Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	175,600	171,300
Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	101,400	102,600
Equity Securities [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	101,400	102,600
Equity Securities [Member] | Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,900	98,000
Equity Securities [Member] | Level 1 [Member] | Common Stock [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90,900	98,000
Equity Securities [Member] | Level 1 [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,700	1,300
Equity Securities [Member] | Level 1 [Member] | American Depository Receipt (ADR) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,700	1,300
Equity Securities [Member] | Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,800	2,500
Equity Securities [Member] | Level 1 [Member] | Real Estate Investment Trust (REIT) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,800	2,500
Equity Securities [Member] | Level 1 [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		800
Equity Securities [Member] | Level 1 [Member] | Preferred Stocks [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		800
Equity Securities [Member] | Level 1 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 1 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 1 [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 1 [Member] | Equity Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Level 2 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | Common Stock [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | American Depository Receipt (ADR) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | Real Estate Investment Trust (REIT) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Level 2 [Member] | Preferred Stocks [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Level 2 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Level 2 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53,700	45,600
Equity Securities [Member] | Level 2 [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 2 [Member] | Equity Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Common Stock [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | American Depository Receipt (ADR) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Real Estate Investment Trust (REIT) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Level 3 [Member] | Preferred Stocks [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member] | Level 3 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] | Level 3 [Member] | Equity Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	293,100	315,700
Debt Securities [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	293,100	315,700
Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	117,900	129,200
Debt Securities [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	117,900	129,200
Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,000	6,100
Debt Securities [Member] | Municipal Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,000	6,100
Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56,200	47,900
Debt Securities [Member] | Government Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56,200	47,900
Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32,200	22,000
Debt Securities [Member] | Corporate Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32,200	22,000
Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300	300
Debt Securities [Member] | Asset Backed Securities (ABS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300	300
Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,700	9,600
Debt Securities [Member] | Mortgage Back Securities (MBS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,700	9,600
Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500	2,000
Debt Securities [Member] | CMO [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500	2,000
Debt Securities [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	71,300	98,600
Debt Securities [Member] | Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	71,300	98,600
Debt Securities [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	189,200	227,800
Debt Securities [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	189,200	227,800
Debt Securities [Member] | Using NAV [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	117,900	129,200
Debt Securities [Member] | Using NAV [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	117,900	129,200
Debt Securities [Member] | Using NAV [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Municipal Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Government Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Corporate Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Asset Backed Securities (ABS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Mortgage Back Securities (MBS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | CMO [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Using NAV [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	71,300	98,600
Debt Securities [Member] | Using NAV [Member] | Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	71,300	98,600
Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Municipal Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Government Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Corporate Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Asset Backed Securities (ABS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Mortgage Back Securities (MBS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | CMO [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 1 [Member] | Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103,900	87,900
Debt Securities [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103,900	87,900
Debt Securities [Member] | Level 2 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,000	6,100
Debt Securities [Member] | Level 2 [Member] | Municipal Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,000	6,100
Debt Securities [Member] | Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56,200	47,900
Debt Securities [Member] | Level 2 [Member] | Government Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56,200	47,900
Debt Securities [Member] | Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32,200	22,000
Debt Securities [Member] | Level 2 [Member] | Corporate Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32,200	22,000
Debt Securities [Member] | Level 2 [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300	300
Debt Securities [Member] | Level 2 [Member] | Asset Backed Securities (ABS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300	300
Debt Securities [Member] | Level 2 [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,700	9,600
Debt Securities [Member] | Level 2 [Member] | Mortgage Back Securities (MBS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,700	9,600
Debt Securities [Member] | Level 2 [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500	2,000
Debt Securities [Member] | Level 2 [Member] | CMO [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500	2,000
Debt Securities [Member] | Level 2 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2 [Member] | Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Commingled Fund [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Municipal Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Government Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Corporate Bonds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Asset Backed Securities (ABS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Mortgage Back Securities (MBS) [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | CMO [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 3 [Member] | Mutual Funds [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(800)	(400)
Derivative [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(800)	(400)
Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900)
Derivative [Member] | Swaps [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900)
Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,100	700
Derivative [Member] | Purchased Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,100	700
Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1,000)	(800)
Derivative [Member] | Written Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1,000)	(800)
Derivative [Member] | Short [Member] | Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(300)
Derivative [Member] | Short [Member] | Futures [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(300)
Derivative [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Using NAV [Member] | Swaps [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Using NAV [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Purchased Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Written Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Using NAV [Member] | Short [Member] | Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] | Using NAV [Member] | Short [Member] | Futures [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Level 1 [Member] | Swaps [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Level 1 [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Purchased Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Written Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 1 [Member] | Short [Member] | Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] | Level 1 [Member] | Short [Member] | Futures [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(800)	(400)
Derivative [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(800)	(400)
Derivative [Member] | Level 2 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900)
Derivative [Member] | Level 2 [Member] | Swaps [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900)
Derivative [Member] | Level 2 [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,100	700
Derivative [Member] | Level 2 [Member] | Purchased Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,100	700
Derivative [Member] | Level 2 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1,000)	(800)
Derivative [Member] | Level 2 [Member] | Written Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1,000)	(800)
Derivative [Member] | Level 2 [Member] | Short [Member] | Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(300)
Derivative [Member] | Level 2 [Member] | Short [Member] | Futures [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(300)
Derivative [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Level 3 [Member] | Swaps [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Derivative [Member] | Level 3 [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Purchased Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Written Options [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] | Level 3 [Member] | Short [Member] | Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] | Level 3 [Member] | Short [Member] | Futures [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	100	100
Miscellaneous [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	100	100
Miscellaneous [Member] | Using NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous [Member] | Using NAV [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	100	100
Miscellaneous [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	100	100
Miscellaneous [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

Employee Postretirement Benef84

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) $ in Millions	Dec. 31, 2015USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2016	$ 77.8
Expected Benefit Payments - 2017	49.5
Expected Benefit Payments - 2018	52.7
Expected Benefit Payments - 2019	59.2
Expected Benefit Payments - 2020	54.9
Expected Benefit Payments - 2021-2025	299.1
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2016	77.8
Expected Benefit Payments - 2017	49.5
Expected Benefit Payments - 2018	52.7
Expected Benefit Payments - 2019	59.2
Expected Benefit Payments - 2020	54.9
Expected Benefit Payments - 2021-2025	299.1
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2016	11.5
Expected Benefit Payments - 2017	11.9
Expected Benefit Payments - 2018	12.5
Expected Benefit Payments - 2019	13
Expected Benefit Payments - 2020	13.3
Expected Benefit Payments - 2021-2025	68.6
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2016	11.5
Expected Benefit Payments - 2017	11.9
Expected Benefit Payments - 2018	12.5
Expected Benefit Payments - 2019	13
Expected Benefit Payments - 2020	13.3
Expected Benefit Payments - 2021-2025	$ 68.6

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Sep. 02, 2014	Dec. 17, 2013
Line Of Credit Facility [Line Items]
Credit Facilities	$ 900,000,000		$ 900,000,000	$ 40,000,000
Borrowings Outstanding	247,000,000		139,000,000
Letters of Credit Outstanding	2,200,000	$ 93,800,000	2,300,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475,000,000		475,000,000		$ 200,000,000
Borrowings Outstanding	61,000,000		58,000,000
Letters of Credit Outstanding	500,000		600,000
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000		325,000,000
Borrowings Outstanding	0		12,000,000
Letters of Credit Outstanding	500,000		600,000
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000		150,000,000
Borrowings Outstanding	61,000,000		46,000,000
Letters of Credit Outstanding	0		0
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000		300,000,000
Borrowings Outstanding	163,000,000		50,000,000
Letters of Credit Outstanding	0		0
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125,000,000		125,000,000
Borrowings Outstanding	23,000,000		31,000,000
Letters of Credit Outstanding	$ 1,700,000		$ 1,700,000

Short-Term Debt - Credit Faci86

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Dec. 31, 2015	Apr. 10, 2015	Mar. 24, 2015	Sep. 02, 2014	Dec. 17, 2013	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013	Jun. 24, 2013
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity	$ 900,000,000			$ 40,000,000		$ 900,000,000	$ 900,000,000
Senior unsecured bridge credit										$ 1,075,000,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	0.70%					0.70%	0.89%
Line of Credit Facility maximum borrowing capacity	$ 475,000,000				$ 200,000,000	$ 475,000,000	$ 475,000,000
Interest rate description						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%;
Increase of credit facility					175,000,000
Tampa Electric Company [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity					$ 325,000,000			$ 325,000,000
Basis spread on federal funds rate					0.50%
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity	$ 150,000,000					$ 150,000,000
Credit facility maturity date			Mar. 23, 2018
Credit Facility amendment date			Mar. 24, 2015
Loan agreement program and liquidity fees	0.65%
Basis spread on federal funds rate			0.50%
Interest rate description						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
Tampa Electric Company [Member] | Before Amendment and Restatement [Member] | 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date			Apr. 14, 2015
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	1.29%					1.29%	1.16%
Basis spread on federal funds rate					0.50%
Interest rate description						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%;
TECO Energy [Member] | Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Maximum debt capitalization ratio									65.00%
TECO Finance [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	1.29%					1.29%	1.16%
Line of Credit Facility maximum borrowing capacity					$ 200,000,000
Increase of credit facility					100,000,000
Debt instrument maturity date		May 31, 2015
TECO Finance [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity								$ 300,000,000
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	1.29%					1.29%	1.16%
New Mexico Gas Company [Member] | NMGC Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity					$ 125,000,000
Credit facility maturity date				Dec. 17, 2018
Basis spread on federal funds rate				0.50%
Interest rate description						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%;
New Mexico Gas Company [Member] | NMGC Credit Agreement [Member] | Letter of Credit [Member]
Line Of Credit Facility [Line Items]
Increase of credit facility				$ 75,000,000
TEC Receivables Company [Member] | 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Interest rate description						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.
Minimum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage						0.125%
Minimum [Member] | Tampa Electric Company [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date					Oct. 25, 2016
Minimum [Member] | TECO Energy [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date					Oct. 25, 2016
Maximum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage						0.30%
Maximum [Member] | Tampa Electric Company [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date					Dec. 17, 2018
Maximum [Member] | TECO Energy [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date					Dec. 17, 2018
Maximum [Member] | TECO Energy [Member] | Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Maximum debt capitalization ratio							70.00%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions

May. 20, 2015

Apr. 10, 2015

Sep. 02, 2014

Jul. 16, 2014

May. 15, 2014

Sep. 03, 2013

Mar. 15, 2012

Feb. 08, 2011

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Sep. 01, 2013

Debt Instrument [Line Items]

Long-term debt, carrying amount

$ 3,850.2

$ 3,628.5

Estimated fair value

4,061.6

3,987.8

Purchase in lieu of redemption

274.5

83.3

$ 51.6

Held Bonds [Member]

Debt Instrument [Line Items]

Purchase in lieu of redemption

232.6

HCIDA Pollution Control Revenue Refunding Bonds [Member] | Held Bonds [Member]

Debt Instrument [Line Items]

Purchase in lieu of redemption

$ 232.6

TECO Finance [Member]

Debt Instrument [Line Items]

Debt instrument maturity date

May 31, 2015

TECO Finance [Member] | Floating Rate Notes Due 2018 [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 250

Debt instrument, offering date

Apr. 10, 2015

Debt instrument maturity date

Apr. 10, 2018

Basis spread on federal funds rate

0.60%

Interest rate, description

The 2018 Notes bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points.

Net proceeds from offering

$ 248.6

TECO Finance [Member] | Notes Matured in May 2015 [Member] | The TEC 2015 Notes

Debt Instrument [Line Items]

Payment of notes

$ 191

Tampa Electric Company [Member]

Debt Instrument [Line Items]

Long-term debt, carrying amount

$ 2,263.1

2,097.1

Purchase in lieu of redemption

$ 83.3

$ 83.3

$ 51.6

Tampa Electric Company [Member] | 4.35% Notes [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 300

Debt instrument, offering date

May 15, 2014

Debt instrument maturity date

Jan. 1, 2044

Basis spread on federal funds rate

0.15%

Net proceeds from offering

$ 296.6

Stated interest rate

4.35%

4.35%

Debt instrument principal amount market price percentage

99.933%

Redeemable principal amount percentage

100.00%

Redeemable principal amount percentage

100.00%

Debt instrument, start date of redemption

Nov. 15, 2043

Debt instrument, maturity year

2,044

Tampa Electric Company [Member] | 4.20% Notes [Member] | The TEC 2015 Notes

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 250

Debt instrument, offering date

May 20, 2015

Debt instrument maturity date

May 15, 2045

Basis spread on federal funds rate

0.20%

Net proceeds from offering

$ 246.8

Stated interest rate

4.20%

Debt instrument principal amount market price percentage

99.814%

Redeemable principal amount percentage

100.00%

Redeemable principal amount percentage

100.00%

Debt instrument, start date of redemption

Nov. 15, 2044

Tampa Electric Company [Member] | HCIDA Pollution Control Revenue Refunding Bonds [Member]

Debt Instrument [Line Items]

Stated interest rate

5.00%

5.15%

Purchase in lieu of redemption

$ 51.6

$ 86

Debt instrument, repurchase date

Sep. 3, 2013

Mar. 15, 2012

NMGI [Member] | Series A Senior Unsecured Notes 2.71% Notes due 2019 [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 50

Debt instrument, offering date

Sep. 2, 2014

Basis spread on federal funds rate

0.50%

Net proceeds from offering

$ 198.4

Stated interest rate

2.71%

Debt instrument principal amount market price percentage

100.00%

Redeemable principal amount percentage

100.00%

Debt instrument, start date of redemption

Jul. 30, 2019

NMGI [Member] | Series B Senior Unsecured 3.64 % Notes due 2024 [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 150

Debt instrument, offering date

Sep. 2, 2014

Basis spread on federal funds rate

0.50%

Net proceeds from offering

$ 198.4

Stated interest rate

3.64%

Debt instrument principal amount market price percentage

100.00%

Redeemable principal amount percentage

100.00%

Debt instrument, start date of redemption

Jul. 30, 2024

NMGC [Member] | Senior Unsecured 3.54 % Notes due 2026 [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 70

Debt instrument, offering date

Sep. 2, 2014

Basis spread on federal funds rate

0.50%

Net proceeds from offering

$ 69.3

Stated interest rate

3.54%

Debt instrument principal amount market price percentage

100.00%

Redeemable principal amount percentage

100.00%

Debt instrument, start date of redemption

Jul. 30, 2026

NMGC [Member] | New Mexico Gas Company 4.87 % Notes due 2021 [Member]

Debt Instrument [Line Items]

Aggregate principal amount issued

$ 200

Debt instrument, offering date

Jul. 16, 2014

Feb. 8, 2011

Debt instrument maturity date

Feb. 8, 2021

Stated interest rate

4.87%

Long-Term Debt - Schedule of Ma

Long-Term Debt - Schedule of Maturities of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	$ 3,850.2	$ 3,628.5
Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	2,263.1	$ 2,097.1
Tampa Electric Company [Member] | PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	0
2,017	0
2,018	50
2,019	0
2,020	0
Thereafter	211.7
Total long-term debt maturities	261.7
Debt Maturities [Member] | PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	0
2,017	0
2,018	50
2,019	0
2,020	0
Thereafter	211.7
Total long-term debt maturities	261.7
Debt Maturities [Member] | TECO Finance [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	250
2,017	300
2,018	250
2,019	0
2,020	300
Thereafter	0
Total long-term debt maturities	1,100
Debt Maturities [Member] | Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	83.3
2,017	0
2,018	254.2
2,019	0
2,020	0
Thereafter	1,666.7
Total long-term debt maturities	2,004.2
Debt Maturities [Member] | NMGC [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	270
Total long-term debt maturities	270
Debt Maturities [Member] | NMGI [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	0
2,017	0
2,018	0
2,019	50
2,020	0
Thereafter	150
Total long-term debt maturities	200
Debt Maturities [Member] | TECO Energy [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2,016	333.3
2,017	300
2,018	554.2
2,019	50
2,020	300
Thereafter	2,298.4
Total long-term debt maturities	$ 3,835.9

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long Term Debt Outstanding (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, total	$ 3,835.9	$ 3,610.5
Unamortized debt discount, net	14.3	18
Total long-term debt maturities	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
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	261.7	241.7
TECO Finance [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,100	1,041.2
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,265.9	2,099.3
Unamortized debt discount, net	(2.8)	(2.2)
Total long-term debt maturities	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
Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,004.2	1,857.6
Total long-term debt maturities	2,004.2
Tampa Electric Company [Member] | PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	261.7	241.7
Total long-term debt maturities	261.7
NMGI [Member]
Debt Instrument [Line Items]
Long-term debt, total	200	200
NMGC [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 270	270
6.75% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2,015
Long-term debt, total	$ 0	191.2
4.00% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2,016
Long-term debt, total	$ 250	250
6.57% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2,017
Long-term debt, total	$ 300	300
Floating Rate Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 250	0
5.15% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2,020
Long-term debt, total	$ 300	300
5.65% Refunding bonds [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 54.2	54.2
Variable Rate Bonds Repurchased In 2008 [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,020
Long-term debt, total	$ 0	0
5.15% Refunding bonds [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,025
Long-term debt, total	$ 0	0
1.5% term rate bonds repurchased in 2011 [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,030
Long-term debt, total	$ 0	0
5.0% Refunding bonds [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,034
Long-term debt, total	$ 0	0
6.25% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Maturity range start	2,015
Maturity range end	2,016
Long-term debt, total	$ 83.3	166.7
6.10% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 50	50
6.10% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 200	200
5.40% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,021
Long-term debt, total	$ 46.7	46.7
5.40% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,021
Long-term debt, total	$ 231.7	231.7
2.60% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,022
Long-term debt, total	$ 25	25
2.60% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,022
Long-term debt, total	$ 225	225
6.55% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,036
Long-term debt, total	$ 250	250
6.15% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,037
Long-term debt, total	$ 60	60
6.15% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,037
Long-term debt, total	$ 190	190
4.10% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,042
Long-term debt, total	$ 50	50
4.10% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,042
Long-term debt, total	$ 250	250
4.35% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,044
Long-term debt, total	$ 10	10
4.35% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,044
Long-term debt, total	$ 290	290
4.20% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2,045
Long-term debt, total	$ 20	0
4.20% Notes [Member] | Tampa Electric Company [Member] | Tampa Electric [Member]
Debt Instrument [Line Items]
Due	2,045
Long-term debt, total	$ 230	0
2.71 % Notes [Member] | NMGI [Member]
Debt Instrument [Line Items]
Due	2,019
Long-term debt, total	$ 50	50
3.64 % Notes [Member] | NMGI [Member]
Debt Instrument [Line Items]
Due	2,024
Long-term debt, total	$ 150	150
4.87 % Notes [Member] | NMGC [Member]
Debt Instrument [Line Items]
Due	2,021
Long-term debt, total	$ 200	200
3.54 % Notes [Member] | NMGC [Member]
Debt Instrument [Line Items]
Due	2,026
Long-term debt, total	$ 70	$ 70

Long-Term Debt - Schedule of 91

Long-Term Debt - Schedule of Long Term Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	May. 15, 2014	Sep. 30, 2013	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2008
PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
TECO Finance [Member] | 6.75% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.75%
TECO Finance [Member] | 4.00% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.00%
TECO Finance [Member] | 6.57% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.57%
TECO Finance [Member] | 5.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.15%
Tampa Electric Company [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.65%
Tampa Electric Company [Member] | 5.15% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.15%
Tampa Electric Company [Member] | 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Stated interest rate	1.50%
Repurchased bonds, par amount					$ 75
Tampa Electric Company [Member] | 5.0% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
Tampa Electric Company [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.25%
Tampa Electric Company [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
Tampa Electric Company [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
Tampa Electric Company [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
Tampa Electric Company [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.55%
Tampa Electric Company [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Tampa Electric Company [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Tampa Electric Company [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%	4.35%
Tampa Electric Company [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
Tampa Electric Company [Member] | Variable Rate Bonds Repurchased In 2008 [Member]
Debt Instrument [Line Items]
Repurchased bonds, par amount						$ 20
Tampa Electric Company [Member] | Refunding Bonds Repurchased In 2013 [Member]
Debt Instrument [Line Items]
Repurchased bonds, par amount			$ 51.6
Tampa Electric Company [Member] | Refunding Bonds Repurchased In 2012 [Member]
Debt Instrument [Line Items]
Repurchased bonds, par amount				$ 86
NMGI [Member] | 2.71 % Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.71%
NMGI [Member] | 3.64 % Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.64%
NMGC [Member] | 4.87 % Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.87%
NMGC [Member] | 3.54 % Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.54%

Preferred Stock - Additional In

Preferred Stock - Additional Information (Detail)	Dec. 31, 2015$ / sharesshares
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, par value | $ / shares	$ 1
Preferred Stock Par Value [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, shares authorized	10,000,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, par value | $ / shares	$ 100
Preferred stock, no par value | $ / shares
Tampa Electric Company [Member] | Preferred Stock Par Value [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, shares authorized	1,500,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preferred Stock No Par Value [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preference Stock (Subordinated Preferred Stock) Of Tampa Electric - No Par [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, no par value | $ / shares
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

Common Stock - Additional Infor

Common Stock - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 04, 2015
Class Of Stock [Line Items]
Non-vested awards compensation costs, period for recognition		2 years
Actual restricted shares granted		700,000	800,000	700,000
Granted, weighted average grant date fair value		$ 22.96	$ 14.69	$ 17.21
Total fair market value of awards vesting		$ 7.5	$ 3.6	$ 3.5
Unrecognized compensation cost related to all non-vested awards		13.2
Aggregate intrinsic value of stock options exercised		2.9	2.7	2.4
Cash received from all option exercises		9.4	10.8	6.7
Income tax benefit realized from stock option exercises		$ 1.1	$ 1	$ 0.8
Maximum [Member]
Class Of Stock [Line Items]
Percentage of performance based grants can vest		150.00%
Minimum [Member]
Class Of Stock [Line Items]
Percentage of performance based grants can vest		0.00%
Restricted Stock [Member]
Class Of Stock [Line Items]
Non-vested awards compensation costs, period for recognition		3 years
Director Restricted Stock [Member]
Class Of Stock [Line Items]
Time-vested restricted stock granted to directors, vesting period		1 year
2015 Performance-Based Restricted Stock Grants Vested [Member] | Maximum [Member]
Class Of Stock [Line Items]
Percentage of performance based grants can vest		200.00%
2015 Performance-Based Restricted Stock Grants Vested [Member] | Minimum [Member]
Class Of Stock [Line Items]
Percentage of performance based grants can vest		0.00%
2010 Plan [Member]
Class Of Stock [Line Items]
Reduction in number of shares of common stock subject to grants		3,000,000
Common stock subject to grant		4,000,000
Underwriter [Member]
Class Of Stock [Line Items]
Number of shares issued through underwriting agreement	15,500,000
Shares offered, price per share	$ 18.10
Net proceeds from offering through the underwriting	$ 271
Additional shares to be offered under underwriting agreement	2,300,000
Number of days option granted to underwriters	30 days
Proceeds from issuance to underwriters	$ 21
Underwriters exercised this option for an additional, shares	1,200,000
Emera Inc. [Member]
Class Of Stock [Line Items]
Amount of cash offered for each acquiree common stock share outstanding					$ 27.55

Common Stock - Schedule of Assu

Common Stock - Schedule of Assumptions Used to Determine Fair Value (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Risk-free interest rate	0.83%	0.68%	0.41%
Expected lives (in years)	3 years	3 years	3 years
Expected stock volatility	14.78%	17.36%	19.04%
Dividend yield	3.98%	5.13%	4.83%

Common Stock - Schedule of Addi

Common Stock - Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation costs	$ 13.1	$ 12.7	$ 13.5
Income tax benefits	5.1	4.9	5.2
Excess tax benefits	$ 0	$ 0.4	$ 0

Common Stock - Summary of Non-V

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	700,000	800,000	700,000
Granted, weighted average grant date fair value	$ 22.96	$ 14.69	$ 17.21
Time-Based Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2014, Number of Shares	668,000
Granted, Number of Shares	213,000
Vested, Number of Shares	(273,000)
Forfeited, Number of Shares	(19,000)
Nonvested balance at Dec. 31, 2015, Number of Shares	589,000	668,000
Nonvested balance at Dec. 31, 2014, Weighted Average Grant Date Fair Value	$ 17.56
Granted, weighted average grant date fair value	21.34
Vested, Weighted Average Grant Date Fair Value	17.96
Forfeited, Weighted Average Grant Date Fair Value	17.78
Nonvested balance at Dec. 31, 2015, Weighted Average Grant Date Fair Value	$ 18.74	$ 17.56
Performance-Based Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2014, Number of Shares	1,515,000
Granted, Number of Shares	445,000
Vested, Number of Shares	(626,000)
Forfeited, Number of Shares	(43,000)
Nonvested balance at Dec. 31, 2015, Number of Shares	1,291,000	1,515,000
Nonvested balance at Dec. 31, 2014, Weighted Average Grant Date Fair Value	$ 15.44
Granted, weighted average grant date fair value	23.72
Vested, Weighted Average Grant Date Fair Value	15.94
Forfeited, Weighted Average Grant Date Fair Value	16.05
Nonvested balance at Dec. 31, 2015, Weighted Average Grant Date Fair Value	$ 18.06	$ 15.44

Common Stock - Summary of Non97

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average remaining contractual term of restricted stock, years	2 years

Common Stock - Summary of Stock

Common Stock - Summary of Stock Option Transactions (Detail) - Stock Options [Member] $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Schedule Of Stock Options [Line Items]
Outstanding balance at Dec. 31, 2014, Number of Shares	840
Granted, Number of Shares	0
Exercised, Number of Shares	(580)
Cancelled, Number of Shares	(6)
Outstanding balance at Dec. 31, 2015, Number of Shares	254
Exercisable at Dec. 31, 2015, Number of Shares	254
Available for future grant at Dec. 31, 2015, Number of Shares	2,429
Outstanding balance at Dec. 31, 2014, Weighted Avg. Option Price (per share) | $ / shares	$ 16.32
Granted, Weighted Avg. Option Price | $ / shares	0
Exercised, Weighted Avg. Option Price | $ / shares	16.30
Cancelled, Weighted Avg. Option Price | $ / shares	18.87
Outstanding balance at Dec. 31, 2015, Weighted Avg. Option Price (per share) | $ / shares	16.30
Exercisable at Dec. 31, 2015, Weighted Avg. Option Price | $ / shares	$ 16.30
Outstanding balance at Dec. 31, 2015, Weighted Avg. Remaining Contractual Term	1 year
Exercisable at Dec. 31, 2015, Weighted Avg. Remaining Contractual Term	1 year
Outstanding balance at Dec. 31, 2015, Aggregate Intrinsic Value | $	$ 2.6
Exercisable at Dec. 31, 2015, Aggregate Intrinsic Value | $	$ 2.6

Common Stock - Summary of Sto99

Common Stock - Summary of Stock Option Transactions (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015$ / shares
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Option price	$ 16.30

Other Comprehensive Income - Ac

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross		$ 4.3		$ (0.5)		$ 1
Reclassification from AOCI to net income, Gross	[1]	1.4		1.6		1.3
Gain (Loss) on cash flow hedges, Gross		5.7		1.1		2.3
Amortization of unrecognized benefit costs and other, Gross	[2]	3.4		(4.8)		23.6
Increase in unrecognized postemployment costs, Gross	[3]			(12.9)
Change in benefit obligation due to valuation, Gross		(15.5)	[4]	12.6	[5]
Recognized cost due to settlement, Gross		12.1	[6]			2.6
Total other comprehensive income (loss), Gross		5.7		(4)		28.5
Unrealized gain (loss) on cash flow hedges, Tax		(1.5)		0.2		(0.4)
Reclassification from AOCI to net income, Tax	[1]	(0.7)		(0.6)		(0.5)
Gain (Loss) on cash flow hedges, Tax		(2.2)		(0.4)		(0.9)
Amortization of unrecognized benefit costs and other, Tax	[2]	(1.3)		1.8		(8.8)
Increase in unrecognized postemployment costs, Tax	[3]			4.7
Change in benefit obligation due to valuation, Tax		5.7	[4]	(4.6)	[5]
Recognized cost due to settlement, Tax		(4.4)	[6]			(1)
Total other comprehensive income (loss), Tax		(2.2)		1.5		(10.7)
Unrealized gain (loss) on cash flow hedges, Net		2.8		(0.3)		0.6
Reclassification from AOCI to net income, Net	[1]	0.7		1		0.8
Gain (Loss) on cash flow hedges, Net		3.5		0.7		1.4
Amortization of unrecognized benefit costs and other	[2]	2.1		(3)		14.8
Increase in unrecognized postemployment costs		0		(8.2)	[3]	0
Change in benefit obligation due to valuation, Net		(9.8)	[4]	8	[5]
Recognized cost due to settlement, Net		7.7	[6]	0		1.6
Other comprehensive income (loss), net of tax		3.5		(2.5)		17.8
Unamortized pension losses and prior service credits	[7]	(34.2)		(22.5)
Unamortized other benefit gains, prior service costs and transition obligations	[8]	25.6		13.9
Net unrealized losses from cash flow hedges	[9]	(3.6)		(7.1)
Total accumulated other comprehensive loss		(12.2)		(15.7)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross		4.3		0		0
Reclassification from AOCI to net income, Gross		1.4		1.1		1.4
Gain (Loss) on cash flow hedges, Gross		5.7		1.1		1.4
Total other comprehensive income (loss), Gross		5.7		1.1		1.4
Unrealized gain (loss) on cash flow hedges, Tax		(1.5)		0		0
Reclassification from AOCI to net income, Tax		(0.7)		(0.4)		(0.5)
Gain (Loss) on cash flow hedges, Tax		(2.2)		(0.4)		(0.5)
Total other comprehensive income (loss), Tax		(2.2)		(0.4)		(0.5)
Unrealized gain (loss) on cash flow hedges, Net		2.8		0		0
Reclassification from AOCI to net income, Net		0.7		0.7		0.9
Gain (Loss) on cash flow hedges, Net		3.5		0.7		0.9
Other comprehensive income (loss), net of tax		3.5		0.7		$ 0.9
Net unrealized losses from cash flow hedges	[9]	(3.6)		(7.1)
Total accumulated other comprehensive loss		$ (3.6)		$ (7.1)
[1]	Related to interest rate contracts in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations.
[2]	Related to postretirement and postemployment benefits. See Note 5 for additional information.
[3]	Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability.
[4]	Related to the transfer of employees and their associated postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI.
[5]	Includes an adjustment to eliminate TECO Coal’s OPEB liability. See Note 5 for additional information.
[6]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Note 19 for additional information.
[7]	Net of tax benefit of $21.5 million and $13.8 million as of Dec. 31, 2015 and 2014, respectively.
[8]	Net of tax expense of $16.1 million and $8.3 million as of Dec. 31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5.
[9]	Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.

Other Comprehensive Income -101

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Net income discontinued operations settlement	$ 7.7
Net unrealized losses from cash flow hedges, tax benefit	4.5	$ 2.3
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	4.5	2.3
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	13.8	21.5
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unamortized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	$ 8.3	$ 16.1

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic earnings per share
Net income from continuing operations	$ 51	$ 64.9	$ 61.5	$ 63.8	$ 27.4	$ 73	$ 57.6	$ 48.4	$ 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)	9
Amount allocated to nonvested participating shareholders									0	0	0
Income (loss) from discontinued operations —Basic									(67.7)	(76)	9
Net income	$ 50.5	$ 53.2	$ 11.8	$ 58	$ 10.8	$ 11.1	$ 58.4	$ 50.1	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
Earnings per share from continuing operations available to common shareholders—Basic	$ 0.22	$ 0.28	$ 0.26	$ 0.27	$ 0.11	$ 0.32	$ 0.27	$ 0.22	$ 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 - Basic	$ 0.21	$ 0.23	$ 0.05	$ 0.25	$ 0.04	$ 0.04	$ 0.27	$ 0.23	$ 0.74	$ 0.58	$ 0.92
Diluted earnings per share
Net income from continuing operations	$ 51	$ 64.9	$ 61.5	$ 63.8	$ 27.4	$ 73	$ 57.6	$ 48.4	$ 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)	9
Amount allocated to nonvested participating shareholders									0	0	0
Income (loss) from discontinued operations available to common shareholders—Diluted									(67.7)	(76)	9
Net income	$ 50.5	$ 53.2	$ 11.8	$ 58	$ 10.8	$ 11.1	$ 58.4	$ 50.1	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
Average common shares outstanding - Basic									233.1	223.1	215
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	$ 0.22	$ 0.28	$ 0.26	$ 0.27	$ 0.11	$ 0.32	$ 0.27	$ 0.22	$ 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 - Diluted	$ 0.21	$ 0.23	$ 0.05	$ 0.25	$ 0.04	$ 0.04	$ 0.27	$ 0.23	$ 0.74	$ 0.58	$ 0.92
Anti-dilutive shares									0	0	0

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Dec. 19, 2013USD ($)	Feb. 08, 2011CustomerLawsuitInsuranceCarrier	Dec. 31, 2015USD ($)Claims	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2015USD ($)	Mar. 31, 2011Customer
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers | Customer		28,700					32,000
Number of class actions settled | Claims			2
Number of lawsuits for insurance carriers | Lawsuit		2
Number of insurance carriers | InsuranceCarrier		18
Total rental expense and leases			$ 15.3	$ 13.7	$ 7.6
Letters of Credit Outstanding			2.2	2.3		$ 93.8
Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Total rental expense and leases			3.8	4.1	$ 2.3
Letters of Credit Outstanding			0.5	$ 0.6
PGS [Member]
Long Term Commitments [Line Items]
Total potential penalties			3.9
Ultimate financial liability to superfund sites and former MGP sites			33.9
PGS [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Total potential penalties			3.9
Ultimate financial liability to superfund sites and former MGP sites			$ 33.9
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement amount	$ 7.5
Damages awarded	$ 21.1
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member] | U.S. prime rate plus [Member]
Long Term Commitments [Line Items]
Litigation settlement interest	2.00%

Commitments and Contingencie104

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2015USD ($)
Long Term Commitments [Line Items]
Future Minimum Capacity Payments Under PPAs Due, 2016	$ 14.6
Future Minimum Capacity Payments Under PPAs Due, 2017	9.9
Future Minimum Capacity Payments Under PPAs Due, 2018	10.1
Future Minimum Capacity Payments Under PPAs Due, 2019	0
Future Minimum Capacity Payments Under PPAs Due, 2020	0
Future Minimum Capacity Payments Under PPAs Due, Thereafter	0
Total future minimum capacity payments under PPAs due	34.6
Future Minimum Operating Leases Payments Due, 2016	7.7
Future Minimum Operating Leases Payments Due, 2017	7.1
Future Minimum Operating Leases Payments Due, 2018	6.4
Future Minimum Operating Leases Payments Due, 2019	5.7
Future Minimum Operating Leases Payments Due, 2020	5.4
Future Minimum Operating Leases Payments Due, Thereafter	18.6
Total future minimum operating leases payments due	50.9
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2016	222.5
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2017	21.5
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2018	9.6
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2019	9.7
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2020	4.7
Future Minimum Net Purchase Obligations/Commitments Payments Due, Thereafter	20
Total future minimum net purchase obligations/commitments payments due	288
Future Minimum Payments Due, 2016	244.8
Future Minimum Payments Due, 2017	38.5
Future Minimum Payments Due, 2018	26.1
Future Minimum Payments Due, 2019	15.4
Future Minimum Payments Due, 2020	10.1
Future Minimum Payments Due, Thereafter	38.6
Total future minimum payments	373.5
Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Future Minimum Capacity Payments Under PPAs Due, 2016	14.6
Future Minimum Capacity Payments Under PPAs Due, 2017	9.9
Future Minimum Capacity Payments Under PPAs Due, 2018	10.1
Future Minimum Capacity Payments Under PPAs Due, 2019	0
Future Minimum Capacity Payments Under PPAs Due, 2020	0
Future Minimum Capacity Payments Under PPAs Due, Thereafter	0
Total future minimum capacity payments under PPAs due	34.6
Future Minimum Operating Leases Payments Due, 2016	5.7
Future Minimum Operating Leases Payments Due, 2017	5.2
Future Minimum Operating Leases Payments Due, 2018	4.7
Future Minimum Operating Leases Payments Due, 2019	4.4
Future Minimum Operating Leases Payments Due, 2020	4.1
Future Minimum Operating Leases Payments Due, Thereafter	14.5
Total future minimum operating leases payments due	38.6
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2016	218.3
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2017	21.5
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2018	9.6
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2019	9.7
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2020	4.7
Future Minimum Net Purchase Obligations/Commitments Payments Due, Thereafter	20
Total future minimum net purchase obligations/commitments payments due	283.8
Future Minimum Payments Due, 2016	238.6
Future Minimum Payments Due, 2017	36.6
Future Minimum Payments Due, 2018	24.4
Future Minimum Payments Due, 2019	14.1
Future Minimum Payments Due, 2020	8.8
Future Minimum Payments Due, Thereafter	34.5
Total future minimum payments	$ 357

Commitments and Contingencie105

Commitments and Contingencies - Letters of Credit and Guarantees (Detail)	Dec. 31, 2015USD ($)
Guarantee Obligations [Line Items]
Year of Expiration 2016	$ 90,000,000
Year of expiration 2017-2020	0
Year of expiration After 2020	92,900,000
Maximum Theoretical Obligation	182,900,000
Liabilities Recognized at Dec 31, 2015	0
Tampa Electric Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	500,000
Maximum Theoretical Obligation	500,000
Liabilities Recognized at Dec 31, 2015	100,000
New Mexico Gas Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	1,700,000
Maximum Theoretical Obligation	1,700,000
Liabilities Recognized at Dec 31, 2015	0
Fuel Sales and Transportation [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2016	0
Year of expiration 2017-2020	0
Year of expiration After 2020	92,900,000
Maximum Theoretical Obligation	92,900,000
Liabilities Recognized at Dec 31, 2015	0
Letters of Indemnity - Coal Mining Permits
Guarantee Obligations [Line Items]
Year of Expiration 2016	90,000,000
Year of expiration 2017-2020	0
Year of expiration After 2020	0
Maximum Theoretical Obligation	90,000,000
Liabilities Recognized at Dec 31, 2015	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - Ausley McMullen, P.A [Member] $ in Millions	12 Months Ended
	Dec. 31, 2013USD ($)
Related Party Transaction [Line Items]
Legal fees	$ 1.7
Tampa Electric Company [Member]
Related Party Transaction [Line Items]
Legal fees	$ 1.7

Segment Information - Additiona

Segment Information - Additional Information (Detail)	Dec. 31, 2015Customer
Tampa Electric [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	719,000
Tampa Electric [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	719,000
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	361,000
PGS [Member] | Minimum [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	361,000
NMGC [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	516,000

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 676.1	$ 693.8	$ 680.6	$ 693	$ 695.5	$ 687.2	$ 605.7	$ 578	$ 2,743.5	$ 2,566.4	$ 2,355.1
Depreciation and amortization									349	315.3	291.8
Total interest charges									186.4	171.1	161.4
Internally allocated interest									0	0	0
Provision for income taxes									155.3	138.9	112.6
Net income from continuing operations	51	64.9	61.5	63.8	27.4	73	57.6	48.4	241.2	206.4	188.7
Discontinued operations, net of tax									(67.7)	(76)	9
Net income	50.5	$ 53.2	$ 11.8	$ 58	10.8	$ 11.1	$ 58.4	$ 50.1	173.5	130.4	197.7
Goodwill	408.4				408.3				408.4	408.3	0
Total assets	8,961.1				8,726.2				8,961.1	8,726.2	7,448
Capital expenditures									739.7	703.8	526.1
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,419.2	2,419	2,342.8
Depreciation and amortization									313.5	302.6	290.3
Total interest charges									109.6	106.6	105.3
Provision for income taxes									165.5	155.9	138.8
Net income									276.3	260.3	225.6
Total assets	7,726.7				7,274.3				7,726.7	7,274.3	6,875.8
Capital expenditures									686.6	671	501.3
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									(9.5)	(2.4)	(2.2)
Depreciation and amortization									0	0	0
Total interest charges									(1.3)	(5.8)	(7.8)
Internally allocated interest									(1.3)	(5.8)	(7.8)
Provision for income taxes									0	0	0
Net income from continuing operations									0	0	0
Discontinued operations, net of tax									0	0	0
Net income									0	0	0
Goodwill	0				0				0	0
Total assets	(2,376.2)				(1,998.5)				(2,376.2)	(1,998.5)	(1,755.6)
Capital expenditures									0	0	0
Eliminations | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									(6.6)	(1.6)	(1.2)
Depreciation and amortization									0	0	0
Total interest charges									0	0	0
Provision for income taxes									0	0	0
Net income									0	0	0
Total assets	(9.4)				(7.1)				(9.4)	(7.1)	(8.9)
Capital expenditures									0	0	0
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues									2,743.5	2,566.4	2,355.1
Revenues - External [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,419.2	2,419	2,342.8
Revenues - External [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Revenues - External [Member] | Eliminations | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Sales to Affiliates [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Sales to Affiliates [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									(9.5)	(2.4)	(2.2)
Sales to Affiliates [Member] | Eliminations | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									(6.6)	(1.6)	(1.2)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									2,018.3	2,021	1,950.5
Depreciation and amortization									256.7	248.6	238.8
Total interest charges									95.1	92.8	91.8
Internally allocated interest									0	0	0
Provision for income taxes									143.6	133.2	116.9
Net income from continuing operations									241	224.5	190.9
Discontinued operations, net of tax									0	0	0
Net income									241	224.5	190.9
Goodwill	0				0				0	0
Total assets	7,020.7				6,565.4				7,020.7	6,565.4	6,126.9
Capital expenditures									592.6	582.1	422.3
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,018.3	2,021	1,950.5
Depreciation and amortization									256.7	248.6	238.8
Total interest charges									95.1	92.8	91.8
Provision for income taxes									143.6	133.2	116.9
Net income									241	224.5	190.9
Total assets	6,637.1				6,234.4				6,637.1	6,234.4	5,895.4
Capital expenditures									592.6	582.1	422.3
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									2,014.9	2,019.9	1,949.6
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,017.7	2,020.5	1,950.1
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									3.4	1.1	0.9
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0.6	0.5	0.4
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									407.5	399.6	393.5
Depreciation and amortization									56.8	54	51.5
Total interest charges									14.5	13.8	13.5
Internally allocated interest									0	0	0
Provision for income taxes									21.9	22.7	21.9
Net income from continuing operations									35.3	35.8	34.7
Discontinued operations, net of tax									0	0	0
Net income									35.3	35.8	34.7
Goodwill	0				0				0	0
Total assets	1,137.4				1,082.8				1,137.4	1,082.8	1,021.2
Capital expenditures									94	88.9	79
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									407.5	399.6	393.5
Depreciation and amortization									56.8	54	51.5
Total interest charges									14.5	13.8	13.5
Provision for income taxes									21.9	22.7	21.9
Net income									35.3	35.8	34.7
Total assets	1,099				1,047				1,099	1,047	989.3
Capital expenditures									94	88.9	79
PGS [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									401.5	398.5	392.7
PGS [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									401.5	398.5	392.7
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									6	1.1	0.8
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									6	1.1	0.8
NMGC [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									316.5	137.5	0
Depreciation and amortization									33.8	11	0
Total interest charges									13	4.2	0
Internally allocated interest									0	0	0
Provision for income taxes									15.4	7.1	0
Net income from continuing operations									24.1	10.5	0
Discontinued operations, net of tax									0	0	0
Net income									24.1	10.5	0
Goodwill	408.4				408.3				408.4	408.3
Total assets	1,231.3				1,237.2				1,231.3	1,237.2	0
Capital expenditures									48.7	18.2	0
NMGC [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									316.5	137.5	0
NMGC [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Depreciation and amortization									0	0	0
Total interest charges									0	0	0
Internally allocated interest									0	0	0
Provision for income taxes									0	0	0
Net income from continuing operations									0	0	0
Discontinued operations, net of tax									(69.6)	(82)	9
Net income									(69.6)	(82)	9
Goodwill	0				0				0	0
Total assets	0				227.7				0	227.7	316.3
Capital expenditures									3.7	14.6	22.4
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									10.7	10.7	13.3
Depreciation and amortization									1.7	1.7	1.5
Total interest charges									65.1	66.1	63.9
Internally allocated interest									1.3	5.8	7.8
Provision for income taxes									(25.6)	(24.1)	(26.2)
Net income from continuing operations									(59.2)	(64.4)	(36.9)
Discontinued operations, net of tax									1.9	6	0
Net income									(57.3)	(58.4)	(36.9)
Goodwill	0				0				0	0
Total assets	$ 1,947.9				$ 1,611.6				1,947.9	1,611.6	1,739.2
Capital expenditures									0.7	0	2.4
Other [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									10.6	10.5	12.8
Other [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									$ 0.1	$ 0.2	$ 0.5

Segment Information - Schedu109

Segment Information - Schedule of Segment Information (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting [Abstract]
Internally allocated interest costs, pre tax rate	6.00%	6.00%	6.00%
Capital structure assumption, debt to equity ratio	50.00%
Mineral rights	$ 0	$ 10.9	$ 12.1

Asset Retirement Obligations -

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	$ 6.8	$ 6.1	$ 28.6
Cost of removal or dismantling of assets charged to regulatory liability	$ 6.8	6.1
TECO Coal [Member]
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation		$ 22.5

Asset Retirement Obligations111

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation [Line Items]
Beginning balance	$ 6.1	$ 28.6
Additional liabilities	0.9	0.1
Revisions to estimated cash flows	(0.5)	0.2
Acquisition of NMGC	0	0.8
Reclassification to liabilities associated with assets held for sale	0	(22.5)
Other	0.3	(1.1)
Ending balance	6.8	6.1
Tampa Electric Company [Member]
Asset Retirement Obligation [Line Items]
Beginning balance	5.3	4.8
Additional liabilities	0.9	0.1
Revisions to estimated cash flows	(0.5)	0.2
Other	0.3	0.2
Ending balance	$ 6	$ 5.3

Asset Retirement Obligations112

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation [Line Items]
Other asset retirement obligations	$ 0.3	$ (1.1)
Other [Member]
Asset Retirement Obligation [Line Items]
Other asset retirement obligations	$ 0.3	0.2
TECO Coal [Member] | Discontinued Operations [Member]
Asset Retirement Obligation [Line Items]
Other asset retirement obligations		$ (1.3)

Accounting for Derivative In113

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative assets	$ 200,000	$ 0
Derivative liabilities	26,200,000	42,700,000
Cash collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	(23,900,000)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	0	0
Derivative liabilities	26,200,000	42,700,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	$ (24,100,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Nov. 30, 2017
Natural Gas Contracts [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Nov. 30, 2017

Accounting for Derivative In114

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) - Natural Gas Contracts [Member] MMBTU in Millions	Dec. 31, 2015MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	43.5
Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32.6
2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2016 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	38.4
2016 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	27.6
2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2017 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5.1
2017 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	$ 0.2	$ 0
Natural gas derivative liabilities	26.2	42.7
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	26.2	42.7
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.2
Natural gas derivative liabilities	26.2	42.7
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	26.2	42.7
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0.2
Natural gas derivative liabilities	26.2	42.7
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	26.2	42.7
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivatives assets	0
Natural gas derivative liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0.2	$ 0
Derivative liabilities	26.2	42.7
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	26.2	42.7
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	$ 0	$ 0

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 78.9	$ 71.4	$ 64.7
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	78.9	71.4	64.7
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	33.6	25.7	22.1
Power Purchase Agreements [Member] | Variable Interest Entities [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 33.6	$ 25.7	$ 22.1
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	117
Minimum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	157
Maximum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	157

Discontinued Operations, Ass118

Discontinued Operations, Assets Held for Sale and Asset Impairments - Additional Information (Detail) - USD ($)	6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 21, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Asset impairment			$ 78,600,000	$ 115,900,000	$ 0
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Asset impairment	$ 78,600,000			115,900,000	$ 0
Effects of inflation rate					1.00%
Contingent payments			0			$ 60,000,000
Loss on sale, pretax		$ (10,000,000)	$ (10,000,000)	$ 0	$ 0
Settlement charge, related to unfunded black lung obligations		$ 7,700,000
Transaction costs, pretax	12,300,000
Legal and other consultant costs	2,500,000
Severance and other employee costs	$ 9,800,000

Discontinued Operations, Ass119

Discontinued Operations, Assets Held for Sale and Asset Impairments - Carrying Amount of Assets and Liabilities Held for Sale (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets	$ 0	$ 109.6
Property, plant and equipment, net and other long-term assets	0	59.8
Current liabilities	0	39.4
Long-term liabilities	$ 0	65.4
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets		109.6
Property, plant and equipment, net and other long-term assets		59.8
Total assets held for sale		169.4
Current liabilities		39.4
Long-term liabilities		65.4
Total liabilities associated with assets held for sale		$ 104.8

Discontinued Operations, Ass120

Discontinued Operations, Assets Held for Sale and Asset Impairments - Components of Discontinued Operations (Detail) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
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)	9
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues		200.4	443.6	496.2
Income (loss) from operations		(16.9)	(13.9)	5.4
Loss on impairment		(78.6)	(115.9)	0
Loss on sale	$ (10)	(10)	0	0
Income (loss) from discontinued operations		(105.5)	(129.8)	5.4
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Income (loss) from operations		(0.8)	4.4	(0.2)
Income (loss) from discontinued operations		(0.8)	4.4	(0.2)
TECO Coal and TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Provision (benefit) for income taxes		$ (38.6)	$ (49.4)	$ (3.8)

Goodwill - Changes in Carrying

Goodwill - Changes in Carrying Amount of Goodwill (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Beginning Balance	$ 408.3	$ 0
Acquisition of NMGC		408.3
Measurement period adjustments	0.1
Ending Balance	408.4	408.3
NMGC [Member]
Goodwill [Line Items]
Beginning Balance	408.3	0
Acquisition of NMGC		408.3
Measurement period adjustments	0.1
Ending Balance	$ 408.4	$ 408.3

Goodwill - Additional Informati

Goodwill - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Asset impairment	$ 78,600,000	$ 115,900,000	$ 0
NMGC [Member]
Goodwill [Line Items]
Asset impairment	$ 0	$ 0

Mergers and Acquisitions - Addi

Mergers and Acquisitions - Additional Information (Detail)	Sep. 04, 2015USD ($)$ / shares	Sep. 02, 2014USD ($)EmployeeCustomerCountryPipelines	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Aggregate purchase price		$ 950,000,000
Termination fee payable by company	$ 212,500,000
Business combination incremental transaction related costs			$ 17,000,000
Customer percentage of state population		60.00%
Mileage of transmission pipeline served | Pipelines		1,600
Mileage of distribution lines served | Pipelines		10,000
After-tax non-recurring acquisition consummation, integration and other costs				$ 8,600,000	$ 6,200,000
Obligations associated with severance benefits costs			700,000	2,600,000
Tampa Electric Company [Member]
Business Acquisition [Line Items]
Termination fee payable by company	$ 212,500,000
Emera Inc. [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding | $ / shares	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Emera Inc. [Member] | Tampa Electric Company [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding | $ / shares	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Senior secured notes	$ 2,300,000,000
NMGI [Member]
Business Acquisition [Line Items]
Aggregate purchase price		$ 950,000,000
Business acquisition, effective date		Sep. 2, 2014
NMGC [Member]
Business Acquisition [Line Items]
Senior secured notes		$ 200,000,000
Number of employees | Employee		720
Minimum number of customers served | Customer		513,000
Customer rate credit		$ 2,000,000
Increase in rate credit		$ 4,000,000
Goodwill expected tax deductible amount			146,100,000
NM [Member]
Business Acquisition [Line Items]
Number of counties in which entity operates | Country		23
Number of counties | Country		33
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Senior secured notes		$ 22,700,000
Revenue			316,500,000	137,500,000
Net income			$ 19,600,000	$ 8,200,000

Mergers and Acquisitions - Cons

Mergers and Acquisitions - Consideration in Acquisition (Detail) $ in Millions	Sep. 02, 2014USD ($)
Business Combinations [Abstract]
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
Total consideration transferred, excluding cash and working capital adjustments	$ 950

Mergers and Acquisitions - Purc

Mergers and Acquisitions - Purchase Price Allocation (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Sep. 02, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Goodwill	$ 408.4	$ 408.3		$ 0
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Current assets			$ 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

Mergers and Acquisitions - Prel

Mergers and Acquisitions - Preliminary Purchase Price Allocation (Parenthetical) (Detail) - NMGI and NMGC [Member] $ in Millions	Sep. 02, 2014USD ($)
Business Acquisition [Line Items]
Accounts receivables	$ 18.9
Gross contract value	19.6
Contractual receivables not expected to be collected	$ 0.7

Mergers and Acquisitions - Pro

Mergers and Acquisitions - Pro Forma Earning (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Revenues	$ 2,806.6	$ 2,704
Net income from continuing operations	$ 223.8	$ 216.8
Basic and diluted EPS from continuing operations	$ 0.96	$ 0.93

Mergers and Acquisitions - Afte

Mergers and Acquisitions - After tax Transaction and Integration Charges Recognized Upon Closing of Acquisition and Included Consolidated Statements of Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Total accounting charges	$ 17
TECO Energy [Member]
Business Acquisition [Line Items]
Legal and other consultants	0.5	$ 8
Bridge loan costs	0	3.3
Severance and relocation costs	1	2.8
Other costs and tax benefit	0.4	(5.5)
Total accounting charges	$ 1.9	$ 8.6

Quarterly Data - Schedule of Fi

Quarterly Data - Schedule of Financial Data by Quarter (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 676.1	$ 693.8	$ 680.6	$ 693	$ 695.5	$ 687.2	$ 605.7	$ 578	$ 2,743.5	$ 2,566.4	$ 2,355.1
Income from operations	126	146.6	143.3	146.2	112.1	145.7	132	115.6	562.1	505.4	454.6
Net income from continuing operations	51	64.9	61.5	63.8	27.4	73	57.6	48.4	241.2	206.4	188.7
Net income	$ 50.5	$ 53.2	$ 11.8	$ 58	$ 10.8	$ 11.1	$ 58.4	$ 50.1	$ 173.5	$ 130.4	$ 197.7
EPS—Basic
Earnings per share from continuing operations - Basic	$ 0.22	$ 0.28	$ 0.26	$ 0.27	$ 0.11	$ 0.32	$ 0.27	$ 0.22	$ 1.03	$ 0.92	$ 0.88
Net income	0.21	0.23	0.05	0.25	0.04	0.04	0.27	0.23	0.74	0.58	0.92
EPS—Diluted
Earnings per share from continuing operations - Diluted	0.22	0.28	0.26	0.27	0.11	0.32	0.27	0.22	1.03	0.92	0.88
Net income	0.21	0.23	0.05	0.25	0.04	0.04	0.27	0.23	0.74	0.58	0.92
Dividends paid per common share outstanding	$ 0.225	$ 0.225	$ 0.225	$ 0.225	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.90	$ 0.88	$ 0.88

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - TECO Finance [Member] - USD ($) $ in Millions	Feb. 26, 2016	Apr. 10, 2015
Subsequent Event [Line Items]
Debt instrument maturity date		May 31, 2015
One Year Term Loan Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 400
4.00% Notes due Mar. 15, 2016 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 250
Stated interest rate	4.00%
Debt instrument maturity date	Mar. 15, 2016

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Parties (Detail) - Tampa Electric Company [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Natural gas sales, net	$ 0.8	$ 0.3	$ 18.3
Administrative and general, net	69.4	22.5	$ 27.2
Accounts receivable	2.3	2.4
Accounts payable	15.9	9.7
Taxes receivable	61.3	43.3
Taxes payable	$ 1	$ 0

Schedule II - Valuation and 132

Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Allowance for Uncollectible Accounts
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 2.1		$ 4.7	$ 4.2
Charged to Income		2.7		1.4	3.3
Other Charges		0		0.7	0
Payments & Deductions	[1]	2.7		4.7	2.8
Balance at End of Period		2.1		2.1	4.7
Allowance for Uncollectible Accounts | Tampa Electric Company [Member]
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		1.4		2	1.5
Charged to Income		2.7		2.7	3.3
Other Charges		0		0	0
Payments & Deductions	[1]	2.6		3.3	2.8
Balance at End of Period		1.5		1.4	2
Deferred Tax Valuation Allowance
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		4.6		0	3
Charged to Income		1		4.6	0
Other Charges		0		0	0
Payments & Deductions		3.6	[2]	0	3	[2]
Balance at End of Period		$ 2		$ 4.6	$ 0
[1]	Write-off of individual bad debt accounts
[2]	Release of valuation allowance