TECO Energy Inactive 10-K27 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document Information [Line Items]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	350563
Current Fiscal Year End Date	-19
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		235,528,791
Entity Public Float			$3.97
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	96271
Current Fiscal Year End Date	-19
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 $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$25.40	$185.20
Receivables, less allowance for uncollectibles	299.8	287.2
Inventories, at average cost
Derivative assets	0	9.7
Regulatory assets	53.6	34.3
Deferred income taxes	72.8	100.3
Prepayments and other current assets	22.6	36.4
Assets held for sale	109.6	0
Total current assets	755.6	857.7
Property, plant and equipment
Construction work in progress	640	386.7
Other property	14.5	448.3
Property, plant and equipment, at original costs	9,733.90	9,077.30
Accumulated depreciation	-2,645.70	-2,907.20
Total property, plant and equipment, net	7,088.20	6,170.10
Other assets
Regulatory assets	348.5	293.1
Goodwill	408.3	0
Derivative assets	0	0.3
Deferred charges and other assets	65.8	126.8
Assets held for sale	59.8	0
Total other assets	882.4	420.2
Total assets	8,726.20	7,448
Current liabilities
Long-term debt due within one year	274.5	83.3
Notes payable	139	84
Accounts payable	288.6	261.7
Customer deposits	176.2	164.5
Regulatory liabilities	57	85.8
Derivative liabilities	36.6	0.1
Interest accrued	39.9	31.9
Taxes accrued	29.9	34.6
Other	16.8	19.5
Liabilities associated with assets held for sale	39.4	0
Total current liabilities	1,097.90	765.4
Other liabilities
Deferred income taxes	519.2	444
Investment tax credits	9	9.4
Regulatory liabilities	729	631.4
Derivative liabilities	6.1	0.2
Deferred credits and other liabilities	370.9	426.1
Liabilities associated with assets held for sale	65.4	0
Long-term debt, less amount due within one year	3,354	2,837.80
Total other liabilities	5,053.60	4,348.90
Commitments and Contingencies
Capital
Common equity	234.9	217.3
Additional paid in capital	1,875.90	1,581.30
Retained earnings	479.6	548.3
Accumulated other comprehensive loss	-15.7	-13.2
Total capital	2,574.70	2,333.70
Long-term debt, less amount due within one year	3,354	2,837.80
Total liabilities and capital	8,726.20	7,448
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	10.4	9.8
Receivables, less allowance for uncollectibles	227.2	227.6
Inventories, at average cost
Derivative assets	0	9.5
Regulatory assets	52.1	34.3
Deferred income taxes	24.8	29.4
Prepayments and other current assets	17.4	12.5
Total current assets	532.6	548.5
Taxes receivable from affiliate	43.3	54.9
Property, plant and equipment
Construction work in progress	624.2	385.3
Other property	8.6	8.3
Property, plant and equipment, at original costs	9,027.90	8,568.80
Accumulated depreciation	-2,633.80	-2,562.60
Total property, plant and equipment, net	6,402.70	6,014.50
Public Utilities, Property, Plant and Equipment, Net	6,394.10	6,006.20
Other assets
Regulatory assets	319.6	293.1
Derivative assets	0	0.3
Deferred charges and other assets	339	312.8
Unamortized debt expense	16.8	14.8
Other	2.6	4.6
Total assets	7,274.30	6,875.80
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	58	84
Accounts payable	242.3	226
Customer deposits	170.4	164.5
Regulatory liabilities	54.7	85.8
Derivative liabilities	36.6	0
Interest accrued	17	16.4
Taxes accrued	12.4	12.2
Other	10	12
Total current liabilities	684.7	684.2
Other liabilities
Deferred income taxes	1,209.10	1,114.30
Investment tax credits	9	9.4
Regulatory liabilities	623.4	631.4
Derivative liabilities	6.1	0.2
Long-term debt, less amount due within one year	2,013.80	1,797.50
Total other liabilities	2,146.70	2,063.40
Other	299.1	308.1
Commitments and Contingencies
Capital
Common equity	2,130.40	2,030.40
Retained earnings	305.8	308.1
Accumulated other comprehensive loss	-7.1	-7.8
Total capital	2,429.10	2,330.70
Long-term debt, less amount due within one year	2,013.80	1,797.50
Total capital	4,442.90	4,128.20
Total liabilities and capital	7,274.30	6,875.80
Fuel [Member]
Inventories, at average cost
Utility inventories	96.4	118.7
Fuel [Member] \| Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	85.2	93.7
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	75.4	85.9
Materials and Supplies [Member] \| Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	72.2	76.8
Electric [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	7,094.80	6,934
Electric [Member] \| Tampa Electric Company [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	7,094.80	6,934
Gas [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	1,984.60	1,308.30
Gas [Member] \| Tampa Electric Company [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	$1,308.90	$1,249.50

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Allowance for uncollectibles	$2.10	$4.70
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$1	$1
Common equity, shares outstanding	234,900,000	217,300,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$1.40	$2
Common equity, shares authorized	25,000,000	25,000,000
Common equity, shares outstanding	10	10

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Regulated electric and gas	$2,557.30	$2,342.50	$2,377.40
Unregulated	9.1	12.6	10.3
Total revenues	2,566.40	2,355.10	2,387.70
Expenses
Fuel	692.3	680.2	694.7
Purchased power	71.4	64.7	105.3
Cost of natural gas sold	209.7	142.2	155.7
Other	547.8	524.4	462.5
Operation and maintenance other expense	29.5	12.5	7.9
Depreciation and amortization	315.3	291.8	289.6
Taxes, other than income	195	184.7	185.7
Total expenses	2,061	1,900.50	1,901.40
Income from operations	505.4	454.6	486.3
Other income (expense)
Allowance for other funds used during construction	10.5	6.3	2.6
Other income	0.5	1.8	6.5
Loss on debt extinguishment	0	0	-1.2
Total other income	11	8.1	7.9
Interest charges
Interest expense	176.4	165	177.9
Allowance for borrowed funds used during construction	-5.3	-3.6	-1.5
Total interest charges	171.1	161.4	176.4
Income from continuing operations before provision for income taxes	345.3	301.3	317.8
Provision for income taxes	138.9	112.6	120.8
Net income from continuing operations	206.4	188.7	197
Discontinued operations
Income (loss) from discontinued operations	-125.4	5.2	55.4
Provision (benefit) for income taxes	-49.4	-3.8	39.4
Income (loss) from discontinued operations, net	-76	9	16
Less: Income from discontinued operations attributable to noncontrolling interest	0	0	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	-76	9	15.7
Net income attributable to TECO Energy	$130.40	$197.70	$212.70
Average common shares outstanding - Basic	223.1	215	214.3
Average common shares outstanding - Diluted	223.7	215.5	215
Earnings per share from continuing operations - Basic	$0.92	$0.88	$0.92
Earnings per share from continuing operations - Diluted	$0.92	$0.88	$0.92
Earnings per share from discontinued operations attributable to TECO Energy - Basic	($0.34)	$0.04	$0.07
Earnings per share from discontinued operations - Diluted	($0.34)	$0.04	$0.07
Earnings per share attributable to TECO Energy - Basic	$0.58	$0.92	$0.99
Earnings per share attributable to TECO Energy - Diluted	$0.58	$0.92	$0.99
Dividends paid per common share outstanding	$0.88	$0.88	$0.88

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net income attributable to TECO Energy	$130.40		$197.70		$212.70
Other comprehensive income (loss), net of tax
Net unrealized gains (losses) on cash flow hedges	0.7		1.4		-4.2
Amortization of unrecognized benefit costs and other	-3	[1]	14.8	[1]	-4.8	[1],[2]
Change in benefit obligation due to remeasurement	8		0		0
Increase in unrecognized postemployment costs	-8.2		0		0
Recognized benefit costs due to settlement	0		1.6		0
Other comprehensive income (loss), net of tax	-2.5		17.8		-9
Comprehensive income	$127.90		$215.50		$203.70

[1]	Related to postretirement and postemployment benefits. See Note 5 for additional information.
[2]	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
Consolidated Statements of Cash Flows (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income attributable to TECO Energy	$130,400,000	$197,700,000	$212,700,000
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	341,900,000	329,500,000	337,700,000
Deferred income taxes and investment tax credits	89,400,000	110,100,000	136,600,000
Allowance for other funds used during construction	-10,500,000	-6,300,000	-2,600,000
Non-cash stock compensation	12,700,000	13,500,000	12,000,000
(Gain) loss on sales of business/assets	-200,000	-1,600,000	18,500,000
Deferred recovery clauses	-15,200,000	-6,200,000	-8,900,000
Asset impairment	115,900,000	0	17,200,000
Receivables, less allowance for uncollectibles	-36,600,000	-4,500,000	37,700,000
Inventories	12,800,000	1,100,000	-2,400,000
Prepayments and other current assets	2,800,000	-2,200,000	-2,000,000
Taxes accrued	1,100,000	1,400,000	12,100,000
Interest accrued	7,300,000	-1,300,000	-5,900,000
Accounts payable	23,400,000	35,900,000	-1,300,000
Other	-10,400,000	-8,500,000	-4,700,000
Depreciation and amortization	315,300,000	291,800,000	289,600,000
Cash flows from operating activities	664,800,000	658,600,000	756,700,000
Cash flows from investing activities
Capital expenditures	-714,300,000	-532,400,000	-505,100,000
Allowance for other funds used during construction	10,500,000	6,300,000	2,600,000
Purchase of NMGI, net of cash acquired	-751,500,000	0	0
Net proceeds from sales of business/assets	200,000	4,300,000	194,400,000
Restricted cash	0	0	8,900,000
Other investments	-7,900,000	0	0
Cash flows used in investing activities	-1,463,000,000	-521,800,000	-299,200,000
Cash flows from financing activities
Dividends paid	-199,200,000	-191,200,000	-190,400,000
Proceeds from the sale of common stock	302,300,000	6,700,000	3,900,000
Proceeds from long-term debt issuance	563,600,000	0	538,100,000
Repayment of long-term debt/Purchase in lieu of redemption	-83,300,000	-51,600,000	-650,400,000
Change in short-term debt	55,000,000	84,000,000	0
Other financing activities	0	0	-2,200,000
Cash flows from/(used in) financing activities	638,400,000	-152,100,000	-301,000,000
Net (decrease) increase in cash and cash equivalents	-159,800,000	-15,300,000	156,500,000
Cash and cash equivalents at beginning of the year	185,200,000	200,500,000	44,000,000
Cash and cash equivalents at end of the year	25,400,000	185,200,000	200,500,000
Supplemental disclosure of cash flow information
Interest	161,300,000	161,000,000	188,400,000
Income taxes paid	2,900,000	1,800,000	7,200,000
Supplemental disclosure of non-cash activities
Debt assumed in NMGI acquisition	200,000,000	0	0
Change in accrued capital expenditures	13,300,000	4,700,000	-13,900,000
Tampa Electric Company [Member]
Cash flows from operating activities
Net income attributable to TECO Energy	260,300,000	225,600,000	227,200,000
Adjustments to reconcile net income to net cash from operating activities:
Deferred income taxes and investment tax credits	92,200,000	118,100,000	155,600,000
Allowance for other funds used during construction	-10,500,000	-6,300,000	-2,600,000
Deferred recovery clauses	-16,200,000	-6,200,000	-8,900,000
Receivables, less allowance for uncollectibles	400,000	-13,800,000	1,600,000
Inventories	13,100,000	-9,000,000	4,100,000
Taxes accrued	11,800,000	-34,300,000	-5,700,000
Interest accrued	600,000	-900,000	-8,300,000
Accounts payable	5,900,000	34,800,000	12,400,000
Other	-13,000,000	-2,800,000	4,000,000
Depreciation and amortization	302,600,000	290,300,000	288,200,000
Cash flows from operating activities	647,200,000	595,500,000	667,600,000
Cash flows from investing activities
Capital expenditures	-681,500,000	-507,600,000	-459,000,000
Allowance for other funds used during construction	10,500,000	6,300,000	2,600,000
Net proceeds from sale of assets	0	100,000	300,000
Cash flows used in investing activities	-671,000,000	-501,200,000	-456,100,000
Cash flows from financing activities
Dividends paid	-262,600,000	-222,100,000	-228,300,000
Proceeds from the sale of common stock	100,000,000	60,000,000	118,000,000
Proceeds from long-term debt issuance	296,300,000	0	538,100,000
Repayment of long-term debt/Purchase in lieu of redemption	-83,300,000	-51,600,000	-608,000,000
Change in short-term debt	-26,000,000	84,000,000	0
Cash flows from/(used in) financing activities	24,400,000	-129,700,000	-180,200,000
Net (decrease) increase in cash and cash equivalents	600,000	-35,400,000	31,300,000
Cash and cash equivalents at beginning of the year	9,800,000	45,200,000	13,900,000
Cash and cash equivalents at end of the year	10,400,000	9,800,000	45,200,000
Supplemental disclosure of cash flow information
Interest	102,500,000	102,400,000	128,100,000
Income taxes paid	52,600,000	56,400,000	-9,700,000
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$14,300,000	$4,700,000	($13,900,000)

Consolidated_Statements_of_Cap

Consolidated Statements of Capital (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Beginning Balance	$2,333.70	$2,291.80	$2,267.20
Net income	130.4	197.7	213
Other comprehensive loss, after tax	-2.5	17.8	-9
Common stock issued	300.8	5.9	-2.9
Cash dividends declared	-199.2	-191.2	-190.4
Stock compensation expense	12.7	13.5	12
Noncontrollingbdividends			-0.3
Tax benefitsbstock compensation			2.8
Restricted stockbdividends	1.2	1.1
Tax short fallbstock compensation	-2.4	-2.9
Noncontrollingbsale of business			-0.6
Ending Balance	2,574.70	2,333.70	2,291.80
Common Stock [Member]
Beginning Balance	217.3	216.6	215.8
Beginning Balance, shares	217,300,000	216,600,000	215,800,000
Common stock issued	17.6	0.7	0.8
Common stock issued, shares	17,600,000	700,000	800,000
Ending Balance	234.9	217.3	216.6
Ending Balance, shares	234,900,000	217,300,000	216,600,000
Additional Paid-in Capital [Member]
Beginning Balance	1,581.30	1,564.50	1,553.40
Common stock issued	283.2	5.2	-3.7
Stock compensation expense	12.7	13.5	12
Tax benefitsbstock compensation			2.8
Restricted stockbdividends	1.1	1
Tax short fallbstock compensation	-2.4	-2.9
Ending Balance	1,875.90	1,581.30	1,564.50
Retained Earnings [Member]
Beginning Balance	548.3	541.7	519.4
Net income	130.4	197.7	212.7
Cash dividends declared	-199.2	-191.2	-190.4
Restricted stockbdividends	0.1	0.1
Ending Balance	479.6	548.3	541.7
Accumulated Other Comprehensive Income (Loss) [Member]
Beginning Balance	-13.2	-31	-22
Other comprehensive loss, after tax	-2.5	17.8	-9
Ending Balance	-15.7	-13.2	-31
Noncontrolling Interest [Member]
Beginning Balance			0.6
Net income			0.3
Noncontrollingbdividends			-0.3
Noncontrollingbsale of business			-0.6
Ending Balance	$0	$0	$0

Consolidated_Statements_of_Inc1

Consolidated Statements of Income and Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Total revenues	$2,566.40	$2,355.10	$2,387.70
Expenses
Fuel	692.3	680.2	694.7
Purchased power	71.4	64.7	105.3
Cost of natural gas sold	209.7	142.2	155.7
Other	547.8	524.4	462.5
Depreciation and amortization	315.3	291.8	289.6
Taxes, other than income	195	184.7	185.7
Total expenses	2,061	1,900.50	1,901.40
Income from operations	505.4	454.6	486.3
Other income (expense)
Allowance for other funds used during construction	10.5	6.3	2.6
Total other income	11	8.1	7.9
Interest charges
Interest on long-term debt	176.4	165	177.9
Allowance for borrowed funds used during construction	-5.3	-3.6	-1.5
Total interest charges	171.1	161.4	176.4
Income from continuing operations before provision for income taxes	345.3	301.3	317.8
Provision for income taxes	138.9	112.6	120.8
Net income attributable to TECO Energy	130.4	197.7	212.7
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges	0.7	1.4	-4.2
Other comprehensive income (loss), net of tax	-2.5	17.8	-9
Comprehensive income	127.9	215.5	203.7
Tampa Electric Company [Member]
Revenues
Electric	2,020.50	1,950.10	1,981
Gas	398.5	392.7	397
Total revenues	2,419	2,342.80	2,378
Expenses
Fuel	692.3	680.2	694.7
Purchased power	71.4	64.7	105.3
Cost of natural gas sold	137	142.6	155.8
Other	518.4	523.6	462
Depreciation and amortization	302.6	290.3	288.2
Taxes, other than income	189.8	183.1	184
Total expenses	1,911.50	1,884.50	1,890
Income from operations	507.5	458.3	488
Other income (expense)
Allowance for other funds used during construction	10.5	6.3	2.6
Other income, net	4.8	5.1	4.1
Total other income	15.3	11.4	6.7
Interest charges
Interest on long-term debt	107.5	105	119.6
Other interest	4.2	3.9	7.7
Allowance for borrowed funds used during construction	-5.1	-3.6	-1.5
Total interest charges	106.6	105.3	125.8
Income from continuing operations before provision for income taxes	416.2	364.4	368.9
Provision for income taxes	155.9	138.8	141.7
Net income attributable to TECO Energy	260.3	225.6	227.2
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges	0.7	0.9	-4.1
Other comprehensive income (loss), net of tax	0.7	0.9	-4.1
Comprehensive income	$261	$226.50	$223.10

Consolidated_Statements_of_Ret

Consolidated Statements of Retained Earnings (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Beginning Balance	$548.30
Add: Net income	130.4	197.7	212.7
Deduct: Cash dividends on capital stockbcommon	199.2	191.2	190.4
Ending Balance	479.6	548.3
Tampa Electric Company [Member]
Beginning Balance	308.1	304.6	305.7
Add: Net income	260.3	225.6	227.2
Retained Earning, Gross	568.4	530.2	532.9
Deduct: Cash dividends on capital stockbcommon	262.6	222.1	228.3
Ending Balance	$305.80	$308.10	$304.60

Consolidated_Statements_of_Cap1

Consolidated Statements of Capitalization - Capital Stock (Detail) (USD $)	3 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
Common equity, shares authorized	400,000,000	400,000,000	400,000,000	400,000,000
Capital Stock Outstanding December 31, Shares	234,900,000	217,300,000	234,900,000	217,300,000
Cash Dividends Paid Per Share	$0.22	$0.22	$0.88	$0.88
Cash Dividends Paid			$199.20	$191.20
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	2,130.40	2,030.40	2,130.40	2,030.40
Cash Dividends Paid			$262.60	$222.10

Consolidated_Statements_of_Cap2

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Preferred stock - par value	$1
Equity contributions made by TECO Energy	$100	$60
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_Cap3

Consolidated Statements of Capitalization - Long-Term Debt (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt, total	$3,610.50	$2,923.80
Long-term debt, carrying amount	3,628.50	2,921.10
Unamortized debt discount, net	18	-2.7
Less amount due within one year	274.5	83.3
Total long-term debt	3,354	2,837.80
Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,097.10	1,880.80
Long-term debt, carrying amount	2,099.30	1,882.60
Total long-term debt	2,013.80	1,797.50
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,857.60	1,650.90
Less amount due within one year	83.3	83.3
Total long-term debt	2,013.80	1,797.50
Tampa Electric Company [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,857.60	1,650.90
Unamortized debt discount, net	-2.2	-1.8
Less amount due within one year	83.3	83.3
Long-term debt, fair value	2,372.20	2,042
Tampa Electric Company [Member] \| Long-Term Debt [Member] \| Carrying Amount [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	2,097.10	1,880.80
Tampa Electric Company [Member] \| 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] \| 5.65% Refunding bonds [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] \| Variable rate bonds repurchased in 2008 Due To 2020 [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	0	0
Tampa Electric Company [Member] \| Variable rate bonds repurchased in 2008 Due To 2020 [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 5.15% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 5.15% Refunding bonds [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 1.5% term rate bonds repurchased in 2011 [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 5.0% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 5.0% Refunding bonds [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
Tampa Electric Company [Member] \| 6.25% Notes [Member]
Debt Instrument [Line Items]
Maturity range end	2016
Maturity range start	2014
Long-term debt, total	166.7	250
Tampa Electric Company [Member] \| 6.25% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Maturity range end	2016
Maturity range start	2014
Long-term debt, total	166.7	250
Tampa Electric Company [Member] \| 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	200	200
Tampa Electric Company [Member] \| 6.10% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	200	200
Tampa Electric Company [Member] \| 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] \| 5.40% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] \| 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225	225
Tampa Electric Company [Member] \| 2.60% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225	225
Tampa Electric Company [Member] \| 6.55% Notes [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250	250
Tampa Electric Company [Member] \| 6.55% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250	250
Tampa Electric Company [Member] \| 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190	190
Tampa Electric Company [Member] \| 6.15% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190	190
Tampa Electric Company [Member] \| 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	250	250
Tampa Electric Company [Member] \| 4.10% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	250	250
Tampa Electric Company [Member] \| 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	290	0
Tampa Electric Company [Member] \| 4.35% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	290	0
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	241.7	231.7
PGS [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	241.7	231.7
PGS [Member] \| 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	50	50
PGS [Member] \| 6.10% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	50	50
PGS [Member] \| 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	46.7	46.7
PGS [Member] \| 5.40% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	46.7	46.7
PGS [Member] \| 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	25	25
PGS [Member] \| 2.60% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	25	25
PGS [Member] \| 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	60	60
PGS [Member] \| 6.15% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	60	60
PGS [Member] \| 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	50	50
PGS [Member] \| 4.10% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	50	50
PGS [Member] \| 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	10	0
PGS [Member] \| 4.35% Notes [Member] \| Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$10	$0

Consolidated_Statements_of_Cap4

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) (Detail) (USD $)	Dec. 31, 2014	Mar. 31, 2008	Mar. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2008	Mar. 31, 2012
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%
Tampa Electric [Member] \| 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Stated interest rate	1.50%
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%
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] \| 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
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%
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%
Tampa Electric Company [Member] \| Variable rate bonds repurchased in 2008 Due To 2020 [Member]
Debt Instrument [Line Items]
Variable rate bonds, par amounts		$20
Tampa Electric Company [Member] \| Variable Rate Bonds [Member]
Debt Instrument [Line Items]
Variable rate bonds, par amounts			$86

Consolidated_Statements_of_Cap5

Consolidated Statements of Capitalization - Long-term Debt Maturities (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term debt maturities	$3,610.50
Tampa Electric Company [Member]
Debt Instrument [Line Items]
2015	83.3
2016	83.4
2017	0
2018	254.2
2019	0
Thereafter	1,436.70
Total long-term debt maturities	1,857.60
PGS [Member]
Debt Instrument [Line Items]
2015	0
2016	0
2017	0
2018	50
2019	0
Thereafter	191.7
Total long-term debt maturities	241.7
Long Term Debt Maturities
Debt Instrument [Line Items]
2015	83.3
2016	83.4
2017	0
2018	304.2
2019	0
Thereafter	1,628.40
Total long-term debt maturities	$2,099.30

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 subsidiaries, NMGI and TECO Diversified, owns NMGC and TECO Coal, respectively.
	TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida.
	NMGC, a Delaware corporation and wholly owned subsidiary of NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico.
	TECO Coal, a Kentucky LLC, has 10 subsidiaries located in Eastern Kentucky, Tennessee and Virginia. These entities own mineral rights, own or operate surface and underground mines and own interests in coal processing and loading facilities. On Oct. 17, 2014, TECO Diversified entered into an agreement to sell all of its ownership interest in TECO Coal. On Feb. 5, 2015, the agreement was amended to extend the closing date to Mar. 13, 2015.
	The significant accounting policies for both utility and diversified operations 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 as of the acquisition date of Sept. 2, 2014 (see Note 21). In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at TECO Energy that are directly related to TECO Coal (see Note 19).
	For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority 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).
	Use of Estimates
	The use of estimates is inherent in the preparation of financial statements in accordance with 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.
	Planned Major Maintenance
	Tampa Electric, PGS and NMGC expense major maintenance costs as incurred. For electric and gas utilities, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC, FPSC and NMPRC, as applicable.
	Planned major maintenance projects at TECO Coal that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.
	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 (including NMGC from the acquisition date), expressed as a percentage of the original cost of depreciable property, was 3.6% for 2014, 3.7% for 2013 and 3.8% for 2012.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC 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		5 - 40 years

	Office equipment and furniture		3 - 30 years

	Vehicles and other equipment		2 - 15 years

	Computer software		2 - 15 years
	Total depreciation expense for the years ended Dec. 31, 2014, 2013 and 2012 was $307.5 million, $285.6 million and $276.3 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 2014 was 4.92%. Total AFUDC for the years ended Dec. 31, 2014, 2013 and 2012 was $15.8 million, $9.9 million and $4.1 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. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory is classified within Assets held for sale at Dec. 31, 2014.

	Fuel Inventory		Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Tampa Electric		$	85.2	$	93.7
	TECO Coal			0		25
	NMGC			11.2		0
	Total		$	96.4	$	118.7
	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 for additional details).
	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 for additional details).
	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 for further detail.
	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 for further detail.
	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 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer. They are included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.
	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, 2014, 2013 and 2012, total costs of $4.3 million, $23.1 million and $13.8 million, respectively, consisting primarily of natural gas purchased, were netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income.
	Shipping and Handling
	TECO Coal incurred costs to ship product to customers of $5.2 million, $8.2 million and $9.0 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The costs are included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.
	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.
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, gas storage, interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2014 and 2013, unbilled revenues of $86.6 million and $46.7 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $71.4 million, $64.7 million and $105.3 million, for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts
TECO Coal incurs most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.
Tampa Electric and PGS are allowed to recover certain costs on a dollar-per-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 $113.9 million, $108.5 million and $111.5 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes, and they are 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.
Deferred Charges and Other Assets
Deferred charges and other assets consist primarily of offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense, as well as mining development costs amortized on a per ton basis in 2013 and assets related to NMGC’s ROW in 2014. The mining development costs were impaired in 2014. See Notes 20 and 21 for additional information on the impairment and ROW, respectively.
Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet 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.
Deferred Credits and Other Liabilities
Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2014 and 2013 ranged from 2.71% to 3.86% and 3.51% to 4.86%, respectively.
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, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.
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 consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.

Tampa Electric Company [Member]
Significant Accounting Policies	1. Significant Accounting Policies
	TEC has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. TEC’s significant accounting policies are as follows:
	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 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.
	TEC’s retail and wholesale businesses are regulated by the FPSC and related 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 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 minority 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).
	Planned Major Maintenance
	Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
	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.
	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 2014, 3.7% for 2013 and 3.8% for 2012. 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, 2014, 2013 and 2012 was $295.8 million, $284.2 million and $275.1 million, respectively.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC 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.
	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.
	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, 2014, 2013 and 2012 was $15.6 million, $9.9 million and $4.1 million, respectively.
	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.
	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.
	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 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	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). As of Dec. 31, 2014 and 2013, unbilled revenues of $49.3 million and $46.7 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $71.4 million, $64.7 million and $105.3 million, for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.
	Accounting for Excise Taxes, Franchise Fees and Gross Receipts
	TEC is allowed to recover certain costs on a dollar-per-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 $113.9 million, $108.5 million and $111.5 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

New_Accounting_Pronouncements

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2014
New Accounting Pronouncements	2. New Accounting Pronouncements
	Extraordinary and Unusual Items
	In January 2015, the FASB issued guidance to remove the concept of extraordinary items from U.S. GAAP. Therefore, events or transactions that are of an unusual nature and occur infrequently will no longer be allowed to be separately disclosed, net of tax, in the income statement after income from continuing operations. The standard is effective for the company beginning Jan. 1, 2016. The company does not expect a significant impact from the adoption of this guidance.
	Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
	In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations. Under this new guidance, which is intended to enhance convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective prospectively for the company beginning in 2015.
	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. This guidance is effective for the company beginning in 2017 and allows for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.
	Going Concern
	In August 2014, the FASB issued guidance defining management’s responsibility to decide whether there is substantial doubt about an organization’s ability to continue as a going concern and the related footnote disclosures required. This guidance is effective prospectively for the company beginning in 2017. The company does not expect any significant impact from the adoption of this guidance on its financial statements.
Tampa Electric Company [Member]
New Accounting Pronouncements	2. New Accounting Pronouncements
	Extraordinary and Unusual Items
	In January 2015, the FASB issued guidance to remove the concept of extraordinary items from U.S. GAAP. Therefore, events or transactions that are of an unusual nature and occur infrequently will no longer be allowed to be separately disclosed, net of tax, in the income statement after income from continuing operations. The standard is effective for the company beginning Jan. 1, 2016. TEC does not expect a significant impact from the adoption of this guidance.
	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. This guidance is effective for the company beginning in 2017 and allows for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.
	Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
	In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations. Under the new guidance, which is intended to enhance convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for TEC beginning in 2015.
	Going Concern
	In August 2014, the FASB issued guidance defining management’s responsibility to decide whether there is substantial doubt about an organization’s ability to continue as a going concern and the related footnote disclosures required. This guidance is effective for TEC beginning in 2017. TEC does not expect any significant impact from the adoption of this guidance on its financial statements.

Regulatory

Regulatory	12 Months Ended
Regulatory	Dec. 31, 2014
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 under PUHCA 2005. 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 and all of 2012 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 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between TEC 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 TEC’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 TEC could seek a review of Tampa Electric’s 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. Effective Nov. 1, 2013, Tampa Electric ceased accruing $8.0 million annually to the FERC-authorized and FPSC-approved self-insured storm damage reserve.
	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 FERC-authorized and 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, 2014 and 2013.
	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; and 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.
	Details of the regulatory assets and liabilities as of Dec. 31, 2014 and 2013 are presented in the following table:

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Regulatory assets:
	Regulatory tax asset (1)		$	69.2	$	67.4
	Other:
	Cost-recovery clauses			45.1		6.1
	Postretirement benefit asset (2)			194		182.7
	Deferred bond refinancing costs (3)			7.2		8
	Debt basis adjustment (3)			20.9		0
	Environmental remediation			53.1		51.4
	Competitive rate adjustment			2.8		4.1
	Other			9.8		7.7
	Total other regulatory assets			332.9		260
	Total regulatory assets			402.1		327.4
	Less: Current portion			53.6		34.3
	Long-term regulatory assets		$	348.5	$	293.1
	Regulatory liabilities:
	Regulatory tax liability (1)		$	6.9	$	9.8
	Other:
	Cost-recovery clauses			25.9		54.5
	Transmission and delivery storm reserve			56.1		56.1
	Deferred gain on property sales (4)			0.8		2
	Accumulated reserve—cost of removal			695.2		594
	Other			1.1		0.8
	Total other regulatory liabilities			779.1		707.4
	Total regulatory liabilities			786		717.2
	Less: Current portion			57		85.8
	Long-term regulatory liabilities		$	729	$	631.4
	-1	Primarily related to plant life and derivative positions.
	-2	Amortized over the remaining service life of plan participants.
	-3	Amortized over the term of the related debt instruments.
	-4	Amortized over a 5-year period with various ending dates.
	All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:

	Regulatory assets

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Clause recoverable (1)		$	47.9	$	10.2
	Components of rate base (2)			199		185.6
	Regulatory tax assets (3)			69.2		67.4
	Capital structure and other (3)			86		64.2
	Total		$	402.1	$	327.4
	-1	To be recovered through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year.
	-2	Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
	-3	“Regulatory tax assets” and “Capital structure and other” regulatory assets, including environmental remediation, have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.
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 under PUHCA 2005. 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 and 2012, 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 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between TEC 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 TEC’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 TEC could seek a review of Tampa Electric’s 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. Effective Nov. 1, 2013, Tampa Electric ceased accruing $8.0 million annually to the FERC-authorized and FPSC-approved self-insured storm damage reserve.
	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 FERC-authorized and 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, 2014 and 2013.
	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; and 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.
	Details of the regulatory assets and liabilities as of Dec. 31, 2014 and 2013 are presented in the following table:
	Regulatory Assets and Liabilities

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Regulatory assets:
	Regulatory tax asset (1)		$	69.2	$	67.4
	Other:
	Cost-recovery clauses			43.6		6.1
	Postretirement benefit asset (2)			187.8		182.7
	Deferred bond refinancing costs (3)			7.2		8
	Environmental remediation			53.1		51.4
	Competitive rate adjustment			2.8		4.1
	Other			8		7.7
	Total other regulatory assets			302.5		260
	Total regulatory assets			371.7		327.4
	Less: Current portion			52.1		34.3
	Long-term regulatory assets		$	319.6	$	293.1
	Regulatory liabilities:
	Regulatory tax liability (1)		$	5.1	$	9.8
	Other:
	Cost-recovery clauses			23.5		54.5
	Transmission and delivery storm reserve			56.1		56.1
	Deferred gain on property sales (4)			0.8		2
	Provision for stipulation and other			1.1		0.8
	Accumulated reserve - cost of removal			591.5		594
	Total other regulatory liabilities			673		707.4
	Total regulatory liabilities			678.1		717.2
	Less: Current portion			54.7		85.8
	Long-term regulatory liabilities		$	623.4	$	631.4
	-1	Primarily related to plant life and derivative positions.
	-2	Amortized over the remaining service life of plan participants.
	-3	Amortized over the term of the related debt instruments.
	-4	Amortized over a 5-year period with various ending dates.
	All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:
	Regulatory assets

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Clause recoverable (1)		$	46.4	$	10.2
	Components of rate base (2)			191		185.6
	Regulatory tax assets (3)			69.2		67.4
	Capital structure and other (3)			65.1		64.2
	Total		$	371.7	$	327.4
	-1	To be recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year.
	-2	Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
	-3	“Regulatory tax assets” and “Capital structure and other” regulatory assets, including environmental remediation, have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

Income_Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2014
Income Taxes	4. Income Taxes
	Income Tax Expense
	In 2014, 2013 and 2012, TECO Energy recorded net tax provisions from continuing operations of $138.9 million, $112.6 million and $120.8 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, foreign income taxes and prior year audits in 2014, 2013 and 2012 were $2.9 million, $1.8 million and $7.2 million, respectively.
	Income tax expense consists of the following:
	Income Tax Expense (Benefit)

	(millions)
	For the year ended Dec. 31,		2014				2013				2012
	Continuing Operations
	Current income taxes
	Federal		$	0.5			$	2.2			$	15.7
	State			0				0				0
	Deferred income taxes
	Federal			111				98.8				89.2
	State			27.7				11.9				16.2
	Amortization of investment tax credits			(0.3	)			(0.3	)			(0.3	)
	Income tax expense from continuing operations			138.9				112.6				120.8
	Discontinued Operations
	Current income taxes
	Federal			0				0				0
	Foreign			0				0				6.8
	State			(0.4	)			(3.5	)			1.1
	Deferred income taxes
	Federal			(44.0	)			(0.3	)			28.6
	Foreign			0				0				0
	State			(5.0	)			0				2.9
	Income tax expense from discontinued operations			(49.4	)			(3.8	)			39.4
	Total income tax expense		$	89.5			$	108.8			$	160.2
	During 2014 and 2013, TECO Energy increased its net operating loss carryforward. Total current income tax expense for the year ended Dec. 31, 2012 was reduced by $13.6 million to reflect the benefits of operating loss carryforwards.
	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,		2014				2013				2012
	Income tax expense at the federal statutory rate of 35%		$	120.9			$	105.5			$	111.2
	Increase (decrease) due to:
	State income tax, net of federal income tax			17				7.5				10.4
	Valuation allowance			0.9				0				1.1
	Other			0.1				(0.4	)			(1.9	)
	Total income tax expense from continuing operations		$	138.9			$	112.6			$	120.8
	Income tax expense as a percent of income from continuing operations,			40.2	%			37.4	%			38	%
	before income taxes			40.2	%			37.4	%			38	%
	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 2014, the effective tax rate also increased by 1.9% as a result of a state consolidated tax adjustment.
	As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2014 will be realized in future periods.
	Deferred Income Taxes
	The major components of the company’s deferred tax assets and liabilities recognized are as follows:

	(millions)
	As of Dec. 31,		2014				2013
	Deferred tax liabilities (1)
	Property related		$	1,391.30			$	1,164.20
	Pension			62.3				52.8
	Total deferred tax liabilities			1,453.60				1,217.00
	Deferred tax assets (1)
	Alternative minimum tax credit carryforward			214				213
	Loss and credit carryforwards (2)			566.7				479.8
	Other postretirement benefits			71.5				68.9
	Other			159.6				111.6
	Total deferred tax assets			1,011.80				873.3
	Valuation allowance (3)			(4.6	)			0
	Total deferred tax assets, net of valuation allowance			1,007.20				873.3
	Total deferred tax liability, net			446.4				343.7
	Less: Current portion of deferred tax asset			(72.8	)			(100.3	)
	Long-term portion of deferred tax liability, net		$	519.2			$	444
-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, 2014 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 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	$3.6 million related to discontinued operations.
At Dec. 31, 2014, the company had cumulative unused federal, Florida, New Mexico and Kentucky NOLs for income tax purposes of $1,543.7 million, $562.4 million, $56.0 million, and $18.4 million, respectively, expiring at various times between 2025 and 2033. The federal NOL includes $110.4 million of acquired NOLs due to the acquisition of NMGI. In addition, the company has unused general business credits of $4.0 million expiring between 2026 and 2033. During 2014, the company’s available AMT credit carryforward increased from $213.0 million to $214.0 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. During 2014, the company recorded a $4.6 million valuation allowance for state NOL carryforwards and state deferred tax assets, net of federal tax. The valuation allowance includes $3.6 million related to TECO Coal discontinued operations.
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)		2014				2013				2012
Balance at Jan. 1,		$	0			$	2.9			$	4.1
Decreases due to expiration of statute of limitations			0				(2.9	)			0
Dispositions			0				0				(1.2	)
Balance at Dec. 31		$	0			$	0				2.9
The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense – Other” in the Consolidated Statements of Income. In 2014, 2013 and 2012, the company recognized $0.0 million, $(0.9) million and $0.3 million, respectively, of pretax charges (benefits) for interest only. Additionally, the company had $0.0 million of interest accrued at Dec. 31, 2014 and 2013. No amounts have been recorded for penalties.
The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2011 and forward. Years 2014 and 2015 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,		2014				2013				2012
	Current income taxes
	Federal		$	54.8			$	19.4			$	(19.5	)
	State			8.9				1.3				5.6
	Deferred income taxes
	Federal			79				99.8				141.2
	State			13.5				18.6				14.7
	Amortization of investment tax credits			(0.3	)			(0.3	)			(0.3	)
	Total income tax expense		$	155.9			$	138.8			$	141.7
	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,		2014				2013				2012
	Income tax expense at the federal statutory rate of 35%		$	145.7			$	127.5			$	129.1
	Increase (decrease) due to
	State income tax, net of federal income tax			14.5				13				13.2
	Other			(4.3	)			(1.7	)			(0.6	)
	Total income tax expense on consolidated statements of income		$	155.9			$	138.8			$	141.7
	Income tax expense as a percent of income from continuing operations,			37.5	%			38.1	%			38.4	%
	before income taxes			37.5	%			38.1	%			38.4	%
	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,		2014				2013
	Deferred tax liabilities (1)
	Property related		$	1,328.80			$	1,166.40
	Pension and postretirement benefits			72.5				70.5
	Pension			51.8				43.2
	Total deferred tax liabilities			1,453.10				1,280.10
	Deferred tax assets (1)
	Loss and credit carryforwards			77.7				4.8
	Medical benefits			51				50.9
	Insurance reserves			29				29.1
	Pension and postretirement benefits			72.5				70.5
	Capitalized energy conservation assistance costs			20.3				19.6
	Other			18.3				20.3
	Total deferred tax assets			268.8				195.2
	Total deferred tax liability, net			1,184.30				1,084.90
	Less: Current portion of deferred tax asset			(24.8	)			(29.4	)
	Long-term portion of deferred tax liability, net		$	1,209.10			$	1,114.30
	-1	Certain property related assets and liabilities have been netted.
	At Dec. 31, 2014, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $194.1 million and $268.5 million, respectively, expiring in 2033.
	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, 2014 and 2013, TEC did not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2015. As of Dec. 31, 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 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2011 and onward. Years 2014 and 2015 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_Benefi

Employee Postretirement Benefits	12 Months Ended
Employee Postretirement Benefits	Dec. 31, 2014
Employee Postretirement Benefits	5. Employee Postretirement Benefits
	Pension Benefits
	TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.
	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.
	The qualified pension plan’s actuarial value of assets, including credit balance, was 110.8% of the Pension Protection Act funded target as of Jan. 1, 2014 and is estimated at 115.9% of the Pension Protection Act funded target as of Jan. 1, 2015.
	Amounts disclosed for pension benefits in the following tables and discussion also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. TECO Coal participants will cease earning pension benefits upon the anticipated sale. As a result, a curtailment loss was recognized in the fourth quarter of 2014. See curtailment-related line items in tables below.
	A curtailment loss in the Retirement Plan was recognized in the fourth quarter of 2014 in anticipation of the sale of TECO Coal. 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 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 Funded status 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. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in the Consolidated Balance Sheets for 2014 and 2013.

	Obligations and Funded Status		Pension Benefits								Other Benefits
	(millions)		2014				2013				2014				2013
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	666			$	715			$	208.1			$	230.3
	Service cost			18.3				18.2				2.5				2.5
	Interest cost			32				28.9				10.8				9.3
	Plan participants’ contributions			0				0				2.8				2.9
	Plan amendments			0				0				(23.2	)			0
	Actuarial loss (gain)			48.3				(50.4	)			1.5				(22.1	)
	Gross benefits paid			(39.9	)			(43.1	)			(16.0	)			(15.0	)
	Transfer in due to the effect of business combination			0				0				26.7				0
	Plan curtailment			4				0				(11.7	)			0
	Special termination benefit			0.2				0				0				0
	Settlements			0				(2.6	)			0				0
	Federal subsidy on benefits paid		n/a				n/a					0				0.2
	Net benefit obligation at end of year		$	728.9			$	666			$	201.5			$	208.1

	Change in plan assets
	Fair value of plan assets at beginning of year		$	593			$	529.1			$	0			$	0
	Actual return on plan assets			46.4				63.7				0.1				0
	Employer contributions			47.5				44.6				(1.0	)			11.9
	Employer direct benefit payments			1				1.3				16
	Plan participants’ contributions			0				0				2.8				2.9
	Transfer in due to acquisition			0				0				16.9				0
	Settlements			0				(2.6	)			0				0
	Net benefits paid			(39.9	)			(43.1	)			(16.0	)			(14.8	)
	Fair value of plan assets at end of year		$	648			$	593			$	18.8			$	0

	Funded status
	Fair value of plan assets (1)		$	648			$	593			$	18.8			$	0
	Less: Benefit obligation (PBO/APBO)			728.9				666				201.5				208.1
	Funded status at end of year			(80.9	)			(73.0	)			(182.7	)			(208.1	)
	Unrecognized costs in regulated asset acquired in business combination			0				0				6.4				0
	Unrecognized net actuarial loss			203.7				173.1				9.6				19.7
	Unrecognized prior service (benefit) cost			0				(0.4	)			(24.0	)			(0.7	)
	Net amount required to be recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

	Amounts recognized in balance sheet
	Regulatory assets		$	167.4			$	139.6			$	26.6			$	43.2
	Accrued benefit costs and other current liabilities			(4.9	)			(3.3	)			(10.7	)			(13.3	)
	Deferred credits and other liabilities			(76.0	)			(69.7	)			(172.0	)			(194.8	)
	Accumulated other comprehensive loss (income), pretax			36.3				33.1				(34.6	)			(24.2	)
	Net amount recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)
	-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.
Amounts recognized in accumulated other comprehensive income, pretax

		Pension Benefits								Other Benefits
(millions)		2014				2013				2014				2013
Net actuarial loss (gain)		$	36			$	32.7			$	(30.1	)		$	(23.8	)
Prior service cost (credit)			0.3				0.4				(4.5	)			(0.4	)
Amount recognized, pretax		$	36.3			$	33.1			$	(34.6	)		$	(24.2	)
The accumulated benefit obligation for all defined benefit pension plans was $685.0 million at Dec. 31, 2014 and $624.1 million at Dec. 31, 2013. The projected benefit obligation for the other postretirement benefits plan was $201.5 million at Dec. 31, 2014 and $208.1 million at Dec. 31, 2013.
Assumptions used to determine benefit obligations at Dec. 31:

		Pension Benefits								Other Benefits
		2014				2013				2014				2013
Discount rate			4.258	%			5.118	%			4.211	%			5.096	%
Rate of compensation increase—weighted			3.87	%			3.73	%			3.86	%			3.71	%
Healthcare cost trend rate
Immediate rate		n/a				n/a					7.09	%			7.25	%
Ultimate rate		n/a				n/a					4.57	%			4.5	%
Year rate reaches ultimate		n/a				n/a				2025				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		$	7			$	(6.4	)
The discount rate assumption used to determine the Dec. 31, 2014 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
		2014				2013				2012				2014				2013			2012

Service cost		$	18.3			$	18.2			$	17			$	2.5			$	2.5		$	2.4
Interest cost			32				28.9				30.1				10.8				9.3			10.1
Expected return on plan assets			(41.8	)			(38.4	)			(37.1	)			(0.3	)			0			0
Amortization of:
Actuarial loss			13.5				20.5				15.3				0.2				1			0.1
Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)			(0.2	)			(0.4	)		0.8
Transition obligation			0				0				0				0				0			1.8
Curtailment loss (gain)			3.9				0				0				(0.2	)			0			0
Special termination benefit			0.2				0				0				0				0			0
Settlement loss			0				1				0				0				0			0
Net periodic benefit cost		$	25.7			$	29.8			$	24.9			$	12.8			$	12.4		$	15.2

Prior service cost		$	0			$	0			$	0			$	(23.6	)		$	0		$	(5.2	)
Net loss (gain)			44.1				(75.7	)			34				(9.9	)			(15.6	)	16.3
Unrecognized costs in regulated asset acquired in business combination			0				0				0				6.4				0			0
Amortization of:
Actuarial gain (loss)			(13.5	)			(21.5	)			(15.3	)			(0.2	)			(1.0	)		(0.1	)
Prior service (benefit) cost		0.4					0.4				0.4				0.2				0.3			(0.8	)
Transition obligation			0				0				0				0				0			(1.8	)
Total recognized in OCI and regulatory assets		$	31			$	(96.8	)		$	19.1			$	(27.1	)		$	(16.3	)	$	8.4
Total recognized in net periodic benefit cost, OCI and regulatory assets		$	56.7			$	(67.0	)		$	44			$	(14.3	)		$	(3.9	)	$	23.6

A curtailment loss and special termination benefits were recognized for the Retirement Plan due to the expected sale of TECO Coal. 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 credit for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $3.3 million and $0.3 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 and prior service credit for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $10.0 million and $0.1 million, respectively. There will be no net loss and 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. 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
		2014 (a)				2013				2012				2014				2013			2012
Discount rate		5.118%/4.277%/4.331%					4.196	%			4.797	%			5.096	%			4.18	%		4.744	%
Expected long-term return on plan assets		7.25%/7.00%/7.00%					7.5	%			7.5	%			5.75			n/a			n/a
Rate of compensation increase			3.73	%			3.76	%			3.83	%			3.71	%			3.74	%		3.82	%
Healthcare cost trend rate
Initial rate		n/a				n/a				n/a					7.25	%			7.5	%		7.75	%
Ultimate rate		n/a				n/a				n/a					4.5	%			4.5	%		4.5	%
Year rate reaches ultimate		n/a				n/a				n/a				2025				2025			2025
(a)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 2014 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, 2014, TECO Energy’s pension plan experienced actual asset returns of approximately 7.9%.
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			$	(0.4	)
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						2014				2013
Equity securities		48%-54%					50	%			54	%
Fixed income securities		46%-52%					50	%			46	%
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). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.
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, 2014 and Dec. 31, 2013.

(millions)		At Fair Value as of Dec. 31, 2014
		Level 1				Level 2				Level 3				Total
Cash		$	0.4			$	0			$	0			$	0.4
Accounts receivable			1.4				0				0				1.4
Accounts payable			(5.3	)			0				0				(5.3	)
Cash equivalents
Short term investment funds (STIFs)			7.6				0				0				7.6
Treasury bills (T bills)			0				0.2				0				0.2
Discounted notes			0				8.8				0				8.8
Total cash equivalents			7.6				9				0				16.6
Equity securities
Common stocks			98				0				0				98
American depository receipts (ADRs)			1.3				0				0				1.3
Real estate investment trusts (REITs)			2.5				0				0				2.5
Preferred stock			0.8				0				0				0.8
Mutual funds			171.3				0				0				171.3
Commingled fund			0				45.6				0				45.6
Total equity securities			273.9				45.6				0				319.5
Fixed income securities
Municipal bonds			0				6.1				0				6.1
Government bonds			0				47.9				0				47.9
Corporate bonds			0				22				0				22
Asset backed securities (ABS)			0				0.3				0				0.3
Mortgage-backed securities (MBS), net short sales			0				9.6				0				9.6
Collateralized mortgage obligations (CMOs)			0				2				0				2
Mutual fund			0				98.6				0				98.6
Commingled fund			0				129.2				0				129.2
Total fixed income securities			0				315.7				0				315.7
Derivatives
Short futures			0				(0.3	)			0				(0.3	)
Purchased options (swaptions)			0				0.7				0				0.7
Written options (swaptions)			0				(0.8	)			0				(0.8	)
Total derivatives			0				(0.4	)			0				(0.4	)
Miscellaneous			0				0.1				0				0.1
Total		$	278			$	370			$	0			$	648

(millions)		At Fair Value as of Dec. 31, 2013
		Level 1				Level 2				Level 3				Total
Accounts receivable		$	44.7			$	0			$	0			$	44.7
Accounts payable			(40.8	)			0				0				(40.8	)
Cash equivalents
Short term investment funds (STIFs)			7.9				0				0				7.9
Treasury bills (T bills)			0				0.3				0				0.3
Repurchase agreement			0				8.8				0				8.8
Commercial paper			0				0.4				0				0.4
Money markets			0				1.5				0				1.5
Total cash equivalents			7.9				11				0				18.9
Equity securities
Common stocks			91.6				0				0				91.6
American depository receipts (ADRs)			3				0				0				3
Real estate investment trusts (REITs)			1.7				0				0				1.7
Preferred stock			0				0.8				0				0.8
Mutual funds			172.6				0				0				172.6
Commingled fund			0				50				0				50
Total equity securities			268.9				50.8				0				319.7
Fixed income securities
Municipal bonds			0				7.3				0				7.3
Government bonds			0				35.7				0				35.7
Corporate bonds			0				19.6				0				19.6
Asset backed securities (ABS)			0				0.4				0				0.4
Mortgage-backed securities (MBS), net short sales			0				6.7				0				6.7
Collateralized mortgage obligations (CMOs)			0				2.3				0				2.3
Mutual fund			0				85.1				0				85.1
Commingled fund			0				94.1				0				94.1
Total fixed income securities			0				251.2				0				251.2
Derivatives
Short futures			0				0.2				0				0.2
Swaps			0				(0.9	)			0				(0.9	)
Purchased options (swaptions)			0				0.2				0				0.2
Written options (swaptions)			0				(0.4	)			0				(0.4	)
Total derivatives			0				(0.9	)			0				(0.9	)
Miscellaneous			0				0.2				0				0.2
Total		$	280.7			$	312.3			$	0			$	593
—	The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
—	The STIF is valued at net asset value (NAV) as determined by JP Morgan. 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, making this a Level 1 asset.
—	The primary pricing inputs in determining the Level 1 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, making these Level 1 assets.
—	The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
—	T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
—	The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
—	The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
—	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 CMOs 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. Commercial MBS are priced using payment information and yields.
—	The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
—	The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. 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 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
—	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.
Other Postretirement Benefit Plan Assets
NMGC’s other postretirement benefits plan had $18.8 million of assets as of Dec. 31, 2014. 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 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 $47.5 million and $42.0 million of contributions to this plan in 2014 and 2013, respectively, which met the minimum funding requirements for both 2014 and 2013. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2015 to be $43.7 million and expects to make contributions from 2016 to 2019 in the range of $2.5 to $36.5 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.
The SERP is funded periodically to meet the benefit obligations. The company made contributions of $1.2 million and $2.6 million to this plan in 2014 and 2013, respectively. In 2015, the company expects to make contributions of about $4.9 million to this plan.
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 2015, 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
2015		$	73.4			$	11.5
2016			47.9				12
2017			47.8				12.5
2018			51.9				12.9
2019			58.3				13.4
2020-2024			285.5				69.5
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 April 2013, 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, 2014, 2013 and 2012, the company and its subsidiaries recognized expense totaling $13.1 million, $11.3 million and $7.0 million, respectively, related to the matching contributions made to this plan.
Effective Jan. 1, 2015, the employer matching contribution will increase to 70% of eligible participant contributions with additional incentive match of up to 30%.
Black Lung Liability
TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. TECO Coal applied the accounting guidance of ASC 715, Compensation – Retirement Benefits, and annual expense was recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially-computed liability for such benefits over the employee’s applicable term of service. At Dec. 31, 2014 and 2013, TECO Coal had an actuarially-determined black lung liability of $24.7 million and $24.5 million, respectively. TECO Coal recognized expense related to the black lung liability of $2.4 million, $2.2 million and $1.8 million for 2014, 2013 and 2012, respectively.
As discussed in Note 19, TECO Coal was classified as an asset held for sale in 2014. In accordance with ASC 715, an after-tax settlement charge of $7.9 million related to the unfunded black lung obligations recorded in accumulated other comprehensive income will be recognized as a loss from discontinued operations upon completion of the sale of TECO Coal, which is expected to occur in 2015.
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 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.
	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.
	The qualified pension plan’s actuarial value of assets, including credit balance, was 110.8% of the Pension Protection Act funded target as of Jan. 1, 2014 and is estimated at 115.9% of the Pension Protection Act funded target as of Jan. 1, 2015.
	Amounts disclosed for pension benefits in the following tables and discussion also include the unfunded 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 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.
	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. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in TECO Energy’s Consolidated Balance Sheets for 2014 and 2013.

	TECO Energy		Pension Benefits								Other Benefits
	Obligations and Funded Status
	(millions)		2014				2013				2014				2013
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	666			$	715			$	208.1			$	230.3
	Service cost			18.3				18.2				2.5				2.5
	Interest cost			32				28.9				10.8				9.3
	Plan participants’ contributions			0				0				2.8				2.9
	Plan amendments			0				0				(23.2	)			0
	Actuarial loss (gain)			48.3				(50.4	)			1.5				(22.1	)
	Gross benefits paid			(39.9	)			(43.1	)			(16.0	)			(15.0	)
	Transfer in due to the effect of business combination			0				0				26.7				0
	Plan curtailment			4				0				(11.7	)			0
	Special termination benefit			0.2				0				0				0
	Settlements			0				(2.6	)			0				0
	Federal subsidy on benefits paid		n/a				n/a					0				0.2
	Net benefit obligation at end of year		$	728.9			$	666			$	201.5			$	208.1

	Change in plan assets
	Fair value of plan assets at beginning of year		$	593			$	529.1			$	0			$	0
	Actual return on plan assets			46.4				63.7				0.1				0
	Employer contributions			47.5				44.6				(1.0	)			11.9
	Employer direct benefit payments			1				1.3				16
	Plan participants’ contributions			0				0				2.8				2.9
	Transfer in due to acquisition			0				0				16.9				0
	Settlements			0				(2.6	)			0				0
	Net benefits paid			(39.9	)			(43.1	)			(16.0	)			(14.8	)
	Fair value of plan assets at end of year		$	648			$	593			$	18.8			$	0

	Funded status
	Fair value of plan assets (1)		$	648			$	593			$	18.8			$	0
	Less: Benefit obligation (PBO/APBO)			728.9				666				201.5				208.1
	Funded status at end of year			(80.9	)			(73.0	)			(182.7	)			(208.1	)
	Unrecognized costs in regulated asset acquired in business combination			0				0				6.4				0
	Unrecognized net actuarial loss			203.7				173.1				9.6				19.7
	Unrecognized prior service (benefit) cost			0				(0.4	)			(24.0	)			(0.7	)
	Net amount required to be recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

	Amounts recognized in balance sheet
	Regulatory assets		$	167.4			$	139.6			$	26.6			$	43.2
	Accrued benefit costs and other current liabilities			(4.9	)			(3.3	)			(10.7	)			(13.3	)
	Deferred credits and other liabilities			(76.0	)			(69.7	)			(172.0	)			(194.8	)
	Accumulated other comprehensive loss (income), pretax			36.3				33.1				(34.6	)			(24.2	)
	Net amount recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)
	·	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.

	Tampa Electric Company		Pension Benefits								Other Benefits
Amounts recognized in balance sheet
(millions)		2014				2013				2014				2013
Regulatory assets		$	167.4			$	139.6			$	20.4			$	43.2
Accrued benefit costs and other current liabilities			(0.6	)			(0.9	)			(9.1	)			(10.8	)
Deferred credits and other liabilities			(53.5	)			(50.1	)			(137.1	)			(158.3	)
		$	113.3			$	88.6			$	(125.8	)		$	(125.9	)
The accumulated benefit obligation for TECO Energy Consolidated defined benefit pension plans was $685.0 million at Dec. 31, 2014 and $624.1 million at Dec. 31, 2013. The projected benefit obligation for the other postretirement benefits plan was $201.5 million at Dec. 31, 2014 and $208.1 million at Dec. 31, 2013.
Assumptions used to determine benefit obligations at Dec. 31:

		Pension Benefits								Other Benefits
		2014				2013				2014				2013
Discount rate			4.258	%			5.118	%			4.211	%			5.096	%
Rate of compensation increase-weighted average			3.87	%			3.73	%			3.86	%			3.71	%
Healthcare cost trend rate
Immediate rate		n/a				n/a					7.09	%			7.25	%
Ultimate rate		n/a				n/a					4.57	%			4.5	%
Year rate reaches ultimate		n/a				n/a				2025				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		$	3.7			$	(3.6	)
The discount rate assumption used to determine the Dec. 31, 2014 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
		2014				2013				2012				2014				2013			2012
(millions)
Service cost		$	18.3			$	18.2			$	17			$	2.5			$	2.5		$	2.4
Interest cost			32				28.9				30.1				10.8				9.3			10.1
Expected return on plan assets			(41.8	)			(38.4	)			(37.1	)			(0.3	)			0			0
Amortization of:
Actuarial loss			13.5				20.5				15.3				0.2				1			0.1
Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)			(0.2	)			(0.4	)		0.8
Transition obligation			0				0				0				0				0			1.8
Curtailment loss (gain)			3.9				0				0				(0.2	)			0			0
Special termination benefit			0.2				0				0				0				0			0
Settlement loss			0				1				0				0				0			0
Net periodic benefit cost		$	25.7			$	29.8			$	24.9			$	12.8			$	12.4		$	15.2

Prior service cost		$	0			$	0			$	0			$	(23.6	)		$	0		$	(5.2	)
Net loss (gain)			44.1				(75.7	)			34				(9.9	)			(15.6	)	16.3
Unrecognized costs in regulated asset acquired in business combination			0				0				0				6.4				0			0
Amortization of:
Actuarial gain (loss)			(13.5	)			(21.5	)			(15.3	)			(0.2	)			(1.0	)		(0.1	)
Prior service (benefit) cost		0.4					0.4				0.4				0.2				0.3			(0.8	)
Transition obligation			0				0				0				0				0			(1.8	)
Total recognized in OCI and regulatory assets		$	31			$	(96.8	)		$	19.1			$	(27.1	)		$	(16.3	)	$	8.4
Total recognized in net periodic benefit cost, OCI and regulatory assets		$	56.7			$	(67.0	)		$	44			$	(14.3	)		$	(3.9	)	$	23.6
TEC’s portion of the net periodic benefit costs for pension benefits was $14.8 million, $21.7 million and $18.3 million for 2014, 2013 and 2012, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $10.4 million, $10.0 million and $12.4 million for 2014, 2013 and 2012, respectively.
The estimated net loss and prior service credit 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 $10.0 million and $0.1 million, respectively. There will be no net loss and 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
		2014 (a)				2013				2012				2014				2013			2012
Discount rate		5.118%/4.277%/4.331%					4.196	%			4.797	%			5.096	%			4.18	%		4.744	%
Expected long-term return on plan assets		7.25%/7.00%/7.00%					7.5	%			7.5	%			5.75			n/a			n/a
Rate of compensation increase			3.73	%			3.76	%			3.83	%			3.71	%			3.74	%		3.82	%
Healthcare cost trend rate
Initial rate		n/a				n/a				n/a					7.25	%			7.5	%		7.75	%
Ultimate rate		n/a				n/a				n/a					4.5	%			4.5	%		4.5	%
Year rate reaches ultimate		n/a				n/a				n/a				2025				2025			2025
(a) 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 2014 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, 2014, TECO Energy’s pension plan experienced actual asset returns of approximately 7.9%.
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		$	0.3			$	(0.3	)
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 Allocation, End of Year
Asset Category						2014				2013
Equity securities		48%-54%					50	%			54	%
Fixed income securities		46%-52%					50	%			46	%
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). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.
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, 2014 and 2013.
Pension Plan Investments

(millions)		At Fair Value as of Dec. 31, 2014
		Level 1				Level 2				Level 3				Total
Cash		$	0.4			$	0			$	0			$	0.4
Accounts receivable			1.4				0				0				1.4
Accounts payable			(5.3	)			0				0				(5.3	)
Cash equivalents
Short term investment funds (STIFs)			7.6				0				0				7.6
Treasury bills (T bills)			0				0.2				0				0.2
Discounted notes			0				8.8				0				8.8
Total cash equivalents			7.6				9				0				16.6
Equity securities
Common stocks			98				0				0				98
American depository receipts (ADRs)			1.3				0				0				1.3
Real estate investment trusts (REITs)			2.5				0				0				2.5
Preferred stock			0.8				0				0				0.8
Mutual funds			171.3				0				0				171.3
Commingled fund			0				45.6				0				45.6
Total equity securities			273.9				45.6				0				319.5
Fixed income securities
Municipal bonds			0				6.1				0				6.1
Government bonds			0				47.9				0				47.9
Corporate bonds			0				22				0				22
Asset backed securities (ABS)			0				0.3				0				0.3
Mortgage-backed securities (MBS), net short sales			0				9.6				0				9.6
Collateralized mortgage obligations (CMOs)			0				2				0				2
Mutual fund			0				98.6				0				98.6
Commingled fund			0				129.2				0				129.2
Total fixed income securities			0				315.7				0				315.7
Derivatives
Short futures			0				(0.3	)			0				(0.3	)
Purchased options (swaptions)			0				0.7				0				0.7
Written options (swaptions)			0				(0.8	)			0				(0.8	)
Total derivatives			0				(0.4	)			0				(0.4	)
Miscellaneous			0				0.1				0				0.1
Total		$	278			$	370			$	0			$	648



Pension Plan Investments

(millions)		At Fair Value as of Dec. 31, 2013
		Level 1				Level 2				Level 3				Total
Accounts receivable		$	44.7			$	0			$	0			$	44.7
Accounts payable			(40.8	)			0				0				(40.8	)
Cash equivalents
Short term investment funds (STIFs)			7.9				0				0				7.9
Treasury bills (T bills)			0				0.3				0				0.3
Repurchase agreement			0				8.8				0				8.8
Commercial paper			0				0.4				0				0.4
Money markets			0				1.5				0				1.5
Total cash equivalents			7.9				11				0				18.9
Equity securities
Common stocks			91.6				0				0				91.6
American depository receipts (ADRs)			3				0				0				3
Real estate investment trusts (REITs)			1.7				0				0				1.7
Preferred stock			0				0.8				0				0.8
Mutual funds			172.6				0				0				172.6
Commingled fund			0				50				0				50
Total equity securities			268.9				50.8				0				319.7
Fixed income securities
Municipal bonds			0				7.3				0				7.3
Government bonds			0				35.7				0				35.7
Corporate bonds			0				19.6				0				19.6
Asset backed securities (ABS)			0				0.4				0				0.4
Mortgage-backed securities (MBS), net short sales			0				6.7				0				6.7
Collateralized mortgage obligations (CMOs)			0				2.3				0				2.3
Mutual fund			0				85.1				0				85.1
Commingled fund			0				94.1				0				94.1
Total fixed income securities			0				251.2				0				251.2
Derivatives
Short futures			0				0.2				0				0.2
Swaps			0				(0.9	)			0				(0.9	)
Purchased options (swaptions)			0				0.2				0				0.2
Written options (swaptions)			0				(0.4	)			0				(0.4	)
Total derivatives			0				(0.9	)			0				(0.9	)
Miscellaneous			0				0.2				0				0.2
Total		$	280.7			$	312.3			$	0			$	593
·	The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
·	The STIF is valued at net asset value (NAV) as determined by JP Morgan. 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, making this a Level 1 asset.
·	The primary pricing inputs in determining the Level 1 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, making these Level 1 assets.
·	The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
·	T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
·	The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
·	The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
·	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 CMOs 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. Commercial MBS are priced using payment information and yields.
·	The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
·	The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. 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 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
·	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.
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
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 $47.5 million of contributions to this plan in 2014 and $42.0 million in 2013, which met the minimum funding requirements for both 2014 and 2013. TEC’s portion of the contribution in 2014 was $38.2 million and in 2013 was $33.5 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2015 to be $43.7 million, with TEC’s portion being $33.5 million. TECO Energy estimates it will make annual contributions from 2016 to 2019 ranging from $2.5 to $36.5 million per year based on current assumptions, with TEC’s portion to range from $1.5 million to $29.0 million. These amounts are in excess of the minimum funding required under ERISA guidelines.
The SERP is funded annually to meet the benefit obligations. TECO Energy made contributions of $1.2 million and $2.6 million to this plan in 2014 and 2013, respectively. TEC’s portion of the contributions in 2014 and 2013 were $0.8 million and $1.0 million, respectively. In 2015, TECO Energy expects to make a contribution of about $4.9 million to this plan. TEC’s portion of the expected contribution is about $0.6 million.
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 2015, TECO Energy expects to make a contribution of about $14.3 million. TEC’s portion of the expected contribution is $9.1 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
2015		$	73.4			$	11.5
2016			47.9				12
2017			47.8				12.5
2018			51.9				12.9
2019			58.3				13.4
2020-2024			285.5				69.5
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 April 2013, 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, 2014, 2013 and 2012, TECO Energy and its subsidiaries recognized expense totaling $13.1 million, $11.3 million and $7.0 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $10.2 million, $9.1 million and $6.0 million for 2014, 2013 and 2012, respectively.
Effective Jan. 1, 2015, the employer matching contribution will increase to 70% of eligible participant contributions with additional incentive match of up to 30%

ShortTerm_Debt

Short-Term Debt	12 Months Ended
Short-Term Debt	Dec. 31, 2014
Short-Term Debt	6. Short-Term Debt
	At Dec. 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:
	Credit Facilities

			Dec. 31, 2014						Dec. 31, 2013
							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	$	12	$	0.6	$	325	$	6	$	0.7
	1-year accounts receivable facility			150		46		0		150		78		0
	TECO Energy/TECO Finance:
	5-year facility (2)(3)			300		50		0		200		0		0
	New Mexico Gas Company:
	5-year facility (2)			125		31		1.7		0		0		0
	Total		$	900	$	139	$	2.3	$	675	$	84	$	0.7
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	-3	TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
	At Dec. 31, 2014, 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, 2014 and 2013 was 1.16% and 0.56%, respectively.
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 3, 2015, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 13 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A., Inc. as Program Agent. The amendment extends the maturity date to Apr. 14, 2015.
	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 its $125 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.
	TECO Energy and TECO Finance Bridge Facility
	TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement (the Bridge Facility) on June 24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders in the Bridge Facility. TECO Energy unconditionally guaranteed TECO Finance’s obligations under the Bridge Facility. In the third quarter of 2014, TECO Energy permanently financed the NMGC Acquisition with a combination of (i) a TECO Energy equity offering, (ii) the issuance of debt at NMGC and NMGI, (iii) cash on hand and (iv) short-term borrowings. Upon closing of the acquisition on Sept. 2, 2014, the commitment under the Bridge Facility was permanently cancelled by TECO Energy and TECO Finance.
	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); (ii) continued to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.
	On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.
	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 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closed, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changed the definition of Permitted Liens to permit the acquisition of a significant subsidiary that has outstanding secured debt and made other changes matching the corresponding covenant in the Bridge Facility, 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, 2014 and 2013, the following credit facilities and related borrowings existed:
	Credit Facilities

			Dec. 31, 2014						Dec. 31, 2013
							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	$	12	$	0.6	$	325	$	6	$	0.7
	1-year accounts receivable facility			150		46		0		150		78		0
	Total		$	475	$	58	$	0.6	$	475	$	84	$	0.7
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	At Dec. 31, 2014, 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, 2014 and 2013 was 0.7% and 0.56%, respectively.
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 3, 2015, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 13 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A., Inc. as Program Agent. The amendment extends the maturity date to Apr.14, 2015.
	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); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.
	On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.

LongTerm_Debt

Long-Term Debt	12 Months Ended
Long-Term Debt	Dec. 31, 2014
Long-Term Debt	7. Long-Term Debt
	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. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 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 100% 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 other 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 2015 through 2019 and thereafter are as follows:
	Long-Term Debt Maturities

																		Total
	As of Dec. 31, 2014																	Long-Term
	(millions)		2015				2016			2017		2018		2019		Thereafter		Debt
	TECO Finance		$	191.2			$	250		$	300	$	0	$	0	$	300	$	1,041.20
	Tampa Electric			83.3				83.4			0		254.2		0		1,436.70		1,857.60
	PGS			0				0			0		50		0		191.7		241.7
	NMGI			0				0			0		0		50		150		200
	NMGC			0				0			0		0		0		270		270
	Total long-term debt maturities		$	274.5			$	333.4		$	300	$	304.2	$	50	$	2,348.40	$	3,610.50
	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 and 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, Series 2007 B
	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, 2014, $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, 2014 and 2013, TECO Energy had the following long-term debt outstanding:

	Long-Term Debt
	(millions)				Due		2014			2013
	TECO Finance		Notes (1)(2)(3) : 6.75%		2015		$	191.2		$	191.2
			4.00%		2016			250			250
			6.57%		2017			300			300
			5.15%		2020			300			300
			Total long-term debt of TECO Finance					1,041.20			1,041.20
	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
			5.15% Refunding bonds repurchased in 2013 (6)		2025			0			0
			1.5% Term rate bonds repurchased in 2011 (7)		2030			0			0
			5.0% Refunding bonds repurchased in 2012 (8)		2034			0			0
			Notes (1)(2) : 6.25%		2014-2016			166.7			250
			6.10%		2018			200			200
			5.40%		2021			231.7			231.7
			2.60%		2022			225			225
			6.55%		2036			250			250
			6.15%		2037			190			190
			4.10%		2042			250			250
			4.35%		2044			290			0
			Total long-term debt of Tampa Electric					1,857.60			1,650.90
	PGS		Notes (1)(2) : 6.10%		2018			50			50
			5.40%		2021			46.7			46.7
			2.60%		2022			25			25
			6.15%		2037			60			60
			4.10%		2042			50			50
			4.35%		2044			10			0
			Total long-term debt of PGS					241.7			231.7
	NMGI		Notes (1)(2) : 2.71%		2019			50			0
			3.64%		2024			150			0
			Total long-term debt of NMGI					200			0
	NMGC		Notes (1)(2) : 4.87%		2021			200			0
		3.54%		2026			70			0
		Total long-term debt of NMGC					270			0
		Total long-term debt of TECO Energy					3,610.50			2,923.80
Unamortized debt discount, net							18			(2.7	)
Total carrying amount of long-term debt							3,628.50			2,921.10
Less amount due within one year							274.5			83.3
Total long-term debt						$	3,354.00		$	2,837.80
-1	These securities are subject to redemption in whole or in part, at any time, at the option of the company.
-2	These long-term debt agreements contain various restrictive financial covenants.
-3	Guaranteed by TECO Energy.
-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 4.35% 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 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, 2014. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA 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.
	As of Dec. 31, 2014, $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
Preferred Stock	Dec. 31, 2014
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
Common Stock	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Common Stock	9. Common Stock
	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 to reduce the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), remove the cap on shares available for stock grant, place various limitations on the terms of awards granted under the 2010 Plan, remove the ability to make awards to consultants of the company and reapprove 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 between 0% and 150% 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 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		2014				2013				2012
	Assumptions applicable to performance-based restricted stock
	Risk-free interest rate			0.68	%			0.41	%			0.38	%
	Expected lives (in years)			3				3				3
	Expected stock volatility			17.36	%			19.04	%			20.99	%
	Dividend yield			5.13	%			4.83	%			4.78	%
	In 2014, 2013 and 2012, 0.8 million, 0.7 million and 1.0 million shares of restricted stock were granted, respectively, with weighted-average fair value per share of $14.69, $17.21 and $15.96, respectively. The total fair market value of awards vesting during 2014, 2013 and 2012 was $3.6 million, $3.5 million and $14.3 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2014, there was $12.7 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)		2014				2013				2012
	Compensation costs (1)		$	12.7			$	13.5			$	12
	Income tax benefits (1)			4.9				5.2				4.6
	Excess tax benefits (2)			0.4				0				2.6
	-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 $2.7 million, $2.4 million and $0.3 million for the periods ended Dec. 31, 2014, 2013 and 2012, respectively. Cash received from option exercises under all share-based payment arrangements was $10.8 million, $6.7 million and $1.1 million for the periods ended Dec. 31, 2014, 2013 and 2012, respectively. The income tax benefit realized from stock option exercises was $1.0 million, $0.8 million and $0.1 million for the periods ended Dec. 31, 2014, 2013 and 2012, 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, 2013			638			$	18.33				1,505		$	17.04
	Granted			265			$	16.93				537		$	13.59
	Vested			(200	)		$	19.16				(444	)	$	18.53
	Forfeited			(35	)		$	17.51				(83	)	$	15.51
	Nonvested balance at Dec. 31, 2014			668			$	17.56				1,515		$	15.44
	-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, 2013			1,567			$	15.62
	Granted			0			$	0
	Exercised			(727	)		$	14.8
	Cancelled			0			$	0
	Outstanding balance at Dec. 31, 2014(1)			840			$	16.32				1		$	3.5
	Exercisable at Dec. 31, 2014 (1)			840			$	16.32				1		$	3.5
	Available for future grant at Dec. 31, 2014			2,482
	-1	Option prices range from $16.21 to $19.01 per share.
	As of Dec. 31, 2014, the options outstanding and exercisable are summarized below:

	Range of						Weighted-Avg.				Weighted-Avg.
	Option Prices		Option Shares				Option Price				Remaining
	(per share)		(thousands)				(per share)				Contractual Life (years)

$16.21 — $ 19.01			840			$	16.32			1
Total			840			$	16.32			1
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 2014, 2013 and 2012, resulting in no increase in shares outstanding.

Other_Comprehensive_Income

Other Comprehensive Income	12 Months Ended
Other Comprehensive Income	Dec. 31, 2014
Other Comprehensive Income	10. Other Comprehensive Income
	TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2014, 2013 and 2012, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

	(millions)		Gross			Tax			Net
	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
	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 (3)			(12.9	)		4.7			(8.2	)
	Change in benefit obligation due to remeasurement (4)			12.6			(4.6	)		8
	Total other comprehensive income (loss)		$	(4.0	)	$	1.5		$	(2.5	)
	2013
	Unrealized gain (loss) on cash flow hedges		$	1		$	(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 benefit costs due to settlement			2.6			(1.0	)		1.6
	Total other comprehensive income (loss)		$	28.5		$	(10.7	)	$	17.8
	2012
	Unrealized gain (loss) on cash flow hedges		$	(7.4	)	$	2.8		$	(4.6	)
	Reclassification from AOCI to net income (1)			0.6			(0.2	)		0.4
	Gain (Loss) on cash flow hedges			(6.8	)		2.6			(4.2	)
	Amortization of unrecognized benefit costs and other (2)(5)			(4.8	)		0			(4.8	)
	Total other comprehensive income (loss)		$	(11.6	)	$	2.6		$	(9.0	)
	-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	Includes an adjustment to eliminate TECO Coal’s OPEB liability. See Note 5 for additional information.
	-5	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.
	Accumulated Other Comprehensive Loss

	(millions) Dec. 31,		2014			2013
	Unrecognized pension losses and prior service credits (1)		$	(22.5	)	$	(20.5	)
	Unrecognized other benefit gains, prior service costs and transition obligations (2)			13.9			15.1
	Net unrealized losses from cash flow hedges (3)			(7.1	)		(7.8	)
	Total accumulated other comprehensive loss		$	(15.7	)	$	(13.2	)
	-1	Net of tax benefit of $13.8 million and $12.6 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.
	-2	Net of tax expense of $8.3 million and $9.1 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively. Balance includes a $7.9 million loss at Dec. 31, 2014 related to TECO Coal’s unfunded black lung liability that will be reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5.
	-3	Net of tax benefit of $4.5 million and $4.9 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	8. Other Comprehensive Income
	TEC reported the following OCI (loss) for the years ended Dec. 31, 2014, 2013 and 2012, 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
	2014
	Unrealized gain (loss) on cash flow hedges		$	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
	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
	2012
	Unrealized gain (loss) on cash flow hedges		$	(8.0	)	$	3.1		$	(4.9	)
	Reclassification from AOCI to net income			1.4			(0.6	)		0.8
	Gain (Loss) on cash flow hedges			(6.6	)		2.5			(4.1	)
	Total other comprehensive income (loss)		$	(6.6	)	$	2.5		$	(4.1	)
	Accumulated Other Comprehensive Loss

	(millions) As of Dec. 31,		2014			2013
	Net unrealized losses from cash flow hedges (1)		$	(7.1	)	$	(7.8	)
	Total accumulated other comprehensive loss		$	(7.1	)	$	(7.8	)
	-1	Net of tax benefit of $4.5 million and $4.9 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
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)		2014			2013 (1)			2012 (1)
	Basic earnings per share
	Net income from continuing operations		$	206.4		$	188.7		$	197
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Income before discontinued operations available to		$	205.7		$	188.1		$	196.3
	common shareholders—Basic
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy, net
	Amount allocated to nonvested participating shareholders			0			0			0
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy available to common shareholders—Basic
	Net income attributable to TECO Energy		$	130.4		$	197.7		$	212.7
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Net income attributable to TECO Energy available to		$	129.7		$	197.1		$	212
	common shareholders—Basic
	Average common shares outstanding—Basic			223.1			215			214.3
	Earnings per share from continuing operations available to		$	0.92		$	0.88		$	0.92
	common shareholders—Basic
	Earnings per share from discontinued operations		$	(0.34	)	$	0.04		$	0.07
	attributable to TECO Energy available to common
	shareholders—Basic
	Earnings per share attributable to TECO Energy available		$	0.58		$	0.92		$	0.99
	to common shareholders—Basic
	Diluted earnings per share
	Net income from continuing operations		$	206.4		$	188.7		$	197
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Income before discontinued operations available to		$	205.7		$	188.1		$	196.3
	common shareholders—Diluted
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy, net
	Amount allocated to nonvested participating shareholders			0			0			0
	Income (loss) from discontinued operations attributable		$	(76.0	)	$	9		$	15.7
	to TECO Energy available to common
	shareholders—Diluted
	Net income attributable to TECO Energy		$	130.4		$	197.7		$	212.7
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Net income attributable to TECO Energy available to		$	129.7		$	197.1		$	212
	common shareholders—Diluted
	Unadjusted average common shares outstanding—Diluted			223.1			215			214.3
	Assumed conversion of stock options, unvested restricted			0.6			0.5			0.7
	stock and contingent performance shares, net
	Average common shares outstanding—Diluted			223.7			215.5			215
	Earnings per share from continuing operations available to		$	0.92		$	0.88		$	0.92
	common shareholders—Diluted
	Earnings per share from discontinued operations		$	(0.34	)	$	0.04		$	0.07
	attributable to TECO Energy available to common
	shareholders—Diluted
	Earnings per share attributable to TECO Energy available		$	0.58		$	0.92		$	0.99
	to common shareholders—Diluted
	Anti-dilutive shares			0			0			0.4
	-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
Commitments and Contingencies	Dec. 31, 2014
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. 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.
	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.
	Tampa Electric Legal Proceedings
	Three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida for personal injuries allegedly caused by exposure to a chemical substance at one of TEC's power stations. The suit was originally filed in 2002, and the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014, all plaintiffs voluntarily dismissed their suits with prejudice.
	A thirty-six year old man died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and nineteen other defendants alleges, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death.
	In September 2014, a man was electrocuted when allegedly two energized, downed primary conductors fell during a heavy storm, leading to his death. Plaintiff's wrongful death complaint against Tampa Electric alleges, among other things, negligence and code violations.
	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.”
	The two purported class action suits (three purported classes) were consolidated. The court dismissed the class actions in their entirety with prejudice in October 2014 and appeals from the dismissal were taken by the plaintiffs in November 2014 and are pending.
	Two lawsuits representing 18 insurance carriers have filed subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. These subrogation matters are pending and discovery is proceeding. NMGC has filed motions to dismiss similar to those previously filed and ruled on favorably in the class actions.
	The company believes the claims in the pending actions described above in this item are without merit and intends to defend each matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters.
	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 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. Guatemala also requested that the enforcement of the Award be stayed while the annulment proceeding is pending. Under the applicable rules, the enforcement of the Award is provisionally stayed until the ad hoc committee constituted for purposes of deciding Guatemala's application makes a decision regarding whether the stay should continue through the rest of the annulment proceeding.
	Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the 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 is scheduled in October 2015 and the proceedings as a whole are expected to take approximately two years to conclude, with a decision by the ad hoc committee in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.
	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, 2014, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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 under long-term leases, primarily for building space, capacity payments, 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, 2014, 2013 and 2012 totaled $13.7 million, $7.6 million and $8.1 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, 2014:

			Capacity		Operating		Net Purchase
	(millions)		Payments		Leases(1)		Obligations/Commitments(1)		Total
	Year ended Dec. 31:
	2015		$	30	$	8.9	$	204.5	$	243.4
	2016			14.6		8		86.8		109.4
	2017			9.9		7		19.8		36.7
	2018			10.1		6.2		5.2		21.5
	2019			0		5.7		5.3		11
	Thereafter			0		18.4		0		18.4
	Total future minimum payments		$	64.6	$	54.2	$	321.6	$	440.4
	-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, 2014 are as follows:



	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Guarantees for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TECO Energy
	Fuel sales and transportation (2)		$	0	$	0	$	92.9		92.9	$	0

	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Letter of Credit for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TEC		$	0	$	0	$	0.6	$	0.6	$	0.1
	NMGC		$	0	$	0	$	1.7	$	1.7	$	0
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019.
	-2	The amounts shown 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, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.
	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, 2014, 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. 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.
	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.
	Tampa Electric Legal Proceedings
	Three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida for personal injuries allegedly caused by exposure to a chemical substance at one of TEC's power stations. The suit was originally filed in 2002, and the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014 all plaintiffs voluntarily dismissed their suits with prejudice.
	A thirty-six year old man died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and nineteen other defendants alleges, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death.
	In September 2014, a man was electrocuted when allegedly two energized, downed primary conductors fell during a heavy storm, leading to his death. Plaintiff's wrongful death complaint against Tampa Electric alleges, among other things, negligence and code violations.
	The company believes the claims in the pending actions described above in this item are without merit and intends to defend each matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters.
	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, 2014, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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 under long-term leases, primarily for building space, capacity payments, 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, 2014, 2013 and 2012, totaled $4.1 million, $2.3 million and $2.2 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, 2014:

			Capacity		Operating		Net Purchase
	(millions)		Payments		Leases(1)		Obligations/Commitments(1)		Total
	Year ended Dec. 31:
	2015		$	30	$	6.7	$	203.2	$	239.9
	2016			14.6		6.1		86.8		107.5
	2017			9.9		5.2		19.8		34.9
	2018			10.1		4.5		5.2		19.8
	2019			0		4.4		5.3		9.7
	Thereafter			0		13		0		13
	Total future minimum payments		$	64.6	$	39.9	$	320.3	$	424.8
	-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
	TEC 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.
	At Dec. 31, 2014, TEC was not obligated under guarantees, but had the following letters of credit outstanding.
	Letters of Credit-Tampa Electric Company

	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Letter of Credit for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TEC		$	0	$	0	$	0.6	$	0.6	$	0.1
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019.
	-2	The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at Dec. 31, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.
	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, 2014, TEC was in compliance with all required financial covenants.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2014
Related Party Transactions	13. Related Parties
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 and $1.3 million for the years ended Dec. 31, 2013 and 2012, respectively, 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, 2014, 2013 and 2012. No material balances were payable as of Dec. 31, 2014 or 2013.
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)		2014		2013		2012
	Natural gas sales, net		$	0.3	$	18.3	$	11.7
	Administrative and general, net		$	22.5	$	27.2	$	23.4
	Amounts due from or to affiliates at Dec. 31,

	(millions)		2014		2013
	Accounts receivable(1)		$	2.4	$	1.3
	Accounts payable(1)			9.7		9.8
	Taxes receivable(2)			43.3		54.9
	Taxes payable			0		0.4
	-1	Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
	-2	Taxes receivable is due from 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 and $1.2 million for the years ended Dec. 31, 2013 and 2012, respectively, to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee.

Segment_Information

Segment Information	12 Months Ended
Segment Information	Dec. 31, 2014
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 more than 706,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for almost 354,000 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 approximately 513,000 residential, commercial, industrial customers in the State of New Mexico.
			Tampa							TECO				TECO									TECO
	(millions)		Electric		PGS		NMGC (4)			Coal (2)				Guatemala (2)			Other (4)			Eliminations			Energy
	2014
	Revenues—external		$	2,019.90	$	398.5	$	137.5		$	0			$	0		$	10.5		$	0		$	2,566.40
	Sales to affiliates			1.1		1.1		0			0				0			40.6			(42.8	)		0
	Total revenues			2,021.00		399.6		137.5			0				0			51.1			(42.8	)		2,566.40
	Depreciation and amortization			248.6		54		11			0				0			1.7			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			1.4			(1.4	)		0
	Provision for income taxes			133.2		22.7		7.1			0				0			(24.1	)		0			138.9
	Net income from continuing operations			224.5		35.8		10.5			0				0			17.8			(82.2	)		206.4
	Discontinued operations attributable to TECO, net of tax			0		0		0			(82.0	)			0			6			0			(76.0	)
	Net income attributable to TECO Energy			224.5		35.8		10.5			(82.0	)			0			23.8			(82.2	)		130.4
	Current assets held for sale			0		0		0			109.6				0			0			0			109.6
	Non-current assets held for sale			0		0		0			59.8				0			0			0			59.8
	Goodwill			0		0		408.3			0				0			0			0			408.3
	Total assets			6,565.40		1,082.80		1,237.20			227.7		-3		0			5,664.40			(6,051.3	)		8,726.20
	Capital expenditures			592.6		88.9		18.2			14.6				0			0			0			714.3
	2013
	Revenues—external		$	1,949.60	$	392.7	$	0		$	0			$	0		$	12.8		$	0		$	2,355.10
	Sales to affiliates			0.9		0.8		0			0				0			0.5			(2.2	)		0
	Total revenues			1,950.50		393.5		0			0				0			13.3			(2.2	)		2,355.10
	Depreciation and amortization			238.8		51.5		0			0				0			1.5			0			291.8
	Total interest charges (1)			91.8		13.5		0			0				0			63.9			(7.8	)		161.4
	Internally allocated interest (1)			0		0		0			0				0			7.8			(7.8	)		0
	Provision for income taxes			116.9		21.9		0			0				0			(26.2	)		0			112.6
	Net income from continuing operations			190.9		34.7		0			0				0			177.3			(214.2	)		188.7
	Discontinued operations attributable to TECO, net of tax			0		0		0			9				0			0			0			9
	Net income attributable to TECO Energy			190.9		34.7		0			9				0			177.3			(214.2	)		197.7
	Total assets			6,126.90		1,021.20		0			316.3		-3		0			4,717.20			(4,733.6	)		7,448.00
	Capital expenditures			428.6		79		0			22.4				0			2.4			-			532.4
	2012
	Revenues—external		$	1,980.70	$	396.6	$	0		$	0			$	0		$	10.4		$	0		$	2,387.70
	Sales to affiliates			0.6		2.3		0			0				0			0.1			(3.0	)		0
	Total revenues			1,981.30		398.9		0			0				0			10.5			(3.0	)		2,387.70
	Depreciation and amortization			237.6		50.6		0			0				0			1.4			0			289.6
	Total interest charges (1)			109.8		16		0			0				0			64.1			(13.5	)		176.4
	Internally allocated interest (1)			0		0		0			0				0			13.5			(13.5	)		0
	Provision for income taxes			120.2		21.5		0			0				0			(20.9	)		0			120.8
	Net income from continuing operations			193.1		34.1		0			0				0			241.3			(271.5	)		197
	Discontinued operations attributable to TECO, net of tax			0		0		0			50.2				(29.3	)		(5.2	)		0			15.7
	Net income attributable to TECO Energy			193.1		34.1		0			50.2				(29.3	)		236.1			(271.5	)		212.7
	Total assets			6,042.30		1,009.90		0			356.6		-3		164.9			4,870.00			(5,108.8	)		7,334.90
	Capital expenditures			361.7		97.3		0			36.3				8.6			1.2			0			505.1

	-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 2014, 2013 and 2012 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, TECO Guatemala and certain charges at Parent that directly relate to TECO Coal or TECO Guatemala. See Note 19.
	-3	The carrying value of mineral rights as of Dec. 31, 2014, 2013 and 2012 was $10.9 million, $12.1 million and $13.4 million, respectively.
	-4	NMGI is included in the Other segment.
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 more than 706,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for almost 354,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

			Tampa
	(millions)		Electric		PGS		Eliminations			TEC
	2014
	Revenues - external		$	2,020.50	$	398.5	$	0		$	2,419.00
	Sales to affiliates			0.5		1.1		(1.6	)		0
	Total revenues			2,021.00		399.6		(1.6	)		2,419.00
	Depreciation and amortization			248.6		54		0			302.6
	Total interest charges			92.8		13.8		0			106.6
	Provision for income taxes			133.2		22.7		0			155.9
	Net income			224.5		35.8		0			260.3
	Total assets			6,234.40		1,047.00		(7.1	)		7,274.30
	Capital expenditures			592.6		88.9		0			681.5
	2013
	Revenues - external		$	1,950.10	$	392.7	$	0		$	2,342.80
	Sales to affiliates			0.4		0.8		(1.2	)		0
	Total revenues			1,950.50		393.5		(1.2	)		2,342.80
	Depreciation and amortization			238.8		51.5		0			290.3
	Total interest charges			91.8		13.5		0			105.3
	Provision for income taxes			116.9		21.9		0			138.8
	Net income			190.9		34.7		0			225.6
	Total assets			5,895.40		989.3		(8.9	)		6,875.80
	Capital expenditures			428.6		79		0			507.6
	2012
	Revenues - external		$	1,980.90	$	397.1	$	0		$	2,378.00
	Sales to affiliates			0.4		1.8		(2.2	)		0
	Total revenues			1,981.30		398.9		(2.2	)		2,378.00
	Depreciation and amortization			237.6		50.6		0			288.2
	Total interest charges			109.8		16		0			125.8
	Provision for income taxes			120.2		21.5		0			141.7
	Net income			193.1		34.1		0			227.2
	Total assets			5,760.40		970.9		13.3			6,744.60
	Capital expenditures			361.7		97.3		0			459

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2014
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.
	TECO Energy has recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2014 and 2013, these obligations totaled $22.5 million and $23.8 million, respectively, and are classified as Liabilities Associated with Assets Held for Sale on TECO Energy’s Consolidated Balance Sheets.
	Our 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 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, 2014 and 2013, these obligations totaled $6.1 million and $4.8 million, respectively.
	Reconciliation of beginning and ending carrying amount of asset retirement obligations:

			Dec. 31,
	(millions)		2014			2013
	Beginning balance		$	28.6		$	28.6
	Additional liabilities			0.1			0.1
	Liabilities settled			0			(1.4	)
	Accretion expense			0			1.4
	Revisions to estimated cash flows			0.2			(0.3	)
	Acquisition of NMGC			0.8			0
	Reclassification to liabilities associated with assets held for sale			(22.5	)		0
	Other (1)			(1.1	)		0.2
	Ending balance		$	6.1		$	28.6
	-1	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. 2013 includes 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)		2014			2013
	Beginning balance		$	4.8		$	5
	Additional liabilities			0.1			0.1
	Liabilities settled			0			(0.2	)
	Revisions to estimated cash flows			0.2			(0.3	)
	Other (1)			0.2			0.2
	Ending balance		$	5.3		$	4.8
	-1	Accretion recorded as a deferred regulatory asset.

Accounting_for_Derivative_Inst

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2014
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;
	·	To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates; and
	·	To limit the exposure to price fluctuations for physical purchases of fuel at TECO Coal (all of which were settled prior to Dec. 31, 2014).
	TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.
	The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.
	The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 17). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.
	The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC and NMPRC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).
	The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Dec. 31, 2014, all of the company’s physical contracts qualify for the NPNS exception.
	The derivatives that are designated as cash flow hedges at Dec. 31, 2014 and 2013 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 and $10.0 million as of Dec. 31, 2014 and 2013, respectively, and derivative liabilities totaled $42.7 million and $0.3 million as of Dec. 31, 2014 and 2013, 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, 2014 and 2013 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, 2014, net pretax losses of $36.6 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, 2014 and 2013 balance in AOCI related to the cash flow hedges and previously settled interest rate swaps 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, 2014, 2013 and 2012, 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 years ended Dec. 31, 2014, 2013 and 2012 is presented in Note 10. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in Interest expense for TEC and Income (loss) from discontinued operations for TECO Coal.
	The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for financial natural gas contracts. There is no diesel fuel contract exposure beyond 2014. The following table presents the company’s derivative volumes that, as of Dec. 31, 2014, are expected to settle during the 2015 and 2016 fiscal years:

			Natural Gas Contracts
	(millions)		(MMBTUs)
	Year		Physical		Financial
	2015			0		32.4
	2016			0		8.6
	Total			0		41
	The company is exposed to credit risk primarily through 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, 2014, 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 are generally not adjusted 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. As of Dec. 31, 2014, all positions with counterparties were net liabilities.
	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 request immediate payment or 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). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.
	TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).
	TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2014, all of TEC’s physical contracts qualify for the NPNS exception.
	The derivatives that are designated as cash flow hedges at Dec. 31, 2014 and 2013 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. Derivative assets totaled $0 and $9.8 million as of Dec. 31, 2014 and 2013, respectively, and derivative liabilities totaled $42.7 million and $0.2 million as of Dec. 31, 2014 and 2013, 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, 2014 and 2013 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, 2014, net pretax losses of $36.6 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, 2014 and 2013 balance in AOCI related to the cash flow hedges and previously settled interest rate swaps 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, 2014, 2013 and 2012, 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 years ended Dec. 31, 2014, 2013 and 2012 is presented in Note 8. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.
	The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Dec. 31, 2014, are expected to settle during the 2015 and 2016 fiscal years:

			Natural Gas Contracts
	(millions)		(MMBTUs)
	Year		Physical		Financial
	2015			0		32.4
	2016			0		8.6
	Total			0		41
	TEC is exposed to credit risk primarily through 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, 2014, 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 are generally not adjusted 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. As of Dec. 31, 2014, all positions with counterparties were net liabilities.
	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 request immediate payment or 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
Fair Value Measurements	Dec. 31, 2014
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, 2014 and 2013. 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. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.
	Recurring Fair Value Measures

			As of Dec. 31, 2014
	(millions)		Level 1		Level 2		Level 3		Total
	Liabilities
	Natural gas swaps		$	0	$	42.7	$	0	$	42.7

			As of Dec. 31, 2013
	(millions)		Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps		$	0	$	9.8	$	0	$	9.8
	Diesel fuel swaps			0		0.2		0		0.2
	Total		$	0	$	10	$	0	$	10
	Liabilities
	Natural gas swaps		$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps			0		0.1		0		0.1
	Total		$	0	$	0.3	$	0	$	0.3
	Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported 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, 2014, 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 20 for information regarding the fair value of the company’s pension plan investments, long-term debt, and asset impairment charge, respectively.
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, 2014 and 2013. 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. For all assets and liabilities presented below, the market approach was used in determining fair value.
	Recurring Derivative Fair Value Measures

			As of Dec. 31, 2014
	(millions)		Level 1		Level 2		Level 3		Total
	Liabilities
	Natural gas swaps		$	0	$	42.7	$	0	$	42.7

			As of Dec. 31, 2013
	(millions)		Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps		$	0	$	9.8	$	0	$	9.8
	Total		$	0	$	9.8	$	0	$	9.8

	Liabilities
	Natural gas swaps		$	0	$	0.2	$	0	$	0.2
	Total		$	0	$	0.2	$	0	$	0.2
	Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts 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, 2014, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions. There were no Level 3 assets or liabilities during the 2014 or 2013 fiscal years.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2014
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.
	TEC 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 370 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 VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC 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, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $25.7 million, $22.1 million and $75.8 million, under these PPAs for the three years ended Dec. 31, 2014, 2013 and 2012, 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.
	TEC 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 370 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 VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC 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, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $25.7 million, $22.1 million and $75.8 million, under these PPAs for the three years ended Dec. 31, 2014, 2013 and 2012, 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

Discontinued Operations	12 Months Ended
Discontinued Operations	Dec. 31, 2014
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations	19. Discontinued Operations
	TECO Coal
	On Sept. 29, 2014, the Board of Directors of TECO Energy authorized management to enter into negotiations for 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 at Sept. 30, 2014, which for the third quarter 2014 included a pretax $98.4 million impairment charge related to the held-for-sale TECO Coal assets (see Note 20 for further information regarding the impairment charge).
	On Oct. 17, 2014, TECO Diversified entered into an SPA to sell all of its ownership interest in TECO Coal to Cambrian Coal Corporation for $120 million plus contingent payments of up to $50 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. On Dec. 24, 2014, the SPA was amended to extend the closing date to Feb. 20, 2015. As reported in Note 23, on Feb. 5, 2015, the SPA was further amended to extend the closing date to Mar. 13, 2015 and modify the purchase price to $80 million, subject to working capital adjustments, plus contingent payments of up to $60 million. As a result of the amended purchase price an additional pretax $17.5 million impairment charge related to the held-for-sale TECO Coal assets was recorded in discontinued operations in the fourth quarter 2014, which resulted in a total pretax impairment charge of $115.9 million for the year ended Dec. 31, 2014 (see Note 20).
	The SPA contains customary representations, warranties, covenants, and closing conditions, including the purchaser’s obtaining debt financing in order to pay a portion of the purchase price. The SPA also contains indemnification provisions subject to specified limitations as to time and amount. In addition, the SPA, as amended, is subject to termination by either party if specified closing conditions are not met by Mar. 13, 2015. After closing of the sale, TECO Energy will not have influence over operations of TECO Coal, therefore the contingent payments and indemnification provisions are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.
	All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain fourth quarter 2014 charges at Parent that directly relate to the sale of TECO Coal.
	The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

	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
	On Aug. 7, 2012, TECO Energy received an offer from Renewable Energy Investments Guatemala Limited (REIN), a wholly-owned subsidiary of Sur Eléctrica Holding Limited (SUR), to purchase the independent power projects in Guatemala and certain affiliated Guatemala companies. On Sept. 27, 2012, an indirect wholly-owned subsidiary of TECO Energy, Inc., TECO Guatemala Holdings II, LLC (TGH), entered into an equity purchase agreement with SUR, and two equity purchase agreements with REIN (the three equity purchase agreements are collectively referred to herein as the “PAs”). Pursuant to the PA with SUR, TGH agreed to sell all of its ownership interests in TPS Guatemala One, Ltd. (TPS GO) for $12.5 million, and pursuant to the PAs with REIN, it agreed to sell all of its ownership interests in (i) TPS San José International, Inc. (TPS SJI) for $213.5 million and (ii) TECO Guatemala Services, Ltd. (TGS) for $1.5 million (TPS GO, TPS SJI and TGS are collectively referred to herein as the Disposal Group). The companies in the Disposal Group were the ultimate parent companies of TCAE, CGESJ, TEMSA, and TPS Operaciones de Guatemala, Limitada (TPSO), the owner of certain local real estate assets and the employer of the local employees. The total purchase price for the Disposal Group under the PAs was $227.5 million.
	The sale of TPS GO, which owned 96.06% of TCAE, closed on Sept. 27, 2012. An affiliate of the party that controlled the remaining interest in TCAE (the “noncontrolling interest holder”) held certain contractual rights with respect to TEMSA and CGESJ, including a right of first offer. The noncontrolling interest holder was also granted the opportunity to purchase TGS since the operations of TPSO were integral to the operations of TEMSA and CGESJ. The noncontrolling interest holder exercised the right of first offer for TPS SJI and elected to purchase TGS by executing PAs similar to the PAs with REIN on Oct. 17, 2012 and Oct. 26, 2012, respectively. The sales of TPS SJI and TGS to the noncontrolling interest holder closed on Dec. 19, 2012.
	The PAs contain customary representations, warranties, covenants and indemnification provisions subject to specified limitations as to time and amount. As a result of the PAs, the TECO Guatemala segment was accounted for as a discontinued operation beginning in the third quarter of 2012. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain items at Parent that directly relate to TECO Guatemala.
	Net proceeds from the sale of all Guatemalan operations, after transaction-related costs and the $25.3 million repayment of the San José power station project debt, were approximately $197.0 million. The sale resulted in an after-tax book loss and an after-tax charge associated with foreign tax credits of $28.6 million and $22.9 million, respectively.
	The provision for income taxes line item related to TECO Guatemala in the table below includes an after-tax charge of $22.9 million in 2012 associated with foreign tax credits. The 2012 charge is a result of the sales of the Disposal Group which eliminate future foreign source income that would be required to utilize these credits.
	As reported in Note 12, 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.
	Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.
	Combined components of income from discontinued operations attributable to TECO Energy
	The following table provides selected components of discontinued operations related to TECO Coal and TECO Guatemala:

	Components of income from discontinued operations attributable to TECO Energy
	(millions)		2014			2013			2012
	Revenues—TECO Coal		$	443.6		$	496.2		$	608.9
	Revenues—TECO Guatemala			0			0			114.2
	Income (loss) from operations—TECO Coal			(13.9	)		5.4			66
	Income (loss) from operations—TECO Guatemala			4.4			(0.2	)		27.7
	Loss on impairment—TECO Coal			(115.9	)		0			0
	Loss on assets sold, including transaction costs—TECO Guatemala			0			0			(38.3	)
	Income (loss) from discontinued operations—TECO Coal			(129.8	)		5.4			66
	Income (loss) from discontinued operations—TECO Guatemala			4.4			(0.2	)		(10.6	)
	Income (loss) from discontinued operations			(125.4	)		5.2			55.4
	Provision (benefit) for income taxes			(49.4	)		(3.8	)		39.4
	Income (loss) from discontinued operations, net			(76.0	)		9			16
	Less: Income from discontinued operations attributable to noncontrolling interest			0			0			0.3
	Income (loss) from discontinued operations attributable to TECO Energy, net		$	(76.0	)	$	9		$	15.7

Goodwill_and_Asset_Impairments

Goodwill and Asset Impairments	12 Months Ended
Goodwill and Asset Impairments	Dec. 31, 2014
Goodwill And Asset Impairments Disclosure [Abstract]
Goodwill and Asset Impairments	20. Goodwill and Asset Impairments
	In 2012, the company recorded impairment charges to write down TECO Guatemala’s goodwill and long-lived asset balances to their implied fair values prior to selling TECO Guatemala and writing off the remaining balances. In 2014, the company recorded goodwill related to the acquisition of NMGI. Also in 2014, the company recorded impairment charges to write down TECO Coal’s assets to their implied fair values based on a binding offer less estimated costs to sell (see Note 19 for further information on the SPA). None of these impairments had cash flow impacts. See the Consolidated Statements of Cash Flows Asset impairment line item. Further detail is provided below.
	The following table presents the changes in the carrying amount of goodwill related to TECO Guatemala and NMGC for the years ended Dec. 31, 2014, 2013 and 2012.

								Total TECO
	(millions)	TPS GO			TPS SJI			Guatemala			NMGC		Total
	Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4		$	0	$	55.4
	Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)		0		(15.2	)
	Goodwill written off upon sale, pretax		0			(40.2	)		(40.2	)		0		(40.2	)
	Balance as of Dec. 31, 2012	$	0		$	0		$	0		$	0	$	0
	Balance as of Dec. 31, 2013	$	0		$	0		$	0		$	0	$	0
	Acquisition of NMGC		0			0			0			408.3		408.3
	Balance as of Dec. 31, 2014	$	0		$	0		$	0		$	408.3	$	408.3
	Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. TECO Energy reviews recorded goodwill at least annually during the fourth quarter for each reporting unit.
	New Mexico Gas Company
	At Dec. 31, 2014, the company had $408.3 million of goodwill on its balance sheet, which is reflected in the NMGC segment. 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 using a weighted combination of a discounted cash flow analysis, a comparable transaction analysis, and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, rate case assumptions, utility sector market performance and transactions, projected operating and capital cash flows for NMGC’s business and the fair value of debt. The company determined the fair value of NMGC supports the book value and related goodwill carrying amounts at Dec. 31, 2014, resulting in no impairment charge.
	TECO Guatemala
	The goodwill formerly on the company’s balance sheet related to the TECO Guatemala segment and arose from the purchase of multiple entities as a result of the company’s investments in the Alborada (held by TPS GO) and San José (held by TPS SJI) power plants. Since these reporting units were one level below the operating segment level, discrete cash flow information was available, and management regularly reviewed their operating results separately, these were the reporting unit level at which potential impairment was tested.
	Prior to the sales in 2012 (see Note 19), goodwill balances for the TPS GO and TPS SJI reporting units were written down to their implied fair values calculated using the offers from SUR and REIN. Although these were binding quoted prices, the fair value measurements were considered Level 2 measurements since the market was not active as defined by accounting standards (i.e. transactions for these assets were too infrequent to provide pricing information on an ongoing basis). Prior to receiving the offers from REIN and SUR, the fair values of TPS GO’s and TPS SJI’s goodwill amounts were calculated using the discounted cash flows appropriate for the business model of each reporting unit. Discounted cash flows were formerly the best estimates of fair value of the reporting units, since neither a sale nor a similar transaction was readily observed in the marketplace for many years due to an inactive market.
	The Impairment losses, pretax and Goodwill written off upon sale, pretax amounts in the goodwill table above are reflected in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012.
	Prior to the sale of TGS, the company recorded a long-lived asset pretax impairment charge of $2.0 million. This amount is 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 year ended Dec. 31, 2012. The fair value was calculated using the offer from REIN. Although it was a binding quoted price, the fair value measurement was considered a Level 2 measurement since the market was not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis).
	TECO Coal
	In both 2012 and 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in each fourth quarter 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 2012 and 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.
	On Sept. 29, 2014, the Board of Directors of TECO Energy authorized management to enter into negotiations for the sale of TECO Coal (see Note 19). As a result of the anticipated agreement price of $120 million, a pretax $98.4 million asset impairment charge related to the TECO Coal assets was recorded in the third quarter of 2014. On Feb. 5, 2015,the company announced that it had entered into a second amendment to the SPA that was signed in October 2014. The second amendment reduced the purchase price to $80 million. Based on this purchase price reduction and changes that occurred in the fourth quarter to TECO’s investment in TECO Coal, an additional pretax impairment charge of $17.5 million was taken in the fourth quarter, which resulted in a total pretax impairment charge of $115.9 million for the year ended Dec. 31, 2014. These charges represent the write down to TECO Coal’s implied fair value of the then-binding offer and the current SPA purchase price less estimated costs to sell. Although the offer used in the analysis was a binding offer and the SPA is a contracted price, the fair value measurements are considered a 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). 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 year ended Dec. 31, 2014.

Acquisition_of_New_Mexico_Gas_

Acquisition of New Mexico Gas Company	12 Months Ended
Acquisition of New Mexico Gas Company	Dec. 31, 2014
Business Combinations [Abstract]
Acquisition of New Mexico Gas Company	21. Acquisition of New Mexico Gas Company
	Description of Transaction
	On Sept. 2, 2014, the company completed the acquisition contemplated by the SPA 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 the first year after the close of the transaction, which will increase to $4 million per year 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
	Total consideration transferred, excluding cash and working capital adjustments		$	950
	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 will be recorded related to this portion of the goodwill.
	The valuations performed in the third quarter of 2014 to determine the fair value of the assets acquired and liabilities assumed were updated in the fourth quarter of 2014. The updates primarily related to property, plant and equipment that was written off and changes in the valuation of certain liabilities related to employee benefits. These updates increased the amount of goodwill acquired by approximately $6.5 million. Although the allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed, we do not anticipate any material adjustments to the fair value assessments subsequent to Dec. 31, 2014.
	The purchase price allocation of the acquisition of NMGI and NMGC is as follows:

	Purchase Price Allocation
	(millions)
	Current assets (a)		$	48.7
	Property, plant and equipment			616.5
	OPEB regulatory asset			6.4
	Debt-related regulatory asset			23.9
	Goodwill			408.3
	Deferred tax assets			52.8
	Other assets			29.3
	Total assets		$	1,185.90
	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
	(a)	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 year ended Dec. 31, 2014 was an increase of $137.5 million. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the year ended Dec. 31, 2014 was an increase of $8.2 million.
	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 year ending Dec. 31,
	(millions, except per share amounts)		2014				2013
Revenues		$	2,806.60			$	2,704.00
Net income from continuing operations			223.8				216.8
Basic and diluted EPS from continuing operations			0.96				0.93
Goodwill
Goodwill resulting from the acquisition was allocated entirely to the NMGC segment. The goodwill related to the formation of NMGC in 2009 in the amount of $146.1 million is tax deductible. The incremental goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes will be recorded related to this portion of the goodwill.


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 year ended Dec. 31, 2014.

Transaction and Integration Costs
(millions)		Total
Legal and other consultants		$	8
Bridge loan costs			3.3
Severance and relocation costs			2.8
Other costs and tax benefit			(5.5	)
Total accounting charges		$	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 or regulatory asset 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 will continue through 2015. 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, 2014, the obligations associated with the severance benefits costs are $2.6 million.

Quarterly_Data_unaudited

Quarterly Data (unaudited)	12 Months Ended
Quarterly Data (unaudited)	Dec. 31, 2014
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		30-Jun		Mar. 31
	2014
	Revenues	$	695.5	$	687.2	$	605.7	$	578
	Income from operations		112.1		145.7		132		115.6
	Net income from continuing operations		27.4		73		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	$	0.22	$	0.22	$	0.22	$	0.22

	Quarter ended	Dec. 31		Sept. 30		30-Jun		Mar. 31
	2013
	Revenues	$	562.2	$	642.1	$	607.5	$	543.3
	Income from operations		95		141.7		118.1		99.8
	Net income from continuing operations		35.4		64.3		50.7		38.3
	Net income		42		62.8		51.4		41.5
	EPS—Basic
	Net income from continuing operations	$	0.17	$	0.3	$	0.24	$	0.17
	Net income		0.2		0.29		0.24		0.19
	EPS—Diluted
	Net income from continuing operations	$	0.17	$	0.3	$	0.24	$	0.17
	Net income		0.2		0.29		0.24		0.19
	Dividends paid per common share outstanding	$	0.22	$	0.22	$	0.22	$	0.22
	Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events	23. Subsequent Events
	Tampa Electric Company Accounts Receivable Facility
	On Feb. 3, 2015, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 13 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment extends the maturity date to Apr. 14, 2015.
	Amendment to TECO Coal SPA
	On Feb. 5, 2015, TECO Diversified entered into Amendment No. 2 (the Amendment) to the SPA dated as of Oct. 17, 2014, as amended, with Cambrian Coal Corporation. As disclosed in Note 19, the SPA related to the sale of all of the ownership interest in TECO Coal to Cambrian Coal Corporation, and was subject to termination by either party if specified closing conditions, including the purchaser’s obtaining financing in order to pay a portion of the purchase price, were not met by Feb. 20, 2015 (Outside Date). The Amendment (i) reduces the purchase price to $80 million plus any cash on hand as of the closing, subject to customary post-closing adjustments, plus contingent payments of up to $60 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices and (ii) extends the Outside Date by providing that the SPA, as amended, is subject to termination by either party if the specified closing conditions (including the purchaser’s obtaining financing) are not met by Mar. 13, 2015.

Tampa Electric Company [Member]
Subsequent Events	16. Subsequent Events
	On Feb. 3, 2015, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 13 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment extends the maturity date to Apr. 14, 2015.

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts and Reserves	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012
	(millions)

			Balance at		Additions							Balance at
			Beginning		Charged to		Other		Payments &			End of
			of Period		Income		Charges		Deductions			Period
	Allowance for Uncollectible Accounts:
	2014		$	4.7	$	1.4	$	0.7	$	4.7	-1	$	2.1
	2013		$	4.2	$	3.3	$	0	$	2.8	-1	$	4.7
	2012		$	2.6	$	4.8	$	0	$	3.2	-1	$	4.2

	Deferred Tax Valuation Allowance:
	2014		$	0	$	4.6	$	0	$	0		$	4.6
	2013		$	3	$	0	$	0	$	3	-2	$	0
	2012		$	9.7	$	1.1	$	0	$	7.8	-2	$	3


	-1	Write-off of individual bad debt accounts
	-2	Valuation allowance is no longer required



	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	TAMPA ELECTRIC COMPANY
	VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	For the Years Ended Dec. 31, 2014, 2013 and 2012
	(millions)

			Balance at		Additions							Balance at
			Beginning		Charged to		Other		Payments &			End of
			of Period		Income		Charges		Deductions (1)			Period
	Allowance for Uncollectible Accounts:
	2014		$	2	$	2.7	$	0	$	3.3		$	1.4
	2013		$	1.5	$	3.3	$	0	$	2.8		$	2
	2012		$	1.3	$	3.4	$	0	$	3.2		$	1.5


	-1	Write-off of individual bad debt accounts

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Reclassifications	ERROR: Could not retrieve Word content for note block
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 as of the acquisition date of Sept. 2, 2014 (see Note 21). In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at TECO Energy that are directly related to TECO Coal (see Note 19).
	For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority 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).
Use of Estimates	Use of Estimates
	The use of estimates is inherent in the preparation of financial statements in accordance with 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.
Planned Major Maintenance	Planned Major Maintenance
	Tampa Electric, PGS and NMGC expense major maintenance costs as incurred. For electric and gas utilities, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC, FPSC and NMPRC, as applicable.
	Planned major maintenance projects at TECO Coal that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.
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 (including NMGC from the acquisition date), expressed as a percentage of the original cost of depreciable property, was 3.6% for 2014, 3.7% for 2013 and 3.8% for 2012.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC 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		5 - 40 years

	Office equipment and furniture		3 - 30 years

	Vehicles and other equipment		2 - 15 years

	Computer software		2 - 15 years
	Total depreciation expense for the years ended Dec. 31, 2014, 2013 and 2012 was $307.5 million, $285.6 million and $276.3 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 2014 was 4.92%. Total AFUDC for the years ended Dec. 31, 2014, 2013 and 2012 was $15.8 million, $9.9 million and $4.1 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. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory is classified within Assets held for sale at Dec. 31, 2014.

	Fuel Inventory		Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Tampa Electric		$	85.2	$	93.7
	TECO Coal			0		25
	NMGC			11.2		0
	Total		$	96.4	$	118.7

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 for additional details).
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 for additional details).
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 for further detail.
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 for further detail.
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 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
	Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer. They are included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.
	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, 2014, 2013 and 2012, total costs of $4.3 million, $23.1 million and $13.8 million, respectively, consisting primarily of natural gas purchased, were netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income.
Shipping and Handling	Shipping and Handling
	TECO Coal incurred costs to ship product to customers of $5.2 million, $8.2 million and $9.0 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The costs are included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.
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.
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, gas storage, interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
	Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2014 and 2013, unbilled revenues of $86.6 million and $46.7 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $71.4 million, $64.7 million and $105.3 million, for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts	Accounting for Excise Taxes, Franchise Fees and Gross Receipts
	TECO Coal incurs most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.
	Tampa Electric and PGS are allowed to recover certain costs on a dollar-per-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 $113.9 million, $108.5 million and $111.5 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes, and they are 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.
Deferred Charges and Other Assets	Deferred Charges and Other Assets
	Deferred charges and other assets consist primarily of offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense, as well as mining development costs amortized on a per ton basis in 2013 and assets related to NMGC’s ROW in 2014. The mining development costs were impaired in 2014. See Notes 20 and 21 for additional information on the impairment and ROW, respectively.
	Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet 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.
Deferred Credits and Other Liabilities	Deferred Credits and Other Liabilities
	Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2014 and 2013 ranged from 2.71% to 3.86% and 3.51% to 4.86%, respectively.
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, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.
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 consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.
Tampa Electric Company [Member]
Reclassifications	ERROR: Could not retrieve Word content for note block
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.
Planned Major Maintenance	Planned Major Maintenance
	Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.
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 2014, 3.7% for 2013 and 3.8% for 2012. 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, 2014, 2013 and 2012 was $295.8 million, $284.2 million and $275.1 million, respectively.
	On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC 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, 2014, 2013 and 2012 was $15.6 million, $9.9 million and $4.1 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 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
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.
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). As of Dec. 31, 2014 and 2013, unbilled revenues of $49.3 million and $46.7 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.
	Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $71.4 million, $64.7 million and $105.3 million, for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.
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-per-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 $113.9 million, $108.5 million and $111.5 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.
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 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.
	TEC’s retail and wholesale businesses are regulated by the FPSC and related 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 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 minority 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).

Employee_Postretirement_Benefi1

Employee Postretirement Benefits (Tables)	12 Months Ended
Employee Postretirement Benefits (Tables)	Dec. 31, 2014
Schedule of Change in Plan Assets
	Change in plan assets
	Fair value of plan assets at beginning of year		$	593			$	529.1			$	0			$	0
	Actual return on plan assets			46.4				63.7				0.1				0
	Employer contributions			47.5				44.6				(1.0	)			11.9
	Employer direct benefit payments			1				1.3				16
	Plan participants’ contributions			0				0				2.8				2.9
	Transfer in due to acquisition			0				0				16.9				0
	Settlements			0				(2.6	)			0				0
	Net benefits paid			(39.9	)			(43.1	)			(16.0	)			(14.8	)
	Fair value of plan assets at end of year		$	648			$	593			$	18.8			$	0

Schedule of Change in Benefit Obligation
	Obligations and Funded Status		Pension Benefits								Other Benefits
	(millions)		2014				2013				2014				2013
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	666			$	715			$	208.1			$	230.3
	Service cost			18.3				18.2				2.5				2.5
	Interest cost			32				28.9				10.8				9.3
	Plan participants’ contributions			0				0				2.8				2.9
	Plan amendments			0				0				(23.2	)			0
	Actuarial loss (gain)			48.3				(50.4	)			1.5				(22.1	)
	Gross benefits paid			(39.9	)			(43.1	)			(16.0	)			(15.0	)
	Transfer in due to the effect of business combination			0				0				26.7				0
	Plan curtailment			4				0				(11.7	)			0
	Special termination benefit			0.2				0				0				0
	Settlements			0				(2.6	)			0				0
	Federal subsidy on benefits paid		n/a				n/a					0				0.2
	Net benefit obligation at end of year		$	728.9			$	666			$	201.5			$	208.1

Schedule of Funded status
	Funded status
	Fair value of plan assets (1)		$	648			$	593			$	18.8			$	0
	Less: Benefit obligation (PBO/APBO)			728.9				666				201.5				208.1
	Funded status at end of year			(80.9	)			(73.0	)			(182.7	)			(208.1	)
	Unrecognized costs in regulated asset acquired in business combination			0				0				6.4				0
	Unrecognized net actuarial loss			203.7				173.1				9.6				19.7
	Unrecognized prior service (benefit) cost			0				(0.4	)			(24.0	)			(0.7	)
	Net amount required to be recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

	-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.
Schedule of Amount Recognized in Balance Sheet
	Amounts recognized in balance sheet
	Regulatory assets		$	167.4			$	139.6			$	26.6			$	43.2
	Accrued benefit costs and other current liabilities			(4.9	)			(3.3	)			(10.7	)			(13.3	)
	Deferred credits and other liabilities			(76.0	)			(69.7	)			(172.0	)			(194.8	)
	Accumulated other comprehensive loss (income), pretax			36.3				33.1				(34.6	)			(24.2	)
	Net amount recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax	Amounts recognized in accumulated other comprehensive income, pretax

			Pension Benefits								Other Benefits
	(millions)		2014				2013				2014				2013
	Net actuarial loss (gain)		$	36			$	32.7			$	(30.1	)		$	(23.8	)
	Prior service cost (credit)			0.3				0.4				(4.5	)			(0.4	)
	Amount recognized, pretax		$	36.3			$	33.1			$	(34.6	)		$	(24.2	)

Schedule of Net Periodic Benefit Cost	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
			2014				2013				2012				2014			2013			2012

	Service cost		$	18.3			$	18.2			$	17			$	2.5		$	2.5		$	2.4
	Interest cost			32				28.9				30.1				10.8			9.3			10.1
	Expected return on plan assets			(41.8	)			(38.4	)			(37.1	)			(0.3	)		0			0
	Amortization of:
	Actuarial loss			13.5				20.5				15.3				0.2			1			0.1
	Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)			(0.2	)		(0.4	)		0.8
	Transition obligation			0				0				0				0			0			1.8
	Curtailment loss (gain)			3.9				0				0				(0.2	)		0			0
	Special termination benefit			0.2				0				0				0			0			0
	Settlement loss			0				1				0				0			0			0
	Net periodic benefit cost		$	25.7			$	29.8			$	24.9			$	12.8		$	12.4		$	15.2

	Prior service cost		$	0			$	0			$	0			$	(23.6	)	$	0		$	(5.2	)
	Net loss (gain)			44.1				(75.7	)			34				(9.9	)		(15.6	)	16.3
	Unrecognized costs in regulated asset acquired in business combination			0				0				0				6.4			0			0
	Amortization of:
	Actuarial gain (loss)			(13.5	)			(21.5	)			(15.3	)			(0.2	)		(1.0	)		(0.1	)
	Prior service (benefit) cost		0.4					0.4				0.4				0.2			0.3			(0.8	)
	Transition obligation			0				0				0				0			0			(1.8	)
	Total recognized in OCI and regulatory assets		$	31			$	(96.8	)		$	19.1			$	(27.1	)	$	(16.3	)	$	8.4
	Total recognized in net periodic benefit cost, OCI and regulatory assets		$	56.7			$	(67.0	)		$	44			$	(14.3	)	$	(3.9	)	$	23.6


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						2014				2013
	Equity securities		48%-54%					50	%			54	%
	Fixed income securities		46%-52%					50	%			46	%
	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, 2014 and Dec. 31, 2013.

	(millions)		At Fair Value as of Dec. 31, 2014
			Level 1				Level 2				Level 3				Total
	Cash		$	0.4			$	0			$	0			$	0.4
	Accounts receivable			1.4				0				0				1.4
	Accounts payable			(5.3	)			0				0				(5.3	)
	Cash equivalents
	Short term investment funds (STIFs)			7.6				0				0				7.6
	Treasury bills (T bills)			0				0.2				0				0.2
	Discounted notes			0				8.8				0				8.8
	Total cash equivalents			7.6				9				0				16.6
	Equity securities
	Common stocks			98				0				0				98
	American depository receipts (ADRs)			1.3				0				0				1.3
	Real estate investment trusts (REITs)			2.5				0				0				2.5
	Preferred stock			0.8				0				0				0.8
	Mutual funds			171.3				0				0				171.3
	Commingled fund			0				45.6				0				45.6
	Total equity securities			273.9				45.6				0				319.5
	Fixed income securities
	Municipal bonds			0				6.1				0				6.1
	Government bonds			0				47.9				0				47.9
	Corporate bonds			0				22				0				22
	Asset backed securities (ABS)			0				0.3				0				0.3
	Mortgage-backed securities (MBS), net short sales			0				9.6				0				9.6
	Collateralized mortgage obligations (CMOs)			0				2				0				2
	Mutual fund			0				98.6				0				98.6
	Commingled fund			0				129.2				0				129.2
	Total fixed income securities			0				315.7				0				315.7
	Derivatives
	Short futures			0				(0.3	)			0				(0.3	)
	Purchased options (swaptions)			0				0.7				0				0.7
	Written options (swaptions)			0				(0.8	)			0				(0.8	)
	Total derivatives			0				(0.4	)			0				(0.4	)
	Miscellaneous			0				0.1				0				0.1
	Total		$	278			$	370			$	0			$	648

	(millions)		At Fair Value as of Dec. 31, 2013
			Level 1				Level 2				Level 3				Total
	Accounts receivable		$	44.7			$	0			$	0			$	44.7
	Accounts payable			(40.8	)			0				0				(40.8	)
	Cash equivalents
	Short term investment funds (STIFs)			7.9				0				0				7.9
	Treasury bills (T bills)			0				0.3				0				0.3
	Repurchase agreement			0				8.8				0				8.8
	Commercial paper			0				0.4				0				0.4
	Money markets			0				1.5				0				1.5
	Total cash equivalents			7.9				11				0				18.9
	Equity securities
	Common stocks			91.6				0				0				91.6
	American depository receipts (ADRs)			3				0				0				3
	Real estate investment trusts (REITs)			1.7				0				0				1.7
	Preferred stock			0				0.8				0				0.8
	Mutual funds			172.6				0				0				172.6
	Commingled fund			0				50				0				50
	Total equity securities			268.9				50.8				0				319.7
	Fixed income securities
	Municipal bonds			0				7.3				0				7.3
	Government bonds			0				35.7				0				35.7
	Corporate bonds			0				19.6				0				19.6
	Asset backed securities (ABS)			0				0.4				0				0.4
	Mortgage-backed securities (MBS), net short sales			0				6.7				0				6.7
	Collateralized mortgage obligations (CMOs)			0				2.3				0				2.3
Mutual fund			0				85.1				0				85.1
Commingled fund			0				94.1				0				94.1
Total fixed income securities			0				251.2				0				251.2
Derivatives
Short futures			0				0.2				0				0.2
Swaps			0				(0.9	)			0				(0.9	)
Purchased options (swaptions)			0				0.2				0				0.2
Written options (swaptions)			0				(0.4	)			0				(0.4	)
Total derivatives			0				(0.9	)			0				(0.9	)
Miscellaneous			0				0.2				0				0.2
Total		$	280.7			$	312.3			$	0			$	593
-1	The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
-2	The STIF is valued at net asset value (NAV) as determined by JP Morgan. 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, making this a Level 1 asset.
-3	The primary pricing inputs in determining the Level 1 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, making these Level 1 assets.
-4	The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
-5	T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
-6	The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
-7	The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
-8	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 CMOs 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. Commercial MBS are priced using payment information and yields.
-9	The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
-10	The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. 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 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
-11	Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.
-12	Swaps are valued using benchmark yields, swap curves, and cash flow analyses.
-13	Options are valued using the bid-ask spread and the last price.
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
	2015		$	73.4			$	11.5
	2016			47.9				12
	2017			47.8				12.5
	2018			51.9				12.9
	2019			58.3				13.4
	2020-2024			285.5				69.5

Benefit Obligations [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at Dec. 31:

			Pension Benefits								Other Benefits
			2014				2013				2014				2013
	Discount rate			4.258	%			5.118	%			4.211	%			5.096	%
	Rate of compensation increase—weighted			3.87	%			3.73	%			3.86	%			3.71	%
	Healthcare cost trend rate
	Immediate rate		n/a				n/a					7.09	%			7.25	%
	Ultimate rate		n/a				n/a					4.57	%			4.5	%
	Year rate reaches ultimate		n/a				n/a				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 the benefit obligation:

				1%				1%
	(millions)		Increase				Decrease
	Effect on postretirement benefit obligation		$	7			$	(6.4	)

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
			2014 (a)				2013				2012				2014			2013			2012
	Discount rate		5.118%/4.277%/4.331%					4.196	%			4.797	%			5.096	%		4.18	%		4.744	%
	Expected long-term return on plan assets		7.25%/7.00%/7.00%					7.5	%			7.5	%			5.75		n/a			n/a
	Rate of compensation increase			3.73	%			3.76	%			3.83	%			3.71	%		3.74	%		3.82	%
	Healthcare cost trend rate
	Initial rate		n/a				n/a				n/a					7.25	%		7.5	%		7.75	%
	Ultimate rate		n/a				n/a				n/a					4.5	%		4.5	%		4.5	%
	Year rate reaches ultimate		n/a				n/a				n/a				2025			2025			2025
	·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.

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			$	(0.4	)

TECO Energy [Member]
Schedule of Change in Plan Assets	ERROR: Could not retrieve Word content for note block
Schedule of Change in Benefit Obligation	TECO Energy		Pension Benefits								Other Benefits
	Obligations and Funded Status
	(millions)		2014				2013				2014				2013
	Change in benefit obligation
	Net benefit obligation at beginning of year		$	666			$	715			$	208.1			$	230.3
	Service cost			18.3				18.2				2.5				2.5
	Interest cost			32				28.9				10.8				9.3
	Plan participants’ contributions			0				0				2.8				2.9
	Plan amendments			0				0				(23.2	)			0
	Actuarial loss (gain)			48.3				(50.4	)			1.5				(22.1	)
	Gross benefits paid			(39.9	)			(43.1	)			(16.0	)			(15.0	)
	Transfer in due to the effect of business combination			0				0				26.7				0
	Plan curtailment			4				0				(11.7	)			0
	Special termination benefit			0.2				0				0				0
	Settlements			0				(2.6	)			0				0
	Federal subsidy on benefits paid		n/a				n/a					0				0.2
	Net benefit obligation at end of year		$	728.9			$	666			$	201.5			$	208.1

Schedule of Funded status	Funded status
	Fair value of plan assets (1)		$	648			$	593			$	18.8			$	0
	Less: Benefit obligation (PBO/APBO)			728.9				666				201.5				208.1
	Funded status at end of year			(80.9	)			(73.0	)			(182.7	)			(208.1	)
	Unrecognized costs in regulated asset acquired in business combination			0				0				6.4				0
	Unrecognized net actuarial loss			203.7				173.1				9.6				19.7
	Unrecognized prior service (benefit) cost			0				(0.4	)			(24.0	)			(0.7	)
	Net amount required to be recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

	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.
Schedule of Amount Recognized in Balance Sheet	Amounts recognized in balance sheet
	Regulatory assets		$	167.4			$	139.6			$	26.6			$	43.2
	Accrued benefit costs and other current liabilities			(4.9	)			(3.3	)			(10.7	)			(13.3	)
	Deferred credits and other liabilities			(76.0	)			(69.7	)			(172.0	)			(194.8	)
	Accumulated other comprehensive loss (income), pretax			36.3				33.1				(34.6	)			(24.2	)
	Net amount recognized at end of year		$	122.8			$	99.7			$	(190.7	)		$	(189.1	)

Schedule of Net Periodic Benefit Cost	Amounts recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets

	TECO Energy		Pension Benefits												Other Benefits
			2014				2013				2012				2014			2013			2012
	(millions)
	Service cost		$	18.3			$	18.2			$	17			$	2.5		$	2.5		$	2.4
	Interest cost			32				28.9				30.1				10.8			9.3			10.1
	Expected return on plan assets			(41.8	)			(38.4	)			(37.1	)			(0.3	)		0			0
	Amortization of:
	Actuarial loss			13.5				20.5				15.3				0.2			1			0.1
	Prior service (benefit) cost			(0.4	)			(0.4	)			(0.4	)			(0.2	)		(0.4	)		0.8
	Transition obligation			0				0				0				0			0			1.8
	Curtailment loss (gain)			3.9				0				0				(0.2	)		0			0
	Special termination benefit			0.2				0				0				0			0			0
	Settlement loss			0				1				0				0			0			0
	Net periodic benefit cost		$	25.7			$	29.8			$	24.9			$	12.8		$	12.4		$	15.2

	Prior service cost		$	0			$	0			$	0			$	(23.6	)	$	0		$	(5.2	)
	Net loss (gain)			44.1				(75.7	)			34				(9.9	)		(15.6	)	16.3
	Unrecognized costs in regulated asset acquired in business combination			0				0				0				6.4			0			0
	Amortization of:
	Actuarial gain (loss)			(13.5	)			(21.5	)			(15.3	)			(0.2	)		(1.0	)		(0.1	)
	Prior service (benefit) cost		0.4					0.4				0.4				0.2			0.3			(0.8	)
	Transition obligation			0				0				0				0			0			(1.8	)
	Total recognized in OCI and regulatory assets		$	31			$	(96.8	)		$	19.1			$	(27.1	)	$	(16.3	)	$	8.4
	Total recognized in net periodic benefit cost, OCI and regulatory assets		$	56.7			$	(67.0	)		$	44			$	(14.3	)	$	(3.9	)	$	23.6

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 Allocation, End of Year
	Asset Category						2014				2013
	Equity securities		48%-54%					50	%			54	%
	Fixed income securities		46%-52%					50	%			46	%
	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, 2014 and 2013.
	Pension Plan Investments

	(millions)		At Fair Value as of Dec. 31, 2014
			Level 1				Level 2				Level 3				Total
	Cash		$	0.4			$	0			$	0			$	0.4
	Accounts receivable			1.4				0				0				1.4
	Accounts payable			(5.3	)			0				0				(5.3	)
	Cash equivalents
	Short term investment funds (STIFs)			7.6				0				0				7.6
	Treasury bills (T bills)			0				0.2				0				0.2
	Discounted notes			0				8.8				0				8.8
	Total cash equivalents			7.6				9				0				16.6
	Equity securities
	Common stocks			98				0				0				98
	American depository receipts (ADRs)			1.3				0				0				1.3
	Real estate investment trusts (REITs)			2.5				0				0				2.5
	Preferred stock			0.8				0				0				0.8
	Mutual funds			171.3				0				0				171.3
	Commingled fund			0				45.6				0				45.6
	Total equity securities			273.9				45.6				0				319.5
	Fixed income securities
	Municipal bonds			0				6.1				0				6.1
	Government bonds			0				47.9				0				47.9
	Corporate bonds			0				22				0				22
	Asset backed securities (ABS)			0				0.3				0				0.3
	Mortgage-backed securities (MBS), net short sales			0				9.6				0				9.6
	Collateralized mortgage obligations (CMOs)			0				2				0				2
	Mutual fund			0				98.6				0				98.6
	Commingled fund			0				129.2				0				129.2
	Total fixed income securities			0				315.7				0				315.7
	Derivatives
	Short futures			0				(0.3	)			0				(0.3	)
	Purchased options (swaptions)			0				0.7				0				0.7
	Written options (swaptions)			0				(0.8	)			0				(0.8	)
	Total derivatives			0				(0.4	)			0				(0.4	)
	Miscellaneous			0				0.1				0				0.1
	Total		$	278			$	370			$	0			$	648



	Pension Plan Investments

	(millions)		At Fair Value as of Dec. 31, 2013
			Level 1				Level 2				Level 3				Total
	Accounts receivable		$	44.7			$	0			$	0			$	44.7
	Accounts payable			(40.8	)			0				0				(40.8	)
	Cash equivalents
	Short term investment funds (STIFs)			7.9				0				0				7.9
	Treasury bills (T bills)			0				0.3				0				0.3
	Repurchase agreement			0				8.8				0				8.8
	Commercial paper			0				0.4				0				0.4
	Money markets			0				1.5				0				1.5
	Total cash equivalents			7.9				11				0				18.9
	Equity securities
	Common stocks			91.6				0				0				91.6
	American depository receipts (ADRs)			3				0				0				3
	Real estate investment trusts (REITs)			1.7				0				0				1.7
	Preferred stock			0				0.8				0				0.8
	Mutual funds			172.6				0				0				172.6
	Commingled fund			0				50				0				50
	Total equity securities			268.9				50.8				0				319.7
	Fixed income securities
	Municipal bonds			0				7.3				0				7.3
Government bonds			0				35.7				0				35.7
Corporate bonds			0				19.6				0				19.6
Asset backed securities (ABS)			0				0.4				0				0.4
Mortgage-backed securities (MBS), net short sales			0				6.7				0				6.7
Collateralized mortgage obligations (CMOs)			0				2.3				0				2.3
Mutual fund			0				85.1				0				85.1
Commingled fund			0				94.1				0				94.1
Total fixed income securities			0				251.2				0				251.2
Derivatives
Short futures			0				0.2				0				0.2
Swaps			0				(0.9	)			0				(0.9	)
Purchased options (swaptions)			0				0.2				0				0.2
Written options (swaptions)			0				(0.4	)			0				(0.4	)
Total derivatives			0				(0.9	)			0				(0.9	)
Miscellaneous			0				0.2				0				0.2
Total		$	280.7			$	312.3			$	0			$	593

·	The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.
·	The STIF is valued at net asset value (NAV) as determined by JP Morgan. 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, making this a Level 1 asset.
·	The primary pricing inputs in determining the Level 1 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, making these Level 1 assets.
·	The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.
·	T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.
·	The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.
·	The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.
·	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 CMOs 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. Commercial MBS are priced using payment information and yields.
·	The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.
·	The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. 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 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.
·	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.
Schedule of Benefit Payments	Expected Benefit Payments—TECO Energy

	(including projected service and net of employee contributions)						Other
			Pension				Postretirement
	(millions)		Benefits				Benefits
	2015		$	73.4			$	11.5
	2016			47.9				12
	2017			47.8				12.5
	2018			51.9				12.9
	2019			58.3				13.4
	2020-2024			285.5				69.5

Tampa Electric Company [Member]
Schedule of Amount Recognized in Balance Sheet	Tampa Electric Company		Pension Benefits								Other Benefits
	Amounts recognized in balance sheet
	(millions)		2014				2013				2014				2013
	Regulatory assets		$	167.4			$	139.6			$	20.4			$	43.2
	Accrued benefit costs and other current liabilities			(0.6	)			(0.9	)			(9.1	)			(10.8	)
	Deferred credits and other liabilities			(53.5	)			(50.1	)			(137.1	)			(158.3	)
			$	113.3			$	88.6			$	(125.8	)		$	(125.9	)

Tampa Electric Company [Member] \| Benefit Obligations [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at Dec. 31:

			Pension Benefits								Other Benefits
			2014				2013				2014				2013
	Discount rate			4.258	%			5.118	%			4.211	%			5.096	%
	Rate of compensation increase-weighted average			3.87	%			3.73	%			3.86	%			3.71	%
	Healthcare cost trend rate
	Immediate rate		n/a				n/a					7.09	%			7.25	%
	Ultimate rate		n/a				n/a					4.57	%			4.5	%
	Year rate reaches ultimate		n/a				n/a				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 TEC’s benefit obligation:

	(millions)		1% Increase				1 % Decrease
	Effect on postretirement benefit obligation		$	3.7			$	(3.6	)

Tampa Electric Company [Member] \| 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
			2014 (a)				2013				2012				2014			2013			2012
	Discount rate		5.118%/4.277%/4.331%					4.196	%			4.797	%			5.096	%		4.18	%		4.744	%
	Expected long-term return on plan assets		7.25%/7.00%/7.00%					7.5	%			7.5	%			5.75		n/a			n/a
	Rate of compensation increase			3.73	%			3.76	%			3.83	%			3.71	%		3.74	%		3.82	%
	Healthcare cost trend rate
	Initial rate		n/a				n/a				n/a					7.25	%		7.5	%		7.75	%
	Ultimate rate		n/a				n/a				n/a					4.5	%		4.5	%		4.5	%
	Year rate reaches ultimate		n/a				n/a				n/a				2025			2025			2025
	(a) 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.

Tampa Electric Company [Member] \| Effect on Expenses [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		$	0.3			$	(0.3	)

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
Significant Accounting Policies (Tables)	Dec. 31, 2014
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	5 - 40 years

	Office equipment and furniture	3 - 30 years

	Vehicles and other equipment	2 - 15 years

	Computer software	2 - 15 years

Schedule of Fuel Inventory
	Fuel Inventory	Dec. 31,		Dec. 31,
	(millions)	2014		2013
	Tampa Electric	$	85.2	$	93.7
	TECO Coal		0		25
	NMGC		11.2		0
	Total	$	96.4	$	118.7

Regulatory_Tables

Regulatory (Tables)	12 Months Ended
Regulatory (Tables)	Dec. 31, 2014
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Dec. 31, 2014 and 2013 are presented in the following table:

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Regulatory assets:
	Regulatory tax asset (1)		$	69.2	$	67.4
	Other:
	Cost-recovery clauses			45.1		6.1
	Postretirement benefit asset (2)			194		182.7
	Deferred bond refinancing costs (3)			7.2		8
	Debt basis adjustment (3)			20.9		0
	Environmental remediation			53.1		51.4
	Competitive rate adjustment			2.8		4.1
	Other			9.8		7.7
	Total other regulatory assets			332.9		260
	Total regulatory assets			402.1		327.4
	Less: Current portion			53.6		34.3
	Long-term regulatory assets		$	348.5	$	293.1
	Regulatory liabilities:
	Regulatory tax liability (1)		$	6.9	$	9.8
	Other:
	Cost-recovery clauses			25.9		54.5
	Transmission and delivery storm reserve			56.1		56.1
	Deferred gain on property sales (4)			0.8		2
	Accumulated reserve—cost of removal			695.2		594
	Other			1.1		0.8
	Total other regulatory liabilities			779.1		707.4
	Total regulatory liabilities			786		717.2
	Less: Current portion			57		85.8
	Long-term regulatory liabilities		$	729	$	631.4
	-1	Primarily related to plant life and derivative positions.
	-2	Amortized over the remaining service life of plan participants.
	-3	Amortized over the term of the related debt instruments.
	-4	Amortized over a 5-year period with various ending dates.
Regulatory Assets and Related Recovery Period	All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:

	Regulatory assets

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Clause recoverable (1)		$	47.9	$	10.2
	Components of rate base (2)			199		185.6
	Regulatory tax assets (3)			69.2		67.4
	Capital structure and other (3)			86		64.2
	Total		$	402.1	$	327.4
	-1	To be recovered through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year.
	-2	Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
	-3	“Regulatory tax assets” and “Capital structure and other” regulatory assets, including environmental remediation, have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.
Tampa Electric Company [Member]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Dec. 31, 2014 and 2013 are presented in the following table:
	Regulatory Assets and Liabilities

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Regulatory assets:
	Regulatory tax asset (1)		$	69.2	$	67.4
	Other:
	Cost-recovery clauses			43.6		6.1
	Postretirement benefit asset (2)			187.8		182.7
	Deferred bond refinancing costs (3)			7.2		8
	Environmental remediation			53.1		51.4
	Competitive rate adjustment			2.8		4.1
	Other			8		7.7
	Total other regulatory assets			302.5		260
	Total regulatory assets			371.7		327.4
	Less: Current portion			52.1		34.3
	Long-term regulatory assets		$	319.6	$	293.1
	Regulatory liabilities:
	Regulatory tax liability (1)		$	5.1	$	9.8
	Other:
	Cost-recovery clauses			23.5		54.5
	Transmission and delivery storm reserve			56.1		56.1
	Deferred gain on property sales (4)			0.8		2
	Provision for stipulation and other			1.1		0.8
	Accumulated reserve - cost of removal			591.5		594
	Total other regulatory liabilities			673		707.4
	Total regulatory liabilities			678.1		717.2
	Less: Current portion			54.7		85.8
	Long-term regulatory liabilities		$	623.4	$	631.4
	-1	Primarily related to plant life and derivative positions.
	-2	Amortized over the remaining service life of plan participants.
	-3	Amortized over the term of the related debt instruments.
	-4	Amortized over a 5-year period with various ending dates.
Regulatory Assets and Related Recovery Period	All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:
	Regulatory assets

			Dec. 31,		Dec. 31,
	(millions)		2014		2013
	Clause recoverable (1)		$	46.4	$	10.2
	Components of rate base (2)			191		185.6
	Regulatory tax assets (3)			69.2		67.4
	Capital structure and other (3)			65.1		64.2
	Total		$	371.7	$	327.4
	-1	To be recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year.
	-2	Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
	-3	“Regulatory tax assets” and “Capital structure and other” regulatory assets, including environmental remediation, have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2014
Schedule of Income Tax Expense	Income tax expense consists of the following:
	Income Tax Expense (Benefit)

	(millions)
	For the year ended Dec. 31,		2014			2013			2012
	Continuing Operations
	Current income taxes
	Federal		$	0.5		$	2.2		$	15.7
	State			0			0			0
	Deferred income taxes
	Federal			111			98.8			89.2
	State			27.7			11.9			16.2
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.3	)
	Income tax expense from continuing operations			138.9			112.6			120.8
	Discontinued Operations
	Current income taxes
	Federal			0			0			0
	Foreign			0			0			6.8
	State			(0.4	)		(3.5	)		1.1
	Deferred income taxes
	Federal			(44.0	)		(0.3	)		28.6
	Foreign			0			0			0
	State			(5.0	)		0			2.9
	Income tax expense from discontinued operations			(49.4	)		(3.8	)		39.4
	Total income tax expense		$	89.5		$	108.8		$	160.2

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,		2014			2013			2012
	Income tax expense at the federal statutory rate of 35%		$	120.9		$	105.5		$	111.2
	Increase (decrease) due to:
	State income tax, net of federal income tax			17			7.5			10.4
	Valuation allowance			0.9			0			1.1
	Other			0.1			(0.4	)		(1.9	)
	Total income tax expense from continuing operations		$	138.9		$	112.6		$	120.8
	Income tax expense as a percent of income from continuing operations,			40.2	%		37.4	%		38	%
	before income taxes			40.2	%		37.4	%		38	%

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,		2014			2013
	Deferred tax liabilities (1)
	Property related		$	1,391.30		$	1,164.20
	Pension			62.3			52.8
	Total deferred tax liabilities			1,453.60			1,217.00
	Deferred tax assets (1)
	Alternative minimum tax credit carryforward			214			213
	Loss and credit carryforwards (2)			566.7			479.8
	Other postretirement benefits			71.5			68.9
	Other			159.6			111.6
	Total deferred tax assets			1,011.80			873.3
	Valuation allowance (3)			(4.6	)		0
	Total deferred tax assets, net of valuation allowance			1,007.20			873.3
	Total deferred tax liability, net			446.4			343.7
	Less: Current portion of deferred tax asset			(72.8	)		(100.3	)
	Long-term portion of deferred tax liability, net		$	519.2		$	444
	-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, 2014 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 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	$3.6 million related to discontinued operations.
Schedule of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	(millions)		2014			2013			2012
	Balance at Jan. 1,		$	0		$	2.9		$	4.1
	Decreases due to expiration of statute of limitations			0			(2.9	)		0
	Dispositions			0			0			(1.2	)
	Balance at Dec. 31		$	0		$	0			2.9

Tampa Electric Company [Member]
Schedule of Income Tax Expense	Income tax expense consists of the following components:

	(millions)
	For the year ending Dec. 31,		2014			2013			2012
	Current income taxes
	Federal		$	54.8		$	19.4		$	(19.5	)
	State			8.9			1.3			5.6
	Deferred income taxes
	Federal			79			99.8			141.2
	State			13.5			18.6			14.7
	Amortization of investment tax credits			(0.3	)		(0.3	)		(0.3	)
	Total income tax expense		$	155.9		$	138.8		$	141.7

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,		2014			2013			2012
	Income tax expense at the federal statutory rate of 35%		$	145.7		$	127.5		$	129.1
	Increase (decrease) due to
	State income tax, net of federal income tax			14.5			13			13.2
	Other			(4.3	)		(1.7	)		(0.6	)
	Total income tax expense on consolidated statements of income		$	155.9		$	138.8		$	141.7
	Income tax expense as a percent of income from continuing operations,			37.5	%		38.1	%		38.4	%
	before income taxes			37.5	%		38.1	%		38.4	%

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,		2014			2013
	Deferred tax liabilities (1)
	Property related		$	1,328.80		$	1,166.40
	Pension and postretirement benefits			72.5			70.5
	Pension			51.8			43.2
	Total deferred tax liabilities			1,453.10			1,280.10
	Deferred tax assets (1)
	Loss and credit carryforwards			77.7			4.8
	Medical benefits			51			50.9
	Insurance reserves			29			29.1
	Pension and postretirement benefits			72.5			70.5
	Capitalized energy conservation assistance costs			20.3			19.6
	Other			18.3			20.3
	Total deferred tax assets			268.8			195.2
	Total deferred tax liability, net			1,184.30			1,084.90
	Less: Current portion of deferred tax asset			(24.8	)		(29.4	)
	Long-term portion of deferred tax liability, net		$	1,209.10		$	1,114.30
	-1	Certain property related assets and liabilities have been netted.

ShortTerm_Debt_Tables

Short-Term Debt (Tables)	12 Months Ended
Short-Term Debt (Tables)	Dec. 31, 2014
Short-Term Debt Credit Facilities	At Dec. 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:
	Credit Facilities

			Dec. 31, 2014						Dec. 31, 2013
							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	$	12	$	0.6	$	325	$	6	$	0.7
	1-year accounts receivable facility			150		46		0		150		78		0
	TECO Energy/TECO Finance:
	5-year facility (2)(3)			300		50		0		200		0		0
	New Mexico Gas Company:
	5-year facility (2)			125		31		1.7		0		0		0
	Total		$	900	$	139	$	2.3	$	675	$	84	$	0.7
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.
	-3	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, 2014 and 2013, the following credit facilities and related borrowings existed:
	Credit Facilities

			Dec. 31, 2014						Dec. 31, 2013
							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	$	12	$	0.6	$	325	$	6	$	0.7
	1-year accounts receivable facility			150		46		0		150		78		0
	Total		$	475	$	58	$	0.6	$	475	$	84	$	0.7
	-1	Borrowings outstanding are reported as notes payable.
	-2	This 5-year facility matures Dec. 17, 2018.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
Long-Term Debt (Tables)	Dec. 31, 2014
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 2015 through 2019 and thereafter are as follows:
	Long-Term Debt Maturities

																	Total
	As of Dec. 31, 2014																Long-Term
	(millions)		2015			2016		2017			2018		2019		Thereafter		Debt
	TECO Finance		$	191.2		$	250	$	300		$	0	$	0	$	300	$	1,041.20
	Tampa Electric			83.3			83.4		0			254.2		0		1,436.70		1,857.60
	PGS			0			0		0			50		0		191.7		241.7
	NMGI			0			0		0			0		50		150		200
	NMGC			0			0		0			0		0		270		270
	Total long-term debt maturities		$	274.5		$	333.4	$	300		$	304.2	$	50	$	2,348.40	$	3,610.50

Schedule of Long-Term Debt Outstanding	At Dec. 31, 2014 and 2013, TECO Energy had the following long-term debt outstanding:

	Long-Term Debt
	(millions)				Due	2014		2013
	TECO Finance		Notes (1)(2)(3) : 6.75%		2015	$	191.2	$	191.2
			4.00%		2016		250		250
			6.57%		2017		300		300
			5.15%		2020		300		300
			Total long-term debt of TECO Finance				1,041.20		1,041.20
	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
			5.15% Refunding bonds repurchased in 2013 (6)		2025		0		0
			1.5% Term rate bonds repurchased in 2011 (7)		2030		0		0
			5.0% Refunding bonds repurchased in 2012 (8)		2034		0		0
			Notes (1)(2) : 6.25%		2014-2016		166.7		250
			6.10%		2018		200		200
			5.40%		2021		231.7		231.7
			2.60%		2022		225		225
			6.55%		2036		250		250
			6.15%		2037		190		190
			4.10%		2042		250		250
			4.35%		2044		290		0
			Total long-term debt of Tampa Electric				1,857.60		1,650.90
	PGS		Notes (1)(2) : 6.10%		2018		50		50
			5.40%		2021		46.7		46.7
			2.60%		2022		25		25
			6.15%		2037		60		60
			4.10%		2042		50		50
			4.35%		2044		10		0
			Total long-term debt of PGS				241.7		231.7
	NMGI		Notes (1)(2) : 2.71%		2019		50		0
			3.64%		2024		150		0
			Total long-term debt of NMGI				200		0
	NMGC		Notes (1)(2) : 4.87%		2021		200		0
			3.54%		2026		70		0
			Total long-term debt of NMGC				270		0
			Total long-term debt of TECO Energy				3,610.50		2,923.80
	Unamortized debt discount, net						18		(2.7	)
	Total carrying amount of long-term debt						3,628.50		2,921.10
	Less amount due within one year						274.5		83.3
	Total long-term debt					$	3,354.00	$	2,837.80
	-1	These securities are subject to redemption in whole or in part, at any time, at the option of the company.
	-2	These long-term debt agreements contain various restrictive financial covenants.
	-3	Guaranteed by TECO Energy.
	-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
Common Stock (Tables)	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule of Assumptions Used to Determine Fair Value
	Assumptions		2014			2013			2012
	Assumptions applicable to performance-based restricted stock
	Risk-free interest rate			0.68	%		0.41	%		0.38	%
	Expected lives (in years)			3			3			3
	Expected stock volatility			17.36	%		19.04	%		20.99	%
	Dividend yield			5.13	%		4.83	%		4.78	%

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)		2014			2013			2012
	Compensation costs (1)		$	12.7		$	13.5		$	12
	Income tax benefits (1)			4.9			5.2			4.6
	Excess tax benefits (2)			0.4			0			2.6
	-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, 2013			638		$	18.33			1,505		$	17.04
	Granted			265		$	16.93			537		$	13.59
	Vested			(200	)	$	19.16			(444	)	$	18.53
	Forfeited			(35	)	$	17.51			(83	)	$	15.51
	Nonvested balance at Dec. 31, 2014			668		$	17.56			1,515		$	15.44
	-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, 2013			1,567		$	15.62
	Granted			0		$	0
	Exercised			(727	)	$	14.8
	Cancelled			0		$	0
	Outstanding balance at Dec. 31, 2014(1)			840		$	16.32			1		$	3.5
	Exercisable at Dec. 31, 2014 (1)			840		$	16.32			1		$	3.5
	Available for future grant at Dec. 31, 2014			2,482
	-1	Option prices range from $16.21 to $19.01 per share.
Schedule of Option Outstanding and Exercisable	As of Dec. 31, 2014, the options outstanding and exercisable are summarized below:

	Range of					Weighted-Avg.			Weighted-Avg.
	Option Prices		Option Shares			Option Price			Remaining
	(per share)		(thousands)			(per share)			Contractual Life (years)

	$16.21 — $ 19.01			840		$	16.32		1
	Total			840		$	16.32		1

Other_Comprehensive_Income_Tab

Other Comprehensive Income (Tables)	12 Months Ended
Other Comprehensive Income (Tables)	Dec. 31, 2014
Other Comprehensive Income	TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2014, 2013 and 2012, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

	(millions)		Gross			Tax			Net
	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
	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 (3)			(12.9	)		4.7			(8.2	)
	Change in benefit obligation due to remeasurement (4)			12.6			(4.6	)		8
	Total other comprehensive income (loss)		$	(4.0	)	$	1.5		$	(2.5	)
	2013
	Unrealized gain (loss) on cash flow hedges		$	1		$	(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 benefit costs due to settlement			2.6			(1.0	)		1.6
	Total other comprehensive income (loss)		$	28.5		$	(10.7	)	$	17.8
	2012
	Unrealized gain (loss) on cash flow hedges		$	(7.4	)	$	2.8		$	(4.6	)
	Reclassification from AOCI to net income (1)			0.6			(0.2	)		0.4
	Gain (Loss) on cash flow hedges			(6.8	)		2.6			(4.2	)
	Amortization of unrecognized benefit costs and other (2)(5)			(4.8	)		0			(4.8	)
	Total other comprehensive income (loss)		$	(11.6	)	$	2.6		$	(9.0	)
	-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	Includes an adjustment to eliminate TECO Coal’s OPEB liability. See Note 5 for additional information.
	-5	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss

	(millions) Dec. 31,		2014			2013
	Unrecognized pension losses and prior service credits (1)		$	(22.5	)	$	(20.5	)
	Unrecognized other benefit gains, prior service costs and transition obligations (2)			13.9			15.1
	Net unrealized losses from cash flow hedges (3)			(7.1	)		(7.8	)
	Total accumulated other comprehensive loss		$	(15.7	)	$	(13.2	)

	-1	Net of tax benefit of $13.8 million and $12.6 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.
	-2	Net of tax expense of $8.3 million and $9.1 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively. Balance includes a $7.9 million loss at Dec. 31, 2014 related to TECO Coal’s unfunded black lung liability that will be reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5.
	-3	Net of tax benefit of $4.5 million and $4.9 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	TEC reported the following OCI (loss) for the years ended Dec. 31, 2014, 2013 and 2012, 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
	2014
	Unrealized gain (loss) on cash flow hedges		$	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
	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
	2012
	Unrealized gain (loss) on cash flow hedges		$	(8.0	)	$	3.1		$	(4.9	)
	Reclassification from AOCI to net income			1.4			(0.6	)		0.8
	Gain (Loss) on cash flow hedges			(6.6	)		2.5			(4.1	)
	Total other comprehensive income (loss)		$	(6.6	)	$	2.5		$	(4.1	)

Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss

	(millions) As of Dec. 31,		2014			2013
	Net unrealized losses from cash flow hedges (1)		$	(7.1	)	$	(7.8	)
	Total accumulated other comprehensive loss		$	(7.1	)	$	(7.8	)
	-1	Net of tax benefit of $4.5 million and $4.9 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
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)		2014			2013 (1)			2012 (1)
	Basic earnings per share
	Net income from continuing operations		$	206.4		$	188.7		$	197
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Income before discontinued operations available to		$	205.7		$	188.1		$	196.3
	common shareholders—Basic
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy, net
	Amount allocated to nonvested participating shareholders			0			0			0
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy available to common shareholders—Basic
	Net income attributable to TECO Energy		$	130.4		$	197.7		$	212.7
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Net income attributable to TECO Energy available to		$	129.7		$	197.1		$	212
	common shareholders—Basic
	Average common shares outstanding—Basic			223.1			215			214.3
	Earnings per share from continuing operations available to		$	0.92		$	0.88		$	0.92
	common shareholders—Basic
	Earnings per share from discontinued operations		$	(0.34	)	$	0.04		$	0.07
	attributable to TECO Energy available to common
	shareholders—Basic
	Earnings per share attributable to TECO Energy available		$	0.58		$	0.92		$	0.99
	to common shareholders—Basic
	Diluted earnings per share
	Net income from continuing operations		$	206.4		$	188.7		$	197
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Income before discontinued operations available to		$	205.7		$	188.1		$	196.3
	common shareholders—Diluted
	Income (loss) from discontinued operations attributable to		$	(76.0	)	$	9		$	15.7
	TECO Energy, net
	Amount allocated to nonvested participating shareholders			0			0			0
	Income (loss) from discontinued operations attributable		$	(76.0	)	$	9		$	15.7
	to TECO Energy available to common
	shareholders—Diluted
	Net income attributable to TECO Energy		$	130.4		$	197.7		$	212.7
	Amount allocated to nonvested participating shareholders			(0.7	)		(0.6	)		(0.7	)
	Net income attributable to TECO Energy available to		$	129.7		$	197.1		$	212
	common shareholders—Diluted
	Unadjusted average common shares outstanding—Diluted			223.1			215			214.3
	Assumed conversion of stock options, unvested restricted			0.6			0.5			0.7
	stock and contingent performance shares, net
	Average common shares outstanding—Diluted			223.7			215.5			215
	Earnings per share from continuing operations available to		$	0.92		$	0.88		$	0.92
	common shareholders—Diluted
	Earnings per share from discontinued operations		$	(0.34	)	$	0.04		$	0.07
	attributable to TECO Energy available to common
	shareholders—Diluted
	Earnings per share attributable to TECO Energy available		$	0.58		$	0.92		$	0.99
	to common shareholders—Diluted
	Anti-dilutive shares			0			0			0.4
	-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
Commitments and Contingencies (Tables)	Dec. 31, 2014
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, 2014:
			Capacity		Operating		Net Purchase
	(millions)		Payments		Leases(1)		Obligations/Commitments(1)		Total
	Year ended Dec. 31:
	2015		$	30	$	8.9	$	204.5	$	243.4
	2016			14.6		8		86.8		109.4
	2017			9.9		7		19.8		36.7
	2018			10.1		6.2		5.2		21.5
	2019			0		5.7		5.3		11
	Thereafter			0		18.4		0		18.4
	Total future minimum payments		$	64.6	$	54.2	$	321.6	$	440.4
	-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, 2014 are as follows:



	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Guarantees for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TECO Energy
	Fuel sales and transportation (2)		$	0	$	0	$	92.9		92.9	$	0

	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Letter of Credit for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TEC		$	0	$	0	$	0.6	$	0.6	$	0.1
	NMGC		$	0	$	0	$	1.7	$	1.7	$	0
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019.
	-2	The amounts shown 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, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.
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, 2014:
			Capacity		Operating		Net Purchase
	(millions)		Payments		Leases(1)		Obligations/Commitments(1)		Total
	Year ended Dec. 31:
	2015		$	30	$	6.7	$	203.2	$	239.9
	2016			14.6		6.1		86.8		107.5
	2017			9.9		5.2		19.8		34.9
	2018			10.1		4.5		5.2		19.8
	2019			0		4.4		5.3		9.7
	Thereafter			0		13		0		13
	Total future minimum payments		$	64.6	$	39.9	$	320.3	$	424.8
	-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, 2014, TEC was not obligated under guarantees, but had the following letters of credit outstanding.
	Letters of Credit-Tampa Electric Company

	(millions)		Year of Expiration						Maximum
							After (1)		Theoretical		Liabilities Recognized
	Letter of Credit for the Benefit of:		2015		2016-2019		2019		Obligation		at Dec. 31, 2014 (2)
	TEC		$	0	$	0	$	0.6	$	0.6	$	0.1
	-1	These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019.
	-2	The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at Dec. 31, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
Segment Information (Tables)	Dec. 31, 2014
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 more than 706,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for almost 354,000 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 approximately 513,000 residential, commercial, industrial customers in the State of New Mexico.
			Tampa							TECO				TECO									TECO
	(millions)		Electric		PGS		NMGC (4)			Coal (2)				Guatemala (2)			Other (4)			Eliminations			Energy
	2014
	Revenues—external		$	2,019.90	$	398.5	$	137.5		$	0			$	0		$	10.5		$	0		$	2,566.40
	Sales to affiliates			1.1		1.1		0			0				0			40.6			(42.8	)		0
	Total revenues			2,021.00		399.6		137.5			0				0			51.1			(42.8	)		2,566.40
	Depreciation and amortization			248.6		54		11			0				0			1.7			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			1.4			(1.4	)		0
	Provision for income taxes			133.2		22.7		7.1			0				0			(24.1	)		0			138.9
	Net income from continuing operations			224.5		35.8		10.5			0				0			17.8			(82.2	)		206.4
	Discontinued operations attributable to TECO, net of tax			0		0		0			(82.0	)			0			6			0			(76.0	)
	Net income attributable to TECO Energy			224.5		35.8		10.5			(82.0	)			0			23.8			(82.2	)		130.4
	Current assets held for sale			0		0		0			109.6				0			0			0			109.6
	Non-current assets held for sale			0		0		0			59.8				0			0			0			59.8
	Goodwill			0		0		408.3			0				0			0			0			408.3
	Total assets			6,565.40		1,082.80		1,237.20			227.7		-3		0			5,664.40			(6,051.3	)		8,726.20
	Capital expenditures			592.6		88.9		18.2			14.6				0			0			0			714.3
	2013
	Revenues—external		$	1,949.60	$	392.7	$	0		$	0			$	0		$	12.8		$	0		$	2,355.10
	Sales to affiliates			0.9		0.8		0			0				0			0.5			(2.2	)		0
	Total revenues			1,950.50		393.5		0			0				0			13.3			(2.2	)		2,355.10
	Depreciation and amortization			238.8		51.5		0			0				0			1.5			0			291.8
	Total interest charges (1)			91.8		13.5		0			0				0			63.9			(7.8	)		161.4
	Internally allocated interest (1)			0		0		0			0				0			7.8			(7.8	)		0
	Provision for income taxes			116.9		21.9		0			0				0			(26.2	)		0			112.6
	Net income from continuing operations			190.9		34.7		0			0				0			177.3			(214.2	)		188.7
	Discontinued operations attributable to TECO, net of tax			0		0		0			9				0			0			0			9
	Net income attributable to TECO Energy			190.9		34.7		0			9				0			177.3			(214.2	)		197.7
	Total assets			6,126.90		1,021.20		0			316.3		-3		0			4,717.20			(4,733.6	)		7,448.00
	Capital expenditures			428.6		79		0			22.4				0			2.4			-			532.4
	2012
	Revenues—external		$	1,980.70	$	396.6	$	0		$	0			$	0		$	10.4		$	0		$	2,387.70
	Sales to affiliates			0.6		2.3		0			0				0			0.1			(3.0	)		0
	Total revenues			1,981.30		398.9		0			0				0			10.5			(3.0	)		2,387.70
	Depreciation and amortization			237.6		50.6		0			0				0			1.4			0			289.6
	Total interest charges (1)			109.8		16		0			0				0			64.1			(13.5	)		176.4
	Internally allocated interest (1)			0		0		0			0				0			13.5			(13.5	)		0
	Provision for income taxes			120.2		21.5		0			0				0			(20.9	)		0			120.8
	Net income from continuing operations			193.1		34.1		0			0				0			241.3			(271.5	)		197
	Discontinued operations attributable to TECO, net of tax			0		0		0			50.2				(29.3	)		(5.2	)		0			15.7
	Net income attributable to TECO Energy			193.1		34.1		0			50.2				(29.3	)		236.1			(271.5	)		212.7
	Total assets			6,042.30		1,009.90		0			356.6		-3		164.9			4,870.00			(5,108.8	)		7,334.90
	Capital expenditures			361.7		97.3		0			36.3				8.6			1.2			0			505.1

	-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 2014, 2013 and 2012 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, TECO Guatemala and certain charges at Parent that directly relate to TECO Coal or TECO Guatemala. See Note 19.
	-3	The carrying value of mineral rights as of Dec. 31, 2014, 2013 and 2012 was $10.9 million, $12.1 million and $13.4 million, respectively.
	-4	NMGI is included in the Other segment.
Tampa Electric Company [Member]
Schedule of Segment Information
			Tampa
	(millions)		Electric		PGS		Eliminations			TEC
	2014
	Revenues - external		$	2,020.50	$	398.5	$	0		$	2,419.00
	Sales to affiliates			0.5		1.1		(1.6	)		0
	Total revenues			2,021.00		399.6		(1.6	)		2,419.00
	Depreciation and amortization			248.6		54		0			302.6
	Total interest charges			92.8		13.8		0			106.6
	Provision for income taxes			133.2		22.7		0			155.9
	Net income			224.5		35.8		0			260.3
	Total assets			6,234.40		1,047.00		(7.1	)		7,274.30
	Capital expenditures			592.6		88.9		0			681.5
	2013
	Revenues - external		$	1,950.10	$	392.7	$	0		$	2,342.80
	Sales to affiliates			0.4		0.8		(1.2	)		0
	Total revenues			1,950.50		393.5		(1.2	)		2,342.80
	Depreciation and amortization			238.8		51.5		0			290.3
	Total interest charges			91.8		13.5		0			105.3
	Provision for income taxes			116.9		21.9		0			138.8
	Net income			190.9		34.7		0			225.6
	Total assets			5,895.40		989.3		(8.9	)		6,875.80
	Capital expenditures			428.6		79		0			507.6
	2012
	Revenues - external		$	1,980.90	$	397.1	$	0		$	2,378.00
	Sales to affiliates			0.4		1.8		(2.2	)		0
	Total revenues			1,981.30		398.9		(2.2	)		2,378.00
	Depreciation and amortization			237.6		50.6		0			288.2
	Total interest charges			109.8		16		0			125.8
	Provision for income taxes			120.2		21.5		0			141.7
	Net income			193.1		34.1		0			227.2
	Total assets			5,760.40		970.9		13.3			6,744.60
	Capital expenditures			361.7		97.3		0			459

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2014
Schedule of Asset Retirement Obligations	Reconciliation of beginning and ending carrying amount of asset retirement obligations:

			Dec. 31,
	(millions)		2014			2013
	Beginning balance		$	28.6		$	28.6
	Additional liabilities			0.1			0.1
	Liabilities settled			0			(1.4	)
	Accretion expense			0			1.4
	Revisions to estimated cash flows			0.2			(0.3	)
	Acquisition of NMGC			0.8			0
	Reclassification to liabilities associated with assets held for sale			(22.5	)		0
	Other (1)			(1.1	)		0.2
	Ending balance		$	6.1		$	28.6
	-1	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. 2013 includes 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)		2014			2013
	Beginning balance		$	4.8		$	5
	Additional liabilities			0.1			0.1
	Liabilities settled			0			(0.2	)
	Revisions to estimated cash flows			0.2			(0.3	)
	Other (1)			0.2			0.2
	Ending balance		$	5.3		$	4.8
	·	Accretion recorded as a deferred regulatory asset.

Accounting_for_Derivative_Inst1

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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 Dec. 31, 2016 for financial natural gas contracts. There is no diesel fuel contract exposure beyond 2014. The following table presents the company’s derivative volumes that, as of Dec. 31, 2014, are expected to settle during the 2015 and 2016 fiscal years:

		Natural Gas Contracts
	(millions)	(MMBTUs)
	Year	Physical		Financial
	2015		0		32.4
	2016		0		8.6
	Total		0		41

Tampa Electric Company [Member]
Derivative Volumes Expected to Settle	The following table presents TEC’s derivative volumes that, as of Dec. 31, 2014, are expected to settle during the 2015 and 2016 fiscal years:

		Natural Gas Contracts
	(millions)	(MMBTUs)
	Year	Physical		Financial
	2015		0		32.4
	2016		0		8.6
	Total		0		41

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2014
Schedule of Recurring Fair Value Measurements	For natural gas and diesel fuel swaps, the market approach was used in determining fair value.
	Recurring Fair Value Measures

		As of Dec. 31, 2014
	(millions)	Level 1		Level 2		Level 3		Total
	Liabilities
	Natural gas swaps	$	0	$	42.7	$	0	$	42.7

		As of Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Diesel fuel swaps		0		0.2		0		0.2
	Total	$	0	$	10	$	0	$	10
	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Diesel fuel swaps		0		0.1		0		0.1
	Total	$	0	$	0.3	$	0	$	0.3

Tampa Electric Company [Member]
Schedule of Recurring Fair Value Measurements	For all assets and liabilities presented below, the market approach was used in determining fair value.
	Recurring Derivative Fair Value Measures

		As of Dec. 31, 2014
	(millions)	Level 1		Level 2		Level 3		Total
	Liabilities
	Natural gas swaps	$	0	$	42.7	$	0	$	42.7

		As of Dec. 31, 2013
	(millions)	Level 1		Level 2		Level 3		Total
	Assets
	Natural gas swaps	$	0	$	9.8	$	0	$	9.8
	Total	$	0	$	9.8	$	0	$	9.8

	Liabilities
	Natural gas swaps	$	0	$	0.2	$	0	$	0.2
	Total	$	0	$	0.2	$	0	$	0.2

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
Discontinued Operations (Tables)	Dec. 31, 2014
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 attributable to TECO Energy
	(millions)		2014			2013			2012
	Revenues—TECO Coal		$	443.6		$	496.2		$	608.9
	Revenues—TECO Guatemala			0			0			114.2
	Income (loss) from operations—TECO Coal			(13.9	)		5.4			66
	Income (loss) from operations—TECO Guatemala			4.4			(0.2	)		27.7
	Loss on impairment—TECO Coal			(115.9	)		0			0
	Loss on assets sold, including transaction costs—TECO Guatemala			0			0			(38.3	)
	Income (loss) from discontinued operations—TECO Coal			(129.8	)		5.4			66
	Income (loss) from discontinued operations—TECO Guatemala			4.4			(0.2	)		(10.6	)
	Income (loss) from discontinued operations			(125.4	)		5.2			55.4
	Provision (benefit) for income taxes			(49.4	)		(3.8	)		39.4
	Income (loss) from discontinued operations, net			(76.0	)		9			16
	Less: Income from discontinued operations attributable to noncontrolling interest			0			0			0.3
	Income (loss) from discontinued operations attributable to TECO Energy, net		$	(76.0	)	$	9		$	15.7

Goodwill_and_Asset_Impairments1

Goodwill and Asset Impairments (Tables)	12 Months Ended
Goodwill and Asset Impairments (Tables)	Dec. 31, 2014
Goodwill And Asset Impairments Disclosure [Abstract]
Changes in Carrying Amount of Goodwill	The following table presents the changes in the carrying amount of goodwill related to TECO Guatemala and NMGC for the years ended Dec. 31, 2014, 2013 and 2012.

								Total TECO
	(millions)	TPS GO			TPS SJI			Guatemala			NMGC		Total
	Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4		$	0	$	55.4
	Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)		0		(15.2	)
	Goodwill written off upon sale, pretax		0			(40.2	)		(40.2	)		0		(40.2	)
	Balance as of Dec. 31, 2012	$	0		$	0		$	0		$	0	$	0
	Balance as of Dec. 31, 2013	$	0		$	0		$	0		$	0	$	0
	Acquisition of NMGC		0			0			0			408.3		408.3
	Balance as of Dec. 31, 2014	$	0		$	0		$	0		$	408.3	$	408.3

Acquisition_of_New_Mexico_Gas_1

Acquisition of New Mexico Gas Company (Tables)	12 Months Ended
Acquisition of New Mexico Gas Company (Tables)	Dec. 31, 2014
Pro Forma Financial Information
	Pro Forma Impact of Acquisition		For year ending Dec. 31,
	(millions, except per share amounts)		2014			2013
	Revenues		$	2,806.60		$	2,704.00
	Net income from continuing operations			223.8			216.8
	Basic and diluted EPS from continuing operations			0.96			0.93

Pretax Transaction and Integration Charges Recognized Upon Closing of Acquisition and Included Consolidated Statements of Operations	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 year ended Dec. 31, 2014.

	Transaction and Integration Costs
	(millions)		Total
	Legal and other consultants		$	8
	Bridge loan costs			3.3
	Severance and relocation costs			2.8
	Other costs and tax benefit			(5.5	)
	Total accounting charges		$	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
	Total consideration transferred, excluding cash and working capital adjustments		$	950

NMGI and NMGC [Member]
Purchase Price Allocation	The purchase price allocation of the acquisition of NMGI and NMGC is as follows:

	Purchase Price Allocation
	(millions)
	Current assets (a)		$	48.7
	Property, plant and equipment			616.5
	OPEB regulatory asset			6.4
	Debt-related regulatory asset			23.9
	Goodwill			408.3
	Deferred tax assets			52.8
	Other assets			29.3
	Total assets		$	1,185.90
	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
	-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_Table

Quarterly Data (unaudited) (Tables)	12 Months Ended
Quarterly Data (unaudited) (Tables)	Dec. 31, 2014
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		30-Jun		Mar. 31
	2014
	Revenues	$	695.5	$	687.2	$	605.7	$	578
	Income from operations		112.1		145.7		132		115.6
	Net income from continuing operations		27.4		73		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	$	0.22	$	0.22	$	0.22	$	0.22

	Quarter ended	Dec. 31		Sept. 30		30-Jun		Mar. 31
	2013
	Revenues	$	562.2	$	642.1	$	607.5	$	543.3
	Income from operations		95		141.7		118.1		99.8
	Net income from continuing operations		35.4		64.3		50.7		38.3
	Net income		42		62.8		51.4		41.5
	EPS—Basic
	Net income from continuing operations	$	0.17	$	0.3	$	0.24	$	0.17
	Net income		0.2		0.29		0.24		0.19
	EPS—Diluted
	Net income from continuing operations	$	0.17	$	0.3	$	0.24	$	0.17
	Net income		0.2		0.29		0.24		0.19
	Dividends paid per common share outstanding	$	0.22	$	0.22	$	0.22	$	0.22
	Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	A summary of activities between TEC and its affiliates follows:
	Net transactions with affiliates:

	(millions)		2014		2013		2012
	Natural gas sales, net		$	0.3	$	18.3	$	11.7
	Administrative and general, net		$	22.5	$	27.2	$	23.4
	Amounts due from or to affiliates at Dec. 31,

	(millions)		2014		2013
	Accounts receivable(1)		$	2.4	$	1.3
	Accounts payable(1)			9.7		9.8
	Taxes receivable(2)			43.3		54.9
	Taxes payable			0		0.4
	-1	Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
	-2	Taxes receivable is due from TECO Energy.

Significant_Accounting_Policie3

Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	3.60%	3.70%	3.80%
Depreciation expense	$307.50	$285.60	$276.30
Unbilled revenues	86.6	46.7
Purchased power	71.4	64.7	105.3
Franchise fees and gross receipts taxes	113.9	108.5	111.5
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.71%	3.51%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	3.86%	4.86%
Computer Software [Member] \| Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	2 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	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%	3.80%
Depreciation expense	295.8	284.2	275.1
Allowance for funds used during construction rate	6.46%	8.16%	8.16%
Allowance for funds used during construction	15.6	9.9	4.1
Unbilled revenues	49.3	46.7
Purchased power	71.4	64.7	105.3
Franchise fees and gross receipts taxes	113.9	108.5	111.5
Tampa Electric Company [Member] \| Computer Software [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	15 years	15 years
TECO Coal [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of subsidiaries	10
Shipping and Handling	5.2	8.2	9
NMGC [Member]
Summary Of Significant Accounting Policies [Line Items]
Allowance for funds used during construction rate	4.92%
TECO Energy [Member]
Summary Of Significant Accounting Policies [Line Items]
Allowance for funds used during construction	15.8
TECO Energy Source, Inc [Member]
Summary Of Significant Accounting Policies [Line Items]
Costs netted against revenues	$4.30	$23.10	$13.80

Significant_Accounting_Policie4

Significant Accounting Policies - Estimated Useful Lives of Depreciable Property (Detail)	12 Months Ended
	Dec. 31, 2014
Minimum [Member] \| Building and Improvements [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	5 years
Minimum [Member] \| Office Equipment and Furniture [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	3 years
Minimum [Member] \| Vehicles, Mining and Other Equipment [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	2 years
Minimum [Member] \| Computer Software [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	2 years
Maximum [Member] \| Building and Improvements [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	40 years
Maximum [Member] \| Office Equipment and Furniture [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	30 years
Maximum [Member] \| Vehicles, Mining and Other Equipment [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	15 years
Maximum [Member] \| Computer Software [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciable property estimated useful lives	15 years

Significant_Accounting_Policie5

Significant Accounting Policies - Schedule of Fuel Inventory (Detail) (Fuel [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Inventory [Line Items]
Fuel inventory	$96.40	$118.70
Tampa Electric [Member]
Inventory [Line Items]
Fuel inventory	85.2	93.7
TECO Coal [Member]
Inventory [Line Items]
Fuel inventory	0	25
NMGC [Member]
Inventory [Line Items]
Fuel inventory	$11.20	$0

Regulatory_Additional_Informat

Regulatory - Additional Information (Detail) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended
Regulatory - Additional Information (Detail) (USD $)	Feb. 01, 2012	Mar. 31, 2011	Dec. 31, 2014	Dec. 31, 2013
Percentage of return on equity			11.25%
Allowed equity in the capital structure			54.00%
Period of average base rate			13 months
Revenue due to average base rate			$3,400,000,000
Increase in revenue by modification in base rate			33,500,000
Potential increase in ROE			10.25%
Return on equity range			Range of plus or minus 1%
Amortization period for computer software under regulatory requirement description			Tampa Electric began using a 15-year amortization period for all computer software
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	11.5
Tampa Electric Company [Member]
Percentage of return on equity			10.75%
Annual accrual storm damage reserve				8,000,000
Storm damage reserve			56,100,000	56,100,000
Storm damage cost recovery period			12 months
Equity ratio			54.70%
Regulatory matters allowed base rate			560,800,000
PGS Rates [Member]
Percentage of return on equity			10.75%
Equity ratio			54.70%
Regulatory matters allowed base rate			560,800,000
November 1, 2013 [Member]
Additional Revenue generated from increase in service charge			57,500,000
November 1, 2014 [Member]
Additional Revenue generated from increase in service charge			7,500,000
November 1, 2015 [Member]
Additional Revenue generated from increase in service charge			5,000,000
January 1,2017 [Member]
Additional Revenue generated from increase in service charge			110,000,000
Condition One [Member]
ROE lower range limit			9.25%
ROE upper range limit			11.25%
Condition Two [Member]
ROE lower range limit			9.50%
ROE upper range limit			11.50%
Maximum [Member]
Higher Revenue Requirements			$104,000,000
Potential increase in ROE			10.50%
Maximum [Member] \| Tampa Electric Company [Member]
Return on equity			11.75%
Maximum [Member] \| PGS Rates [Member]
Return on equity			11.75%
Minimum [Member] \| Tampa Electric Company [Member]
Return on equity			9.75%
Minimum [Member] \| PGS Rates [Member]
Return on equity			9.75%

Regulatory_Schedule_of_Regulat

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory assets:
Regulatory assets	$402.10	$327.40
Less: Current portion	53.6	34.3
Long-term regulatory assets	348.5	293.1
Regulatory liabilities:
Regulatory liabilities	786	717.2
Less: Current portion	57	85.8
Long-term regulatory liabilities	729	631.4
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	371.7	327.4
Less: Current portion	52.1	34.3
Long-term regulatory assets	319.6	293.1
Regulatory liabilities:
Regulatory liabilities	678.1	717.2
Less: Current portion	54.7	85.8
Long-term regulatory liabilities	623.4	631.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	69.2	67.4
Regulatory Tax Asset [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	69.2	67.4
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	45.1	6.1
Cost-Recovery Clauses [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	43.6	6.1
Postretirement Benefit Asset [Member]
Regulatory assets:
Regulatory assets	194	182.7
Postretirement Benefit Asset [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	187.8	182.7
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	7.2	8
Deferred Bond Refinancing Costs [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	7.2	8
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	20.9	0
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	53.1	51.4
Environmental Remediation [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	53.1	51.4
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.8	4.1
Competitive Rate Adjustment [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.8	4.1
Other [Member]
Regulatory assets:
Regulatory assets	9.8	7.7
Other [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	8	7.7
Total Other Regulatory Assets [Member]
Regulatory assets:
Regulatory assets	332.9	260
Total Other Regulatory Assets [Member] \| Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	302.5	260
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	6.9	9.8
Regulatory Tax Liability [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.1	9.8
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	25.9	54.5
Cost-Recovery Clauses [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	23.5	54.5
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
Deferred Gain on Property Sales [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	2
Deferred Gain on Property Sales [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	2
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	695.2	594
Accumulated Reserve - Cost of Removal [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	591.5	594
Other [Member]
Regulatory liabilities:
Regulatory liabilities	1.1	0.8
Other [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	1.1	0.8
Total Other Regulatory Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	779.1	707.4
Total Other Regulatory Liabilities [Member] \| Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$673	$707.40

Regulatory_Schedule_of_Regulat1

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	Amortized over a 5-year
Tampa Electric Company [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	Amortized over a 5-year

Regulatory_Regulatory_Assets_a

Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Asset [Line Items]
Regulatory assets	$402.10	$327.40
Tampa Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory assets	371.7	327.4
Components of Rate Base [Member]
Regulatory Asset [Line Items]
Regulatory assets	199	185.6
Components of Rate Base [Member] \| Tampa Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory assets	191	185.6
Clause Recoverable [Member]
Regulatory Asset [Line Items]
Regulatory assets	47.9	10.2
Clause Recoverable [Member] \| Tampa Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory assets	46.4	10.2
Regulatory Tax Asset [Member]
Regulatory Asset [Line Items]
Regulatory assets	69.2	67.4
Regulatory Tax Asset [Member] \| Tampa Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory assets	69.2	67.4
Capital Structure and Other [Member]
Regulatory Asset [Line Items]
Regulatory assets	86	64.2
Capital Structure and Other [Member] \| Tampa Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory assets	$65.10	$64.20

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Income tax expense from continuing operations	$138.90	$112.60	$120.80
Cash paid for income taxes	2.9	1.8	7.2
Use of operating loss carryforward			13.6
Effective tax rate	35.00%	35.00%	35.00%
Increase in effective tax rate	1.90%
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	1,543.70
Deferred tax assets expiration date	2025 and 2033
General business credit	4
Deferred tax general business credits expiration date	2026 and 2033
Tax credit carry forwards	214	213
Valuation allowance	4.6	0
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%
Interest charges associated with uncertain tax positions	0	-0.9	0.3
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
Florida [Member]
Income Taxes [Line Items]
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	562.4
New Mexico [Member]
Income Taxes [Line Items]
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	56
Kentucky [Member]
Income Taxes [Line Items]
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	18.4
NMGI [Member]
Income Taxes [Line Items]
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	110.4
TECO Coal [Member] \| Discontinued Operations [Member]
Income Taxes [Line Items]
Valuation allowance	3.6
Tampa Electric Company [Member]
Income Taxes [Line Items]
Income tax expense from continuing operations	155.9	138.8	141.7
Cash paid for income taxes	52.6	56.4	-9.7
Effective tax rate	35.00%	35.00%	35.00%
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	194.1
Deferred tax assets expiration date	2033
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] \| Florida [Member]
Income Taxes [Line Items]
Federal, Florida, New Mexico and Kentucky net operating losses (NOL's) carry forward	$268.50

Income_Taxes_Schedule_of_Incom

Income Taxes - Schedule of Income Tax Expense (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Income tax expense from continuing operations	$138.90	$112.60	$120.80
Total income tax expense	89.5	108.8	160.2
Tampa Electric Company [Member]
Income Taxes [Line Items]
Current income taxes, Federal	54.8	19.4	-19.5
Current income taxes, State	8.9	1.3	5.6
Deferred income taxes, Federal	79	99.8	141.2
Deferred income taxes, State	13.5	18.6	14.7
Amortization of investment tax credits	-0.3	-0.3	-0.3
Income tax expense from continuing operations	155.9	138.8	141.7
Continuing Operations [Member]
Income Taxes [Line Items]
Current income taxes, Federal	0.5	2.2	15.7
Current income taxes, State	0	0	0
Deferred income taxes, Federal	111	98.8	89.2
Deferred income taxes, State	27.7	11.9	16.2
Amortization of investment tax credits	-0.3	-0.3	-0.3
Income tax expense from continuing operations	138.9	112.6	120.8
Discontinued Operations [Member]
Income Taxes [Line Items]
Current income taxes, Federal	0	0	0
Current income taxes, Foreign	0	0	6.8
Current income taxes, State	-0.4	-3.5	1.1
Deferred income taxes, Federal	-44	-0.3	28.6
Deferred income taxes, Foreign	0	0	0
Deferred income taxes, State	-5	0	2.9
Income tax expense from discontinued operations	($49.40)	($3.80)	$39.40

Income_Taxes_Schedule_of_Incom1

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Income tax expense at the federal statutory rate of 35%	$120.90	$105.50	$111.20
State income tax, net of federal income tax	17	7.5	10.4
Valuation allowance	0.9	0	1.1
Other	0.1	-0.4	-1.9
Income tax expense from continuing operations	138.9	112.6	120.8
Income tax expense as a percent of income from continuing operations, before income taxes	40.20%	37.40%	38.00%
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%	145.7	127.5	129.1
State income tax, net of federal income tax	14.5	13	13.2
Other	-4.3	-1.7	-0.6
Income tax expense from continuing operations	$155.90	$138.80	$141.70
Income tax expense as a percent of income from continuing operations, before income taxes	37.50%	38.10%	38.40%

Income_Taxes_Schedule_of_Incom2

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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_Defer

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred tax liabilities
Property related	$1,391.30	$1,164.20
Pension	62.3	52.8
Total deferred tax liabilities	1,453.60	1,217
Deferred tax assets
Alternative minimum tax credit carryforward	214	213
Loss and credit carryforwards	566.7	479.8
Other postretirement benefits	71.5	68.9
Other	159.6	111.6
Total deferred tax assets	1,011.80	873.3
Valuation allowance	-4.6	0
Total deferred tax assets, net of valuation allowance	1,007.20	873.3
Total deferred tax liability, net	446.4	343.7
Less: Current portion of deferred tax asset	-72.8	-100.3
Long-term portion of deferred tax liability, net	519.2	444
Tampa Electric Company [Member]
Deferred tax liabilities
Property related	1,328.80	1,166.40
Pension and postretirement benefits	72.5	70.5
Pension	51.8	43.2
Total deferred tax liabilities	1,453.10	1,280.10
Deferred tax assets
Loss and credit carryforwards	77.7	4.8
Medical benefits	51	50.9
Insurance reserves	29	29.1
Pension and postretirement benefits	72.5	70.5
Capitalized energy conservation assistance costs	20.3	19.6
Other	18.3	20.3
Total deferred tax assets	268.8	195.2
Total deferred tax liability, net	1,184.30	1,084.90
Less: Current portion of deferred tax asset	-24.8	-29.4
Long-term portion of deferred tax liability, net	$1,209.10	$1,114.30

Income_Taxes_Schedule_of_Defer1

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Components Of Deferred Tax Assets And Liabilities [Line Items]
Stockholder's equity increment	$1.10
Valuation allowance	4.6	0
TECO Coal [Member] \| Discontinued Operations [Member]
Components Of Deferred Tax Assets And Liabilities [Line Items]
Valuation allowance	$3.60

Income_Taxes_Schedule_of_Unrec

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Beginning Balance	$0	$2.90	$4.10
Decreases due to expiration of statute of limitations	0	-2.9	0
Dispositions	0	0	-1.2
Ending Balance	$0	$0	$2.90

Employee_Postretirement_Benefi2

Employee Postretirement Benefits - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
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		110.80%
Estimated percentage of qualified pension plan's actuarial value of assets	115.90%
Percentage of tax-free subsidy under prescription drug programs	28.00%
Amortization period of Regulatory Asset	12 years
Tax of premiums paid for retiree medical benefits plan	40.00%
Accumulated benefit obligation of defined benefit pension plans	$685	$624.10
Percentage of defined benefit plan actual return on plan assets	7.90%
Plan assets	648	593
Employer contributions	47.5	42
Employer contributions in next fiscal year	43.7
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	13.1	11.3	7
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	1-Jan-15
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	2.5
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	36.5
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
TECO Coal [Member]
Defined Benefit Plan Disclosure [Line Items]
Black lung liability	24.7	24.5
Expenses related to black lung liability	2.4	2.2	1.8
Settlement charge, related to unfunded black lung obligations	7.9
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
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		110.80%
Estimated percentage of qualified pension plan's actuarial value of assets	115.90%
Percentage of tax-free subsidy under prescription drug programs	28.00%
Amortization period of Regulatory Asset	12 years
Tax of premiums paid for retiree medical benefits plan	40.00%
Plan assets	648	593
Employer contributions	38.2	33.5
Employer contributions in next fiscal year	33.5
Description of defined contribution plan	Effective April 2013, 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	10.2	9.1	6
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] \| Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	1.5
Tampa Electric Company [Member] \| Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	29
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of defined benefit plan actual return on plan assets	7.90%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	201.5	208.1	230.3
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.5
Other postretirement benefits plan assets	0
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	1.9
Plan assets	18.8	0	0
Employer contributions	-1	11.9
Employer contributions in next fiscal year	14.3
Net periodic benefit cost	12.8	12.4	15.2
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	1.9
Other Postretirement Benefits [Member] \| NMGC [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions in next fiscal year	3.6
Other Postretirement Benefits [Member] \| NMGC [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets	18.8
Other Postretirement Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefits plan assets	0
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	1.9
Employer contributions in next fiscal year	9.1
Net periodic benefit cost	10.4	10	12.4
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	1.9
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	201.5	208.1	230.3
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	0
Plan assets	18.8	0	0
Employer contributions	-1	11.9
Net periodic benefit cost	12.8	12.4	15.2
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year	0
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	728.9	666	715
Estimated net loss amortization from AOCI into net periodic benefit cost related to defined benefit plan	3.3
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.3
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.1
Plan assets	648	593	529.1
Employer contributions	47.5	44.6
Net periodic benefit cost	25.7	29.8	24.9
Pension Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.1
Net periodic benefit cost	14.8	21.7	18.3
Pension Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	728.9	666	715
Plan assets	648	593	529.1
Employer contributions	47.5	44.6
Net periodic benefit cost	25.7	29.8	24.9
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	1.2	2.6
Employer contributions in next fiscal year	4.9
SERP [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	0.8	1
Employer contributions in next fiscal year	$0.60

Employee_Postretirement_Benefi3

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	$666	$715
Service cost	18.3	18.2	17
Interest cost	32	28.9	30.1
Plan participantsb contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	48.3	-50.4
Gross benefits paid	-39.9	-43.1
Transfer in due to the effect of business combination	0	0
Plan curtailment	4	0
Special termination benefit	0.2	0	0
Settlements	0	-2.6
Net benefit obligation at end of year	728.9	666	715
Pension Benefits [Member] \| TECO Energy [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	666	715
Service cost	18.3	18.2	17
Interest cost	32	28.9	30.1
Plan participantsb contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	48.3	-50.4
Gross benefits paid	-39.9	-43.1
Transfer in due to the effect of business combination	0	0
Plan curtailment	4	0
Special termination benefit	0.2	0	0
Settlements	0	-2.6
Net benefit obligation at end of year	728.9	666	715
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	208.1	230.3
Service cost	2.5	2.5	2.4
Interest cost	10.8	9.3	10.1
Plan participantsb contributions	2.8	2.9
Plan amendments	-23.2	0
Actuarial loss (gain)	1.5	-22.1
Gross benefits paid	-16	-15
Transfer in due to the effect of business combination	26.7	0
Plan curtailment	-11.7	0
Special termination benefit	0	0	0
Settlements	0	0
Federal subsidy on benefits paid	0	0.2
Net benefit obligation at end of year	201.5	208.1	230.3
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	208.1	230.3
Service cost	2.5	2.5	2.4
Interest cost	10.8	9.3	10.1
Plan participantsb contributions	2.8	2.9
Plan amendments	-23.2	0
Actuarial loss (gain)	1.5	-22.1
Gross benefits paid	-16	-15
Transfer in due to the effect of business combination	26.7	0
Plan curtailment	-11.7	0
Special termination benefit	0	0	0
Settlements	0	0
Federal subsidy on benefits paid	0		0.2
Net benefit obligation at end of year	$201.50	$208.10	$230.30

Employee_Postretirement_Benefi4

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Change in plan assets
Fair value of plan assets at beginning of year	$593
Employer contributions	47.5	42
Fair value of plan assets at end of year	648	593
Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	593	529.1
Actual return on plan assets	46.4	63.7
Employer contributions	47.5	44.6
Employer direct benefit payments	1	1.3
Plan participantsb contributions	0	0
Transfer in due to acquisition	0	0
Settlements	0	-2.6
Net benefits paid	-39.9	-43.1
Fair value of plan assets at end of year	648	593
Pension Benefits [Member] \| TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year	593	529.1
Actual return on plan assets	46.4	63.7
Employer contributions	47.5	44.6
Employer direct benefit payments	1	1.3
Plan participantsb contributions	0	0
Settlements	0	-2.6
Net benefits paid	-39.9	-43.1
Fair value of plan assets at end of year	648	593
Transfer in due to acquisition	0	0
Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0.1	0
Employer contributions	-1	11.9
Employer direct benefit payments	16
Plan participantsb contributions	2.8	2.9
Transfer in due to acquisition	16.9	0
Settlements	0	0
Net benefits paid	-16	-14.8
Fair value of plan assets at end of year	18.8	0
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0.1	0
Employer contributions	-1	11.9
Employer direct benefit payments	16
Plan participantsb contributions	2.8	2.9
Settlements	0	0
Net benefits paid	-16	-14.8
Fair value of plan assets at end of year	18.8	0
Transfer in due to acquisition	$16.90	$0

Employee_Postretirement_Benefi5

Employee Postretirement Benefits - Schedule of Funded Status (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$648	$593
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	648	593	529.1
Less: Benefit obligation (PBO/APBO)	728.9	666	715
Funded status at end of year	-80.9	-73
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Unrecognized net actuarial loss	203.7	173.1
Unrecognized prior service (benefit) cost	0	-0.4
Net amount required to be recognized at end of year	122.8	99.7
Pension Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	648	593	529.1
Less: Benefit obligation (PBO/APBO)	728.9	666	715
Funded status at end of year	-80.9	-73
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Unrecognized net actuarial loss	203.7	173.1
Unrecognized prior service (benefit) cost	0	-0.4
Net amount required to be recognized at end of year	122.8	99.7
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18.8	0	0
Less: Benefit obligation (PBO/APBO)	201.5	208.1	230.3
Funded status at end of year	-182.7	-208.1
Unrecognized costs in regulated asset acquired in business combination	6.4	0	0
Unrecognized net actuarial loss	9.6	19.7
Unrecognized prior service (benefit) cost	-24	-0.7
Net amount required to be recognized at end of year	-190.7	-189.1
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18.8	0	0
Less: Benefit obligation (PBO/APBO)	201.5	208.1	230.3
Funded status at end of year	-182.7	-208.1
Unrecognized costs in regulated asset acquired in business combination	6.4	0	0
Unrecognized net actuarial loss	9.6	19.7
Unrecognized prior service (benefit) cost	-24	-0.7
Net amount required to be recognized at end of year	($190.70)	($189.10)

Employee_Postretirement_Benefi6

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$167.40	$139.60
Accrued benefit costs and other current liabilities	-4.9	-3.3
Deferred credits and other liabilities	-76	-69.7
Accumulated other comprehensive loss (income), pretax	36.3	33.1
Net amount recognized at end of year	122.8	99.7
Pension Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	167.4	139.6
Accrued benefit costs and other current liabilities	-4.9	-3.3
Deferred credits and other liabilities	-76	-69.7
Accumulated other comprehensive loss (income), pretax	36.3	33.1
Net amount recognized at end of year	122.8	99.7
Pension Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	167.4	139.6
Accrued benefit costs and other current liabilities	-0.6	-0.9
Deferred credits and other liabilities	-53.5	-50.1
Net amount recognized at end of year	113.3	88.6
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	26.6	43.2
Accrued benefit costs and other current liabilities	-10.7	-13.3
Deferred credits and other liabilities	-172	-194.8
Accumulated other comprehensive loss (income), pretax	-34.6	-24.2
Net amount recognized at end of year	-190.7	-189.1
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	26.6	43.2
Accrued benefit costs and other current liabilities	-10.7	-13.3
Deferred credits and other liabilities	-172	-194.8
Accumulated other comprehensive loss (income), pretax	-34.6	-24.2
Net amount recognized at end of year	-190.7	-189.1
Other Postretirement Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	20.4	43.2
Accrued benefit costs and other current liabilities	-9.1	-10.8
Deferred credits and other liabilities	-137.1	-158.3
Net amount recognized at end of year	($125.80)	($125.90)

Employee_Postretirement_Benefi7

Employee Postretirement Benefits - Schedule of Funded Status (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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_Benefi8

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$36	$32.70
Prior service cost (credit)	0.3	0.4
Amount recognized, pretax	36.3	33.1
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	-30.1	-23.8
Prior service cost (credit)	-4.5	-0.4
Amount recognized, pretax	($34.60)	($24.20)

Employee_Postretirement_Benefi9

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.26%			4.26%	5.12%
Rate of compensation increasebweighted	3.87%			3.87%	3.73%
Discount rate	4.33%	4.28%	5.12%		4.20%	4.80%
Expected long-term return on plan assets	7.00%	7.00%	7.25%		7.50%	7.50%
Rate of compensation increase				3.73%	3.76%	3.83%
Pension Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.26%			4.26%	5.12%
Rate of compensation increasebweighted	3.87%			3.87%	3.73%
Discount rate	4.33%	4.28%	5.12%		4.20%	4.80%
Expected long-term return on plan assets	7.00%	7.00%	7.25%		7.50%	7.50%
Rate of compensation increase				3.73%	3.76%	3.83%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.21%			4.21%	5.10%
Rate of compensation increasebweighted	3.86%			3.86%	3.71%
Healthcare cost trend rate
Immediate rate				7.09%	7.25%
Ultimate rate				4.57%	4.50%
Year rate reaches ultimate	2025			2025	2025
Other Postretirement Benefits [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.21%			4.21%	5.10%
Rate of compensation increasebweighted	3.86%			3.86%	3.71%
Healthcare cost trend rate
Immediate rate				7.09%	7.25%
Ultimate rate				4.57%	4.50%
Year rate reaches ultimate	2025			2025	2025
Other Postretirement Benefits [Member] \| Net Periodic Benefit Cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate				5.10%	4.18%	4.74%
Expected long-term return on plan assets				5.75%
Rate of compensation increase				3.71%	3.74%	3.82%
Healthcare cost trend rate
Immediate rate				7.25%	7.50%	7.75%
Ultimate rate				4.50%	4.50%	4.50%
Year rate reaches ultimate	2025			2025	2025	2025
Other Postretirement Benefits [Member] \| Net Periodic Benefit Cost [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate				5.10%	4.18%	4.74%
Expected long-term return on plan assets				5.75%
Rate of compensation increase				3.71%	3.74%	3.82%
Healthcare cost trend rate
Immediate rate				7.25%	7.50%	7.75%
Ultimate rate				4.50%	4.50%	4.50%
Year rate reaches ultimate	2025			2025	2025	2025

Recovered_Sheet1

Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	$0.40
Effect on periodic cost - Decrease	-0.4
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	0.3
Effect on periodic cost - Decrease	-0.3
Assumed One-percentage-point Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	7
Effect on postretirement benefit obligation - Decrease	-6.4
Assumed One-percentage-point Change [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	3.7
Effect on postretirement benefit obligation - Decrease	($3.60)

Recovered_Sheet2

Employee Postretirement Benefits - Schedule of Amounts Recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$18.30	$18.20	$17
Interest cost	32	28.9	30.1
Expected return on plan assets	-41.8	-38.4	-37.1
Amortization of:
Actuarial loss	13.5	20.5	15.3
Prior service (benefit) cost	-0.4	-0.4	-0.4
Transition obligation	0	0	0
Curtailment loss (gain)	3.9	0	0
Special termination benefit	0.2	0	0
Settlement loss	0	1	0
Net periodic benefit cost	25.7	29.8	24.9
Prior service cost	0	0	0
Net loss (gain)	44.1	-75.7	34
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Amortization of:
Actuarial gain (loss)	-13.5	-21.5	-15.3
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	31	-96.8	19.1
Total recognized in net periodic benefit cost, OCI and regulatory assets	56.7	-67	44
Pension Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	18.3	18.2	17
Interest cost	32	28.9	30.1
Expected return on plan assets	-41.8	-38.4	-37.1
Amortization of:
Actuarial loss	13.5	20.5	15.3
Prior service (benefit) cost	-0.4	-0.4	-0.4
Transition obligation	0	0	0
Curtailment loss (gain)	3.9	0	0
Special termination benefit	0.2	0	0
Settlement loss	0	1	0
Net periodic benefit cost	25.7	29.8	24.9
Prior service cost	0	0	0
Net loss (gain)	44.1	-75.7	34
Unrecognized costs in regulated asset acquired in business combination	0	0	0
Amortization of:
Actuarial gain (loss)	-13.5	-21.5	-15.3
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	31	-96.8	19.1
Total recognized in net periodic benefit cost, OCI and regulatory assets	56.7	-67	44
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.5	2.5	2.4
Interest cost	10.8	9.3	10.1
Expected return on plan assets	-0.3	0	0
Amortization of:
Actuarial loss	0.2	1	0.1
Prior service (benefit) cost	-0.2	-0.4	0.8
Transition obligation	0	0	1.8
Curtailment loss (gain)	-0.2	0	0
Special termination benefit	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	12.8	12.4	15.2
Prior service cost	-23.6	0	-5.2
Net loss (gain)	-9.9	-15.6	16.3
Unrecognized costs in regulated asset acquired in business combination	6.4	0	0
Amortization of:
Actuarial gain (loss)	-0.2	-1	-0.1
Prior service (benefit) cost	0.2	0.3	-0.8
Transition obligation	0	0	-1.8
Total recognized in OCI and regulatory assets	-27.1	-16.3	8.4
Total recognized in net periodic benefit cost, OCI and regulatory assets	-14.3	-3.9	23.6
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.5	2.5	2.4
Interest cost	10.8	9.3	10.1
Expected return on plan assets	-0.3	0	0
Amortization of:
Actuarial loss	0.2	1	0.1
Prior service (benefit) cost	-0.2	-0.4	0.8
Transition obligation	0	0	1.8
Curtailment loss (gain)	-0.2	0	0
Special termination benefit	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	12.8	12.4	15.2
Prior service cost	-23.6	0	-5.2
Net loss (gain)	-9.9	-15.6	16.3
Unrecognized costs in regulated asset acquired in business combination	6.4	0	0
Amortization of:
Actuarial gain (loss)	-0.2	-1	-0.1
Prior service (benefit) cost	0.2	0.3	-0.8
Transition obligation	0	0	-1.8
Total recognized in OCI and regulatory assets	-27.1	-16.3	8.4
Total recognized in net periodic benefit cost, OCI and regulatory assets	($14.30)	($3.90)	$23.60

Recovered_Sheet3

Employee Postretirement Benefits - Schedule of Pension Plan Assets (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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	48.00%
Equity Securities [Member] \| Target Allocation [Member] \| Maximum [Member]
Asset Category
Target Allocation	54.00%
Equity Securities [Member] \| Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	50.00%	54.00%
Fixed Income Securities [Member] \| Target Allocation [Member] \| Minimum [Member]
Asset Category
Target Allocation	46.00%
Fixed Income Securities [Member] \| Target Allocation [Member] \| Maximum [Member]
Asset Category
Target Allocation	52.00%
Fixed Income Securities [Member] \| Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	50.00%	46.00%

Recovered_Sheet4

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$648	$593
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	648	593
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.4
Cash [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.4
Short Term Investment Fund (STIF) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		7.9
Treasury Bills (T bills) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.3
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	278	280.7
Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	278	280.7
Level 1 [Member] \| Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.4
Level 1 [Member] \| Cash [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.4
Level 1 [Member] \| Short Term Investment Fund (STIF) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		7.9
Level 1 [Member] \| Treasury Bills (T bills) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	370	312.3
Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	370	312.3
Level 2 [Member] \| Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 2 [Member] \| Cash [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
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
Level 2 [Member] \| Treasury Bills (T bills) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.3
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
Level 3 [Member] \| Cash [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
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
Level 3 [Member] \| Treasury Bills (T bills) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.4	44.7
Accounts Receivable [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.4	44.7
Accounts Receivable [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.4	44.7
Accounts Receivable [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.4	44.7
Accounts Receivable [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] \| Level 3 [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	-5.3	-40.8
Accounts Payable [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-5.3	-40.8
Accounts Payable [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-5.3	-40.8
Accounts Payable [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-5.3	-40.8
Accounts Payable [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] \| Level 3 [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	16.6	18.9
Cash Equivalents [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16.6	18.9
Cash Equivalents [Member] \| Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7.6	7.9
Cash Equivalents [Member] \| Short Term Investment Fund (STIF) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7.6
Cash Equivalents [Member] \| Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.2	0.3
Cash Equivalents [Member] \| Treasury Bills (T bills) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.2
Cash Equivalents [Member] \| Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8.8
Cash Equivalents [Member] \| Discounted Notes [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8.8
Cash Equivalents [Member] \| Repurchase Agreements
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8.8
Cash Equivalents [Member] \| Repurchase Agreements \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8.8
Cash Equivalents [Member] \| Commercial Paper
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.4
Cash Equivalents [Member] \| Commercial Paper \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.4
Cash Equivalents [Member] \| Money Market Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1.5
Cash Equivalents [Member] \| Money Market Funds \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1.5
Cash Equivalents [Member] \| Level 1 [Member] \| Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7.6	7.9
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	7.6
Cash Equivalents [Member] \| Level 1 [Member] \| Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	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
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
Cash Equivalents [Member] \| Level 1 [Member] \| Repurchase Agreements
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 1 [Member] \| Repurchase Agreements \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 1 [Member] \| Commercial Paper
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 1 [Member] \| Commercial Paper \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 1 [Member] \| Money Market Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 1 [Member] \| Money Market Funds \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	11
Cash Equivalents [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	11
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
Cash Equivalents [Member] \| Level 2 [Member] \| Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.2	0.3
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	0.2
Cash Equivalents [Member] \| Level 2 [Member] \| Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8.8
Cash Equivalents [Member] \| Level 2 [Member] \| Discounted Notes [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8.8
Cash Equivalents [Member] \| Level 2 [Member] \| Repurchase Agreements
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8.8
Cash Equivalents [Member] \| Level 2 [Member] \| Repurchase Agreements \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8.8
Cash Equivalents [Member] \| Level 2 [Member] \| Commercial Paper
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.4
Cash Equivalents [Member] \| Level 2 [Member] \| Commercial Paper \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.4
Cash Equivalents [Member] \| Level 2 [Member] \| Money Market Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1.5
Cash Equivalents [Member] \| Level 2 [Member] \| Money Market Funds \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1.5
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] \| 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
Cash Equivalents [Member] \| Level 3 [Member] \| Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	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
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
Cash Equivalents [Member] \| Level 3 [Member] \| Repurchase Agreements
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 3 [Member] \| Repurchase Agreements \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 3 [Member] \| Commercial Paper
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 3 [Member] \| Commercial Paper \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 3 [Member] \| Money Market Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Cash Equivalents [Member] \| Level 3 [Member] \| Money Market Funds \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	319.5	319.7
Equity Securities [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	319.5	319.7
Equity Securities [Member] \| Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	91.6
Equity Securities [Member] \| Common Stock [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	91.6
Equity Securities [Member] \| American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.3	3
Equity Securities [Member] \| American Depository Receipt (ADR) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.3	3
Equity Securities [Member] \| Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.5	1.7
Equity Securities [Member] \| Real Estate Investment Trust (REIT) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.5	1.7
Equity Securities [Member] \| Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.8	0.8
Equity Securities [Member] \| Preferred Stocks [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.8	0.8
Equity Securities [Member] \| Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171.3	172.6
Equity Securities [Member] \| Equity Mutual Funds [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171.3	172.6
Equity Securities [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	273.9	268.9
Equity Securities [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	273.9	268.9
Equity Securities [Member] \| Level 1 [Member] \| Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	91.6
Equity Securities [Member] \| Level 1 [Member] \| Common Stock [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	91.6
Equity Securities [Member] \| Level 1 [Member] \| American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.3	3
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	1.3	3
Equity Securities [Member] \| Level 1 [Member] \| Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.5	1.7
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	2.5	1.7
Equity Securities [Member] \| Level 1 [Member] \| Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.8	0
Equity Securities [Member] \| Level 1 [Member] \| Preferred Stocks [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.8	0
Equity Securities [Member] \| Level 1 [Member] \| Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171.3	172.6
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	171.3	172.6
Equity Securities [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50.8
Equity Securities [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50.8
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	0.8
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	0.8
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	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	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
Equity Securities [Member] \| Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50
Equity Securities [Member] \| Commingled Fund [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50
Equity Securities [Member] \| Commingled Fund [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] \| Commingled Fund [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] \| Commingled Fund [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50
Equity Securities [Member] \| Commingled Fund [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45.6	50
Equity Securities [Member] \| Commingled Fund [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Equity Securities [Member] \| Commingled Fund [Member] \| Level 3 [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	315.7	251.2
Debt Securities [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	315.7	251.2
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 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	315.7	251.2
Debt Securities [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	315.7	251.2
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] \| Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	129.2	94.1
Debt Securities [Member] \| Commingled Fund [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	129.2	94.1
Debt Securities [Member] \| Commingled Fund [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Commingled Fund [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Commingled Fund [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	129.2	94.1
Debt Securities [Member] \| Commingled Fund [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	129.2	94.1
Debt Securities [Member] \| Commingled Fund [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Commingled Fund [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6.1	7.3
Debt Securities [Member] \| Municipal Bonds [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6.1	7.3
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6.1	7.3
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6.1	7.3
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Municipal Bonds [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47.9	35.7
Debt Securities [Member] \| Government Bonds [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47.9	35.7
Debt Securities [Member] \| Government Bonds [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Government Bonds [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Government Bonds [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47.9	35.7
Debt Securities [Member] \| Government Bonds [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47.9	35.7
Debt Securities [Member] \| Government Bonds [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Government Bonds [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	19.6
Debt Securities [Member] \| Corporate Bonds [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	19.6
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	19.6
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22	19.6
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Corporate Bonds [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.4
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.4
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.4
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.4
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Asset Backed Securities (ABS) [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9.6	6.7
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9.6	6.7
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9.6	6.7
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9.6	6.7
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mortgage Back Securities (MBS) [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2.3
Debt Securities [Member] \| CMO [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2.3
Debt Securities [Member] \| CMO [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| CMO [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| CMO [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2.3
Debt Securities [Member] \| CMO [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	2.3
Debt Securities [Member] \| CMO [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| CMO [Member] \| Level 3 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98.6	85.1
Debt Securities [Member] \| Mutual Funds [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98.6	85.1
Debt Securities [Member] \| Mutual Funds [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mutual Funds [Member] \| Level 1 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mutual Funds [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98.6	85.1
Debt Securities [Member] \| Mutual Funds [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98.6	85.1
Debt Securities [Member] \| Mutual Funds [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Debt Securities [Member] \| Mutual Funds [Member] \| Level 3 [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	-0.4	-0.9
Derivative [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.4	-0.9
Derivative [Member] \| Short Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.3	0.2
Derivative [Member] \| Short Futures [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.3	0.2
Derivative [Member] \| Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.7	0.2
Derivative [Member] \| Purchased Options [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.7	0.2
Derivative [Member] \| Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.8	-0.4
Derivative [Member] \| Written Options [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.8	-0.4
Derivative [Member] \| Swap
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		-0.9
Derivative [Member] \| Swap \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		-0.9
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] \| Short Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] \| Level 1 [Member] \| Short Futures [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	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] \| Swap
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] \| Level 1 [Member] \| Swap \| 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	-0.4	-0.9
Derivative [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.4	-0.9
Derivative [Member] \| Level 2 [Member] \| Short Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.3	0.2
Derivative [Member] \| Level 2 [Member] \| Short Futures [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.3	0.2
Derivative [Member] \| Level 2 [Member] \| Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.7	0.2
Derivative [Member] \| Level 2 [Member] \| Purchased Options [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.7	0.2
Derivative [Member] \| Level 2 [Member] \| Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.8	-0.4
Derivative [Member] \| Level 2 [Member] \| Written Options [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	-0.8	-0.4
Derivative [Member] \| Level 2 [Member] \| Swap
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		-0.9
Derivative [Member] \| Level 2 [Member] \| Swap \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		-0.9
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] \| Short Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Derivative [Member] \| Level 3 [Member] \| Short Futures [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	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] \| Swap
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Derivative [Member] \| Level 3 [Member] \| Swap \| 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	0.1	0.2
Miscellaneous [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.1	0.2
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	0.1	0.2
Miscellaneous [Member] \| Level 2 [Member] \| Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.1	0.2
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

Recovered_Sheet5

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2015	$73.40
Expected Benefit Payments - 2016	47.9
Expected Benefit Payments - 2017	47.8
Expected Benefit Payments - 2018	51.9
Expected Benefit Payments - 2019	58.3
Expected Benefit Payments - 2020-2024	285.5
Pension Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2015	73.4
Expected Benefit Payments - 2016	47.9
Expected Benefit Payments - 2017	47.8
Expected Benefit Payments - 2018	51.9
Expected Benefit Payments - 2019	58.3
Expected Benefit Payments - 2020-2024	285.5
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2015	11.5
Expected Benefit Payments - 2016	12
Expected Benefit Payments - 2017	12.5
Expected Benefit Payments - 2018	12.9
Expected Benefit Payments - 2019	13.4
Expected Benefit Payments - 2020-2024	69.5
Other Postretirement Benefits [Member] \| TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2015	11.5
Expected Benefit Payments - 2016	12
Expected Benefit Payments - 2017	12.5
Expected Benefit Payments - 2018	12.9
Expected Benefit Payments - 2019	13.4
Expected Benefit Payments - 2020-2024	$69.50

ShortTerm_Debt_Credit_Faciliti

Short-Term Debt - Credit Facilities (Detail) (USD $)	Dec. 31, 2014	Sep. 02, 2014	Dec. 31, 2013	Dec. 17, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 02, 2014	Dec. 31, 2013	Dec. 17, 2013
Line Of Credit Facility [Line Items]
Credit Facilities	$900	$40	$675
Borrowings Outstanding	139		84
Letters of Credit Outstanding	2.3		0.7
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475		475	200
Borrowings Outstanding	58		84
Letters of Credit Outstanding	0.6		0.7
Tampa Electric Company [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325		325
Borrowings Outstanding	12		6
Letters of Credit Outstanding	0.6		0.7
Tampa Electric Company [Member] \| 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150		150
Borrowings Outstanding	46		78
Letters of Credit Outstanding	0		0
TECO Energy [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300		200
Borrowings Outstanding	50		0
Letters of Credit Outstanding	0		0
New Mexico Gas Company [Member] \| 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125		0
Borrowings Outstanding	31		0
Letters of Credit Outstanding	$1.70		$0

ShortTerm_Debt_Credit_Faciliti1

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Line Of Credit Facility [Line Items]
Credit facility maturity date	17-Dec-18	17-Dec-18
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	17-Dec-18	17-Dec-18

ShortTerm_Debt_Additional_Info

Short-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 17, 2013	Sep. 02, 2014	Jun. 24, 2013	Sep. 30, 2014	Feb. 03, 2015
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	$900	$675		40
Credit facility maturity date	17-Dec-18	17-Dec-18
Senior unsecured bridge credit					1,075
NMGC Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity						125
Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity							150
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	0.70%	0.56%
Line Of Credit Facility Maximum Borrowing Capacity	475	475	200
Debt instrument maturity date	31-Mar-15
Credit facility maturity date	17-Dec-18	17-Dec-18
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
Tampa Electric Company [Member] \| Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity							150
Tampa Electric Company [Member] \| 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	150	150
Debt instrument maturity date	31-Mar-15
Credit Facility Amendment Date	28-Feb-15
Tampa Electric Company [Member] \| 1-year Accounts Receivable Facility [Member] \| Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity							150
Tampa Electric Company [Member] \| Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity			325			325
Basis spread on federal funds rate		0.50%
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	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	1.16%	0.56%
Line Of Credit Facility Maximum Borrowing Capacity			200
Increase of credit facility			100
TECO Finance [Member] \| Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity						300
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate	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
Credit facility maturity date				17-Dec-18
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 Bankbs 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
Minimum [Member] \| Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage	0.13%
Minimum [Member] \| Tampa Electric Company [Member] \| Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		25-Oct-16
Minimum [Member] \| TECO Energy [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		25-Oct-16
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		17-Dec-18
Maximum [Member] \| TECO Energy [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		17-Dec-18
Maximum [Member] \| TECO Energy [Member] \| Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Maximum debt capitalization ratio	70.00%

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended				48 Months Ended	65 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 16, 2014	Feb. 08, 2011	Sep. 03, 2013	Mar. 15, 2012	Mar. 15, 2012	Sep. 01, 2013	15-May-14	Sep. 02, 2014
Debt Instrument [Line Items]
Long-term debt, carrying amount	$3,628.50	$2,921.10
Estimated fair value	3,987.80	3,184.10
Ownership of parent company	100.00%
Purchase in lieu of redemption	83.3	51.6	650.4
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
New Mexico Gas Company 4.87 % Notes due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued					200
Debt instrument, offering date				16-Jul-14	8-Feb-11
Debt instrument maturity date					8-Feb-21
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Debt instrument maturity date	31-Mar-15
Purchase in lieu of redemption	83.3	51.6	608
Tampa Electric Company [Member] \| HCIDA Pollution Control Revenue Refunding Bonds [Member]
Debt Instrument [Line Items]
Interest at the initial term rate per annum								5.00%	5.15%
Purchase in lieu of redemption						51.6	86
Debt instrument, repurchase date						3-Sep-13	15-Mar-12
Tampa Electric Company [Member] \| 4.35% Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued										300
Interest at the initial term rate per annum										4.35%
Debt instrument principal amount market price percentage										99.93%
Proceeds from notes net of issuance										296.6
Redeemable principal amount percentage										100.00%
Debt instrument, offering date										15-May-14
Debt instrument, start date of redemption										15-Nov-43
Libor interest rate										0.15%
Debt instrument, maturity year										2044
Redeemable principal amount percentage										100.00%
Debt instrument maturity date										1-Jan-44
Stated interest rate	4.35%									4.35%
Basis spread on federal funds rate										0.15%
NMGI [Member] \| Series A Senior Unsecured Notes 2.71% Notes due 2019 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued											50
Interest at the initial term rate per annum											2.71%
Debt instrument, offering date											2-Sep-14
Debt instrument, start date of redemption											30-Jul-19
NMGI [Member] \| Series B Senior Unsecured 3.64 % Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued											150
Interest at the initial term rate per annum											3.64%
Debt instrument principal amount market price percentage											100.00%
Proceeds from notes net of issuance											198.4
Redeemable principal amount percentage											100.00%
Debt instrument, start date of redemption											30-Jul-24
Basis spread on federal funds rate											0.50%
New Mexico Gas Company [Member] \| Senior Unsecured 3.54 % Notes due 2026 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued											70
Interest at the initial term rate per annum											3.54%
Debt instrument principal amount market price percentage											100.00%
Proceeds from notes net of issuance											$69.30
Redeemable principal amount percentage											100.00%
Debt instrument, offering date											2-Sep-14
Debt instrument, start date of redemption											30-Jul-26
Debt instrument, maturity year											2026
Basis spread on federal funds rate											0.50%
New Mexico Gas Company [Member] \| New Mexico Gas Company 4.87 % Notes due 2021 [Member]
Debt Instrument [Line Items]
Interest at the initial term rate per annum					4.87%
Debt instrument, maturity year					2021

LongTerm_Debt_Schedule_of_Matu

Long-Term Debt - Schedule of Maturities of Long-Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	$3,610.50	$2,923.80
TECO Finance [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	1,041.20	1,041.20
Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	83.3
2016	83.4
2017	0
2018	254.2
2019	0
Thereafter	1,436.70
Total long-term debt maturities	1,857.60	1,650.90
PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	0
2016	0
2017	0
2018	50
2019	0
Thereafter	191.7
Total long-term debt maturities	241.7	231.7
NMGI [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	200	0
NMGC [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total long-term debt maturities	270	0
Debt Maturities [Member] \| TECO Finance [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	191.2
2016	250
2017	300
2018	0
2019	0
Thereafter	300
Total long-term debt maturities	1,041.20
Debt Maturities [Member] \| Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	83.3
2016	83.4
2017	0
2018	254.2
2019	0
Thereafter	1,436.70
Total long-term debt maturities	1,857.60
Debt Maturities [Member] \| PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	0
2016	0
2017	0
2018	50
2019	0
Thereafter	191.7
Total long-term debt maturities	241.7
Debt Maturities [Member] \| NMGI [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	0
2016	0
2017	0
2018	0
2019	50
Thereafter	150
Total long-term debt maturities	200
Debt Maturities [Member] \| NMGC [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	0
2016	0
2017	0
2018	0
2019	0
Thereafter	270
Total long-term debt maturities	270
Debt Maturities [Member] \| TECO Energy [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2015	274.5
2016	333.4
2017	300
2018	304.2
2019	50
Thereafter	2,348.40
Total long-term debt maturities	$3,610.50

LongTerm_Debt_Schedule_of_Long

Long-Term Debt - Schedule of Long Term Debt Outstanding (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt, total	$3,610.50	$2,923.80
Unamortized debt discount, net	18	-2.7
Total carrying amount of long-term debt	3,628.50	2,921.10
Less amount due within one year	274.5	83.3
Long-term debt, less amount due within one year	3,354	2,837.80
TECO Finance [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,041.20	1,041.20
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,857.60	1,650.90
Less amount due within one year	83.3	83.3
Long-term debt, less amount due within one year	2,013.80	1,797.50
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	241.7	231.7
NMGI [Member]
Debt Instrument [Line Items]
Long-term debt, total	200	0
NMGC [Member]
Debt Instrument [Line Items]
Long-term debt, total	270	0
6.75% Notes [Member] \| TECO Finance [Member]
Debt Instrument [Line Items]
Due	2015
Long-term debt, total	191.2	191.2
4.00% Notes [Member] \| TECO Finance [Member]
Debt Instrument [Line Items]
Due	2016
Long-term debt, total	250	250
6.572% Notes [Member] \| TECO Finance [Member]
Debt Instrument [Line Items]
Due	2017
Long-term debt, total	300	300
5.15% Notes [Member] \| TECO Finance [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	300	300
5.65% Refunding bonds [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
Variable Rate Bonds Repurchased In 2008 [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	0	0
5.15% Refunding bonds [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	0
1.5% term rate bonds repurchased in 2011 [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
5.0% Refunding bonds [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
6.25% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Maturity range start	2014
Maturity range end	2016
Long-term debt, total	166.7	250
6.10% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	200	200
6.10% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	50	50
5.40% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
5.40% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	46.7	46.7
2.60% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225	225
2.60% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	25	25
6.55% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250	250
6.15% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190	190
6.15% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	60	60
4.10% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	250	250
4.10% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	50	50
4.35% Notes [Member] \| Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	290	0
4.35% Notes [Member] \| PGS [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	10	0
2.71 % Notes [Member] \| NMGI [Member]
Debt Instrument [Line Items]
Due	2019
Long-term debt, total	50	0
3.64 % Notes [Member] \| NMGI [Member]
Debt Instrument [Line Items]
Due	2024
Long-term debt, total	150	0
4.87 % Notes [Member] \| NMGC [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	200	0
3.54 % Notes [Member] \| NMGC [Member]
Debt Instrument [Line Items]
Due	2026
Long-term debt, total	$70	$0

LongTerm_Debt_Schedule_of_Long1

Long-Term Debt - Schedule of Long Term Debt Outstanding (Parenthetical) (Detail) (USD $)	Dec. 31, 2014	Sep. 30, 2013	Mar. 31, 2011	15-May-14	Mar. 31, 2008	Mar. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2013	Mar. 31, 2011	15-May-14	Mar. 31, 2008	Mar. 31, 2012
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%
Repurchased bonds, par amount		$51.60
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] \| 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
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%
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_Inf

Preferred Stock - Additional Information (Detail) (USD $)	Dec. 31, 2014
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, par value	$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	$100
Preferred stock, no par value
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
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

Common_Stock_Additional_Inform

Common Stock - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 31, 2014
Class Of Stock [Line Items]
Non-vested awards compensation costs, period for recognition	2 years
Actual restricted shares granted	800,000	700,000	1,000,000
Granted, weighted average grant date fair value	$14.69	$17.21	$15.96
Total fair market value of awards vesting	$3.60	$3.50	$14.30
Unrecognized compensation cost related to all non-vested awards	12.7
Aggregate intrinsic value of stock options exercised	2.7	2.4	0.3
Cash received from all option exercises	10.8	6.7	1.1
Income tax benefit realized from stock option exercises	1	0.8	0.1
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
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

Common_Stock_Schedule_of_Assum

Common Stock - Schedule of Assumptions Used to Determine Fair Value (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Risk-free interest rate	0.68%	0.41%	0.38%
Expected lives (in years)	3 years	3 years	3 years
Expected stock volatility	17.36%	19.04%	20.99%
Dividend yield	5.13%	4.83%	4.78%

Common_Stock_Schedule_of_Addit

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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation costs	$12.70	$13.50	$12
Income tax benefits	4.9	5.2	4.6
Excess tax benefits	$0.40	$0	$2.60

Common_Stock_Summary_of_NonVes

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	800,000	700,000	1,000,000
Granted, weighted average grant date fair value	$14.69	$17.21	$15.96
Time-Based Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2013, Number of Shares	638,000
Granted, Number of Shares	265,000
Vested, Number of Shares	-200,000
Forfeited, Number of Shares	-35,000
Nonvested balance at Dec. 31, 2014, Number of Shares	668,000
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value	$18.33
Granted, weighted average grant date fair value	$16.93
Vested, Weighted Average Grant Date Fair Value	$19.16
Forfeited, Weighted Average Grant Date Fair Value	$17.51
Nonvested balance at Dec. 31, 2014, Weighted Average Grant Date Fair Value	$17.56
Performance-Based Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2013, Number of Shares	1,505,000
Granted, Number of Shares	537,000
Vested, Number of Shares	-444,000
Forfeited, Number of Shares	-83,000
Nonvested balance at Dec. 31, 2014, Number of Shares	1,515,000
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value	$17.04
Granted, weighted average grant date fair value	$13.59
Vested, Weighted Average Grant Date Fair Value	$18.53
Forfeited, Weighted Average Grant Date Fair Value	$15.51
Nonvested balance at Dec. 31, 2014, Weighted Average Grant Date Fair Value	$15.44

Common_Stock_Summary_of_NonVes1

Common Stock - Summary of Non-Vested Shares of Restricted Stock (Parenthetical) (Detail) (Restricted Stock [Member])	12 Months Ended
	Dec. 31, 2014
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) (USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2014
Schedule Of Stock Options [Line Items]
Outstanding balance at Dec. 31, 2014, Number of Shares	840
Outstanding balance at Dec. 31, 2014, Weighted Avg. Option Price (per share)	$16.32
Outstanding balance at Dec. 31, 2014, Weighted Avg. Remaining Contractual Term	1 year
Stock Options [Member]
Schedule Of Stock Options [Line Items]
Outstanding balance at Dec. 31, 2013, Number of Shares	1,567
Granted, Number of Shares	0
Exercised, Number of Shares	-727
Cancelled, Number of Shares	0
Outstanding balance at Dec. 31, 2014, Number of Shares	840
Exercisable at Dec. 31, 2014, Number of Shares	840
Available for future grant at Dec. 31, 2014, Number of Shares	2,482
Outstanding balance at Dec. 31, 2013, Weighted Avg. Option Price (per share)	$15.62
Granted, Weighted Avg. Option Price	$0
Exercised, Weighted Avg. Option Price	$14.80
Cancelled, Weighted Avg. Option Price	$0
Outstanding balance at Dec. 31, 2014, Weighted Avg. Option Price (per share)	$16.32
Exercisable at Dec. 31, 2014, Weighted Avg. Option Price	$16.32
Outstanding balance at Dec. 31, 2014, Weighted Avg. Remaining Contractual Term	1 year
Exercisable at Dec. 31, 2014, Weighted Avg. Remaining Contractual Term	1 year
Outstanding balance at Dec. 31, 2014, Aggregate Intrinsic Value	$3.50
Exercisable at Dec. 31, 2014, Aggregate Intrinsic Value	$3.50

Common_Stock_Summary_of_Stock_1

Common Stock - Summary of Stock Option Transactions (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Range of Option Prices, Minimum	$16.21
Range of Option Prices, Maximum	$19.01

Common_Stock_Schedule_of_Optio

Common Stock - Schedule of Option Outstanding and Exercisable (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Range of Option Prices, Minimum	$16.21
Range of Option Prices, Maximum	$19.01
Option Shares	840
Weighted-Avg. Option Price	$16.32
Weighted-Avg. Remaining Contractual Life, Years	1 year
$16.21 - $19.01 [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Range of Option Prices, Minimum	$16.21
Range of Option Prices, Maximum	$19.01
Option Shares	840
Weighted-Avg. Option Price	$16.32
Weighted-Avg. Remaining Contractual Life, Years	1 year

Other_Comprehensive_Income_Acc

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	($0.50)		$1		($7.40)
Reclassification from AOCI to net income, Gross	1.6	[1]	1.3	[1]	0.6	[1]
Gain (Loss) on cash flow hedges, Gross	1.1		2.3		-6.8
Amortization of unrecognized benefit costs and other, Gross	-4.8	[2]	23.6	[2]	-4.8	[2],[3]
Increase in unrecognized postemployment costs, Gross	-12.9	[4]
Change in benefit obligation due to remeasurement, Gross	12.6	[5]
Recognized benefit costs due to settlement, Gross			2.6
Total other comprehensive income (loss), Gross	-4		28.5		-11.6
Unrealized gain (loss) on cash flow hedges, Tax	0.2		-0.4		2.8
Reclassification from AOCI to net income, Tax	-0.6	[1]	-0.5	[1]	-0.2	[1]
Gain (Loss) on cash flow hedges, Tax	-0.4		-0.9		2.6
Amortization of unrecognized benefit costs and other, Tax	1.8	[2]	-8.8	[2]	0	[2],[3]
Increase in unrecognized postemployment costs, Tax	4.7	[4]
Change in benefit obligation due to remeasurement, Tax	-4.6	[5]
Recognized benefit costs due to settlement, Tax			-1
Total other comprehensive income (loss), Tax	1.5		-10.7		2.6
Unrealized gain (loss) on cash flow hedges, Net	-0.3		0.6		-4.6
Reclassification from AOCI to net income, Net	1	[1]	0.8	[1]	0.4	[1]
Gain (Loss) on cash flow hedges, Net	0.7		1.4		-4.2
Amortization of unrecognized benefit costs and other	-3	[2]	14.8	[2]	-4.8	[2],[3]
Increase in unrecognized postemployment costs, Net	-8.2	[4]
Change in benefit obligation due to remeasurement, Net	8	[5]
Recognized benefit costs due to settlement, Net	0		1.6		0
Other comprehensive income (loss), net of tax	-2.5		17.8		-9
Unrecognized pension losses and prior service credits	-22.5	[6]	-20.5	[6]
Unrecognized other benefit gains, prior service costs and transition obligations	13.9	[7]	15.1	[7]
Net unrealized losses from cash flow hedges	-7.1	[8]	-7.8	[8]
Total accumulated other comprehensive loss	-15.7		-13.2
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	0		0		-8
Reclassification from AOCI to net income, Gross	1.1		1.4		1.4
Gain (Loss) on cash flow hedges, Gross	1.1		1.4		-6.6
Total other comprehensive income (loss), Gross	1.1		1.4		-6.6
Unrealized gain (loss) on cash flow hedges, Tax	0		0		3.1
Reclassification from AOCI to net income, Tax	-0.4		-0.5		-0.6
Gain (Loss) on cash flow hedges, Tax	-0.4		-0.5		2.5
Total other comprehensive income (loss), Tax	-0.4		-0.5		2.5
Unrealized gain (loss) on cash flow hedges, Net	0		0		-4.9
Reclassification from AOCI to net income, Net	0.7		0.9		0.8
Gain (Loss) on cash flow hedges, Net	0.7		0.9		-4.1
Other comprehensive income (loss), net of tax	0.7		0.9		-4.1
Net unrealized losses from cash flow hedges	-7.1	[8]	-7.8	[8]
Total accumulated other comprehensive loss	($7.10)		($7.80)

[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]	Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion
[4]	Amounts reflect an out-of-period adjustment related to TECO Coalbs unfunded black lung liability.
[5]	Includes an adjustment to eliminate TECO Coalbs OPEB liability. See Note 5 for additional information.
[6]	Net of tax benefit of $13.8 million and $12.6 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.
[7]	Net of tax expense of $8.3 million and $9.1 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively. Balance includes a $7.9 million loss at Dec. 31, 2014 related to TECO Coalbs unfunded black lung liability that will be reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5.
[8]	Net of tax benefit of $4.5 million and $4.9 million as of Dec. 31, 2014 and Dec. 31, 2013, respectively.

Other_Comprehensive_Income_Acc1

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
Net income discontinued operations settlement	$7.90
Net unrealized losses from cash flow hedges, tax benefit	4.5	4.9
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	4.5	4.9
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	13.8	12.6
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	$8.30	$9.10

Earnings_Per_Share_Schedule_of

Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic earnings per share
Net income from continuing operations	$27.40	$73	$57.60	$48.40	$35.40	$64.30	$50.70	$38.30	$206.40	$188.70	$197
Amount allocated to nonvested participating shareholders									-0.7	-0.6	-0.7
Income before discontinued operations available to common shareholdersbBasic									205.7	188.1	196.3
Income (loss) from discontinued operations attributable to TECO Energy, net									-76	9	15.7
Amount allocated to nonvested participating shareholders									0	0	0
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholdersbBasic									-76	9	15.7
Net income attributable to TECO Energy	10.8	11.1	58.4	50.1	42	62.8	51.4	41.5	130.4	197.7	212.7
Amount allocated to nonvested participating shareholders									-0.7	-0.6	-0.7
Net income attributable to TECO Energy available to common shareholdersbBasic									129.7	197.1	212
Average common shares outstanding - Basic									223.1	215	214.3
Earnings per share from continuing operations available to common shareholdersbBasic	$0.11	$0.32	$0.27	$0.22	$0.17	$0.30	$0.24	$0.17	$0.92	$0.88	$0.92
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholdersbBasic									($0.34)	$0.04	$0.07
Earnings per share attributable to TECO Energy - Basic	$0.04	$0.04	$0.27	$0.23	$0.20	$0.29	$0.24	$0.19	$0.58	$0.92	$0.99
Diluted earnings per share
Net income from continuing operations	27.4	73	57.6	48.4	35.4	64.3	50.7	38.3	206.4	188.7	197
Amount allocated to nonvested participating shareholders									-0.7	-0.6	-0.7
Income before discontinued operations available to common shareholdersbDiluted									205.7	188.1	196.3
Income (loss) from discontinued operations attributable to TECO Energy, net									-76	9	15.7
Amount allocated to nonvested participating shareholders									0	0	0
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholdersbDiluted									-76	9	15.7
Net income attributable to TECO Energy	10.8	11.1	58.4	50.1	42	62.8	51.4	41.5	130.4	197.7	212.7
Amount allocated to nonvested participating shareholders									-0.7	-0.6	-0.7
Net income attributable to TECO Energy available to common shareholdersbDiluted									$129.70	$197.10	$212
Average common shares outstanding - Basic									223.1	215	214.3
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net									0.6	0.5	0.7
Average common shares outstandingbDiluted									223.7	215.5	215
Earnings per share from continuing operations available to common shareholdersbDiluted	$0.11	$0.32	$0.27	$0.22	$0.17	$0.30	$0.24	$0.17	$0.92	$0.88	$0.92
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholdersbDiluted									($0.34)	$0.04	$0.07
Earnings per share attributable to TECO Energy - Diluted	$0.04	$0.04	$0.27	$0.23	$0.20	$0.29	$0.24	$0.19	$0.58	$0.92	$0.99
Anti-dilutive shares									0	0	0.4

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Feb. 08, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 19, 2013	Mar. 31, 2011
	InsuranceCarrier					Customer
	Lawsuit
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers						32,000
Period of appeal expires		30 days
Number of lawsuits for insurance carriers	2
Number of insurance carriers	18
Expected period for annulment proceedings		2 years
Total rental expense and leases		$13.70	$7.60	$8.10
Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Total rental expense and leases		4.1	2.3	2.2
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement interest					U.S. prime rate plus 2%
Litigation settlement amount					7.5
Damages awarded					21.1
Gas Shortages [Member]
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers	28,700
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites		33.3
PGS [Member] \| Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites		$33.30

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Long Term Commitments [Line Items]
Future Minimum Capacity Payments Under PPAs Due, 2015	$30
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, Thereafter	0
Total future minimum capacity payments under PPAs due	64.6
Future Minimum Operating Leases Payments Due, 2015	8.9
Future Minimum Operating Leases Payments Due, 2016	8
Future Minimum Operating Leases Payments Due, 2017	7
Future Minimum Operating Leases Payments Due, 2018	6.2
Future Minimum Operating Leases Payments Due, 2019	5.7
Future Minimum Operating Leases Payments Due, Thereafter	18.4
Total future minimum operating leases payments due	54.2
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2015	204.5
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2016	86.8
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2017	19.8
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2018	5.2
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2019	5.3
Future Minimum Net Purchase Obligations/Commitments Payments Due, Thereafter	0
Total future minimum net purchase obligations/commitments payments due	321.6
Future Minimum Payments Due, 2015	243.4
Future Minimum Payments Due, 2016	109.4
Future Minimum Payments Due, 2017	36.7
Future Minimum Payments Due, 2018	21.5
Future Minimum Payments Due, 2019	11
Future Minimum Payments Due, Thereafter	18.4
Total future minimum payments	440.4
Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Future Minimum Capacity Payments Under PPAs Due, 2015	30
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, Thereafter	0
Total future minimum capacity payments under PPAs due	64.6
Future Minimum Operating Leases Payments Due, 2015	6.7
Future Minimum Operating Leases Payments Due, 2016	6.1
Future Minimum Operating Leases Payments Due, 2017	5.2
Future Minimum Operating Leases Payments Due, 2018	4.5
Future Minimum Operating Leases Payments Due, 2019	4.4
Future Minimum Operating Leases Payments Due, Thereafter	13
Total future minimum operating leases payments due	39.9
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2015	203.2
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2016	86.8
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2017	19.8
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2018	5.2
Future Minimum Net Purchase Obligations/Commitments Payments Due, 2019	5.3
Future Minimum Net Purchase Obligations/Commitments Payments Due, Thereafter	0
Total future minimum net purchase obligations/commitments payments due	320.3
Future Minimum Payments Due, 2015	239.9
Future Minimum Payments Due, 2016	107.5
Future Minimum Payments Due, 2017	34.9
Future Minimum Payments Due, 2018	19.8
Future Minimum Payments Due, 2019	9.7
Future Minimum Payments Due, Thereafter	13
Total future minimum payments	$424.80

Commitments_and_Contingencies_3

Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Tampa Electric Company [Member] \| Letters Of Credit [Member]
Guarantor Obligations [Line Items]
Year of expiration 2015	$0
Year of expiration 2016-2019	0
Year of expiration After 2019	0.6
Maximum Theoretical Obligation	0.6
Liabilities Recognized at Dec 31, 2014	0.1
NMGC [Member] \| Letters Of Credit [Member]
Guarantor Obligations [Line Items]
Year of expiration 2015	0
Year of expiration 2016-2019	0
Year of expiration After 2019	1.7
Maximum Theoretical Obligation	1.7
Liabilities Recognized at Dec 31, 2014	0
Fuel Sales and Transportation [Member]
Guarantor Obligations [Line Items]
Year of expiration 2015	0
Year of expiration 2016-2019	0
Year of expiration After 2019	92.9
Maximum Theoretical Obligation	92.9
Liabilities Recognized at Dec 31, 2014	$0

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Legal fees	$1.70	$1.30
Tampa Electric Company [Member]
Related Party Transaction [Line Items]
Legal fees	$1.70	$1.20

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Related Parties (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Natural gas sales, net	$0.30	$18.30	$11.70
Administrative and general, net	22.5	27.2	23.4
Tampa Electric Company [Member]
Related Party Transaction [Line Items]
Accounts receivable	2.4	1.3
Accounts payable	9.7	9.8
Taxes receivable	43.3	54.9
Taxes payable	$0	$0.40

Segment_Information_Additional

Segment Information - Additional Information (Detail)	Dec. 31, 2014
Segment Information - Additional Information (Detail)	Customer
Tampa Electric [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	706,000
Tampa Electric [Member] \| Minimum [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	706,000
PGS [Member] \| Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	354,000
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	354,000
NMGC [Member] \| Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	513,000

Segment_Information_Schedule_o

Segment Information - Schedule of Segment Information (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Total revenues	$695.50	$687.20	$605.70	$578	$562.20	$642.10	$607.50	$543.30	$2,566.40	$2,355.10	$2,387.70
Depreciation and amortization									315.3	291.8	289.6
Total interest charges									171.1	161.4	176.4
Internally allocated interest									0	0	0
Provision for income taxes									138.9	112.6	120.8
Net income from continuing operations	27.4	73	57.6	48.4	35.4	64.3	50.7	38.3	206.4	188.7	197
Discontinued operations attributable to TECO, net of tax									-76	9	15.7
Add: Net income	10.8	11.1	58.4	50.1	42	62.8	51.4	41.5	130.4	197.7	212.7
Current assets held for sale	109.6				0				109.6	0
Non-current assets held for sale	59.8				0				59.8	0
Goodwill	408.3				0				408.3	0	0	55.4
Total assets	8,726.20				7,448				8,726.20	7,448	7,334.90
Capital expenditures									714.3	532.4	505.1
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,419	2,342.80	2,378
Depreciation and amortization									302.6	290.3	288.2
Total interest charges									106.6	105.3	125.8
Provision for income taxes									155.9	138.8	141.7
Add: Net income									260.3	225.6	227.2
Total assets	7,274.30				6,875.80				7,274.30	6,875.80	6,744.60
Capital expenditures									681.5	507.6	459
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									-42.8	-2.2	-3
Depreciation and amortization									0	0	0
Total interest charges									-5.8	-7.8	-13.5
Internally allocated interest									-1.4	-7.8	-13.5
Provision for income taxes									0	0	0
Net income from continuing operations									-82.2	-214.2	-271.5
Discontinued operations attributable to TECO, net of tax									0	0	0
Add: Net income									-82.2	-214.2	-271.5
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	0								0
Total assets	-6,051.30				-4,733.60				-6,051.30	-4,733.60	-5,108.80
Capital expenditures									0		0
Eliminations \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									-1.6	-1.2	-2.2
Depreciation and amortization									0	0	0
Total interest charges									0	0	0
Provision for income taxes									0	0	0
Add: Net income									0	0	0
Total assets	-7.1				-8.9				-7.1	-8.9	13.3
Capital expenditures									0	0	0
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues									2,566.40	2,355.10	2,387.70
Revenues - External [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,419	2,342.80	2,378
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									-42.8	-2.2	-3
Sales to Affiliates [Member] \| Eliminations \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									-1.6	-1.2	-2.2
Tampa Electric [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									2,021	1,950.50	1,981.30
Depreciation and amortization									248.6	238.8	237.6
Total interest charges									92.8	91.8	109.8
Internally allocated interest									0	0	0
Provision for income taxes									133.2	116.9	120.2
Net income from continuing operations									224.5	190.9	193.1
Discontinued operations attributable to TECO, net of tax									0	0	0
Add: Net income									224.5	190.9	193.1
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	0								0
Total assets	6,565.40				6,126.90				6,565.40	6,126.90	6,042.30
Capital expenditures									592.6	428.6	361.7
Tampa Electric [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,021	1,950.50	1,981.30
Depreciation and amortization									248.6	238.8	237.6
Total interest charges									92.8	91.8	109.8
Provision for income taxes									133.2	116.9	120.2
Add: Net income									224.5	190.9	193.1
Total assets	6,234.40				5,895.40				6,234.40	5,895.40	5,760.40
Capital expenditures									592.6	428.6	361.7
Tampa Electric [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									2,019.90	1,949.60	1,980.70
Tampa Electric [Member] \| Revenues - External [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,020.50	1,950.10	1,980.90
Tampa Electric [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									1.1	0.9	0.6
Tampa Electric [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0.5	0.4	0.4
PGS [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									399.6	393.5	398.9
Depreciation and amortization									54	51.5	50.6
Total interest charges									13.8	13.5	16
Internally allocated interest									0	0	0
Provision for income taxes									22.7	21.9	21.5
Net income from continuing operations									35.8	34.7	34.1
Discontinued operations attributable to TECO, net of tax									0	0	0
Add: Net income									35.8	34.7	34.1
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	0								0
Total assets	1,082.80				1,021.20				1,082.80	1,021.20	1,009.90
Capital expenditures									88.9	79	97.3
PGS [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									399.6	393.5	398.9
Depreciation and amortization									54	51.5	50.6
Total interest charges									13.8	13.5	16
Provision for income taxes									22.7	21.9	21.5
Add: Net income									35.8	34.7	34.1
Total assets	1,047				989.3				1,047	989.3	970.9
Capital expenditures									88.9	79	97.3
PGS [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									398.5	392.7	396.6
PGS [Member] \| Revenues - External [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									398.5	392.7	397.1
PGS [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									1.1	0.8	2.3
PGS [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member] \| Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									1.1	0.8	1.8
NMGC [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									137.5	0	0
Depreciation and amortization									11	0	0
Total interest charges									4.2	0	0
Internally allocated interest									0	0	0
Provision for income taxes									7.1	0	0
Net income from continuing operations									10.5	0	0
Discontinued operations attributable to TECO, net of tax									0	0	0
Add: Net income									10.5	0	0
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	408.3								408.3
Total assets	1,237.20				0				1,237.20	0	0
Capital expenditures									18.2	0	0
NMGC [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									137.5	0	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 attributable to TECO, net of tax									-82	9	50.2
Add: Net income									-82	9	50.2
Current assets held for sale	109.6								109.6
Non-current assets held for sale	59.8								59.8
Goodwill	0								0
Total assets	227.7				316.3				227.7	316.3	356.6
Capital expenditures									14.6	22.4	36.3
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
TECO Guatemala [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 attributable to TECO, net of tax									0	0	-29.3
Add: Net income									0	0	-29.3
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	0								0
Total assets	0				0				0	0	164.9
Capital expenditures									0	0	8.6
TECO Guatemala [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
TECO Guatemala [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									51.1	13.3	10.5
Depreciation and amortization									1.7	1.5	1.4
Total interest charges									66.1	63.9	64.1
Internally allocated interest									1.4	7.8	13.5
Provision for income taxes									-24.1	-26.2	-20.9
Net income from continuing operations									17.8	177.3	241.3
Discontinued operations attributable to TECO, net of tax									6	0	-5.2
Add: Net income									23.8	177.3	236.1
Current assets held for sale	0								0
Non-current assets held for sale	0								0
Goodwill	0								0
Total assets	5,664.40				4,717.20				5,664.40	4,717.20	4,870
Capital expenditures									0	2.4	1.2
Other [Member] \| Revenues - External [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									10.5	12.8	10.4
Other [Member] \| Sales to Affiliates [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									$40.60	$0.50	$0.10

Segment_Information_Schedule_o1

Segment Information - Schedule of Segment Information (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$10.90	$12.10	$13.40

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	$6.10	$28.60	$28.60
TECO Energy [Member]
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	22.5	23.8
Tampa Electric Company [Member]
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	5.3	4.8	5
Cost of removal or dismantling of assets charged to regulatory liability	$6.10	$4.80

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Line Items]
Beginning balance	$28.60	$28.60
Additional liabilities	0.1	0.1
Liabilities settled	0	-1.4
Accretion expense	0	1.4
Revisions to estimated cash flows	0.2	-0.3
Acquisition of NMGC	0.8	0
Reclassification to liabilities associated with assets held for sale	-22.5	0
Other	-1.1	0.2
Ending balance	6.1	28.6
Tampa Electric Company [Member]
Asset Retirement Obligation [Line Items]
Beginning balance	4.8	5
Additional liabilities	0.1	0.1
Liabilities settled	0	-0.2
Revisions to estimated cash flows	0.2	-0.3
Other	0.2	0.2
Ending balance	$5.30	$4.80

Asset_Retirement_Obligations_S1

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Line Items]
Other asset retirement obligations	($1.10)	$0.20
Other [Member]
Asset Retirement Obligation [Line Items]
Other asset retirement obligations	0.2
TECO Coal [Member] \| Discontinued Operations [Member]
Asset Retirement Obligation [Line Items]
Other asset retirement obligations	($1.30)

Accounting_for_Derivative_Inst2

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative assets	$0	$10,000,000
Derivative liabilities	42,700,000	300,000
Collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities	-36,600,000
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	0	9,800,000
Derivative liabilities	42,700,000	200,000
Collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities	($36,600,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	31-Dec-16
Natural Gas Contracts [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	31-Dec-16

Accounting_for_Derivative_Inst3

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) (Natural Gas Contracts [Member])	Dec. 31, 2014
	MMBTU
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	41,000,000
Financial [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	41,000,000
2015 [Member] \| Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2015 [Member] \| Physical [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2015 [Member] \| Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,400,000
2015 [Member] \| Financial [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,400,000
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	8,600,000
2016 [Member] \| Financial [Member] \| Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,600,000

Fair_Value_Measurements_Schedu

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	$42.70	$0.30
Total Swap Assets	0	10
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	42.7	0.2
Total Swap Assets	0	9.8
Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.3
Total Swap Assets		10
Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.2
Total Swap Assets		9.8
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	42.7	0.2
Total Swap Assets		9.8
Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	42.7	0.2
Total Swap Assets		9.8
Diesel Fuel Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.1
Total Swap Assets		0.2
Level 1 [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0
Total Swap Assets		0
Level 1 [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0
Total Swap Assets		0
Level 1 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets		0
Level 1 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets		0
Level 1 [Member] \| Diesel Fuel Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0
Total Swap Assets		0
Level 2 [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.3
Total Swap Assets		10
Level 2 [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.2
Total Swap Assets		9.8
Level 2 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	42.7	0.2
Total Swap Assets		9.8
Level 2 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	42.7	0.2
Total Swap Assets		9.8
Level 2 [Member] \| Diesel Fuel Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0.1
Total Swap Assets		0.2
Level 3 [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets	0	0
Level 3 [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets	0	0
Level 3 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets		0
Level 3 [Member] \| Natural Gas Derivatives [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities	0	0
Total Swap Assets		0
Level 3 [Member] \| Diesel Fuel Derivatives [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total Swap Liabilities		0
Total Swap Assets		$0

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	$0	$10
Total Swap Liabilities	42.7	0.3
Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	9.8
Total Swap Liabilities	42.7	0.2
Fair Value, Measurements, Recurring
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets		10
Total Swap Liabilities		0.3
Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets		9.8
Total Swap Liabilities		0.2
Level 3 [Member] \| Fair Value, Measurements, Recurring
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] \| Fair Value, Measurements, Recurring \| Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	$0	$0

Variable_Interest_Entities_Add

Variable Interest Entities - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$71.40	$64.70	$105.30
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	71.4	64.7	105.3
Power Purchase Agreements [Member] \| Variable Interest Entities [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	25.7	22.1	75.8
Power Purchase Agreements [Member] \| Variable Interest Entities [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$25.70	$22.10	$75.80
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range	117
Minimum [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range	117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range	370
Maximum [Member] \| Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range	370

Discontinued_Operations_Additi

Discontinued Operations - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Sep. 27, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Feb. 05, 2015	Oct. 17, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group	$227.50
Percentage of ownership in TCAE by TPS GO	96.06%
Purchase in lieu of redemption		83.3	51.6	650.4
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Purchase in lieu of redemption			25.3
Net proceeds from sale after transaction costs			197
Gain loss on sale of business net of tax			28.6
Foreign tax credits				22.9
Subsequent Event [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Contingent Payments						60
Purchase price						80
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group							120
Contingent Payments							50
Impairment of held for sale asset		98.4			17.5
Total pretax impairment charges		115.9
TECO Coal [Member] \| Subsequent Event [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Contingent Payments						60
Purchase price						80
TGS [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group	1.5
TPS SJI [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group	213.5
TPS GO [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group	$12.50

Discontinued_Operations_Carryi

Discontinued Operations - Carrying Amount of Assets and Liabilities Held for Sale (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets held for sale	$109.60	$0
Non-current assets held for sale	59.8	0
Current liabilities	39.4	0
Long-term liabilities	65.4	0
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets held for sale	109.6
Non-current assets held for sale	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	$104.80

Discontinued_Operations_Compon

Discontinued Operations - Components of Discontinued Operations (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations	($125.40)	$5.20	$55.40
Provision (benefit) for income taxes	-49.4	-3.8	39.4
Income (loss) from discontinued operations, net	-76	9	16
Less: Income from discontinued operations attributable to noncontrolling interest	0	0	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	-76	9	15.7
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	443.6	496.2	608.9
Income (loss) from operations	-13.9	5.4	66
Loss on impairment	-115.9	0	0
Income (loss) from discontinued operations	-129.8	5.4	66
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	0	0	114.2
Income (loss) from operations	4.4	-0.2	27.7
Loss on assets sold, including transaction costs	0	0	-38.3
Income (loss) from discontinued operations	4.4	-0.2	-10.6
TECO Coal and TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations	-125.4	5.2	55.4
Provision (benefit) for income taxes	-49.4	-3.8	39.4
Income (loss) from discontinued operations, net	-76	9	16
Less: Income from discontinued operations attributable to noncontrolling interest	0	0	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	($76)	$9	$15.70

Goodwill_and_Asset_Impairments2

Goodwill and Asset Impairments - Changes in Carrying Amount of Goodwill (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012
Goodwill [Line Items]
Beginning Balance	$0	$55.40
Impairment losses, pretax		-15.2
Goodwill written off upon sale, pretax		-40.2
Acquisition of NMGC	408.3
Ending Balance	408.3	0
TPS GO [Member]
Goodwill [Line Items]
Beginning Balance	0	3.1
Impairment losses, pretax		-3.1
Goodwill written off upon sale, pretax		0
Acquisition of NMGC	0
Ending Balance	0	0
TPS SJI [Member]
Goodwill [Line Items]
Beginning Balance	0	52.3
Impairment losses, pretax		-12.1
Goodwill written off upon sale, pretax		-40.2
Acquisition of NMGC	0
Ending Balance	0	0
NMGC [Member]
Goodwill [Line Items]
Beginning Balance	0	0
Impairment losses, pretax		0
Goodwill written off upon sale, pretax		0
Acquisition of NMGC	408.3
Ending Balance	408.3	0
TECO Guatemala [Member]
Goodwill [Line Items]
Beginning Balance	0	55.4
Impairment losses, pretax		-15.2
Goodwill written off upon sale, pretax		-40.2
Acquisition of NMGC	0
Ending Balance	$0	$0

Goodwill_and_Asset_Impairments3

Goodwill and Asset Impairments - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 29, 2014	Dec. 31, 2014	Sep. 27, 2012	Dec. 31, 2011	Feb. 05, 2015
Goodwill And Long Lived Asset Impairment [Line Items]
Goodwill	$408,300,000	$0	$0		$408,300,000		$55,400,000
Asset impairment	115,900,000	0	17,200,000
Discontinued Operation Purchase Price						227,500,000
TGS [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Long-lived asset pretax impairment charge			2,000,000
TECO Coal [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Asset impairment		0	0
Long-lived asset pretax impairment charge	115,900,000			98,400,000	17,500,000
Effects of inflation rate		1.00%	1.00%
Discontinued Operation Purchase Price				120,000,000
TECO Coal [Member] \| Subsequent Event [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Discontinued Operation Purchase Price								80,000,000
NMGC [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Goodwill	408,300,000	0	0		408,300,000		0
Asset impairment	$0

Acquisition_of_New_Mexico_Gas_2

Acquisition of New Mexico Gas Company - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 02, 2014	Dec. 31, 2014	Dec. 31, 2013
	Pipelines	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Aggregate purchase price	$950
Customer percentage of state population	60.00%
Mileage of transmission pipeline served	1,600
Mileage of distribution lines served	10,000
Goodwill, period increase (decrease)		6.5
After-tax non-recurring acquisition consummation, integration and other costs		8.6	6.2
Deferred taxes will be recorded	0
TECO Energy [Member]
Business Acquisition [Line Items]
Obligations associated with severance benefits costs		2.6
NMGI [Member]
Business Acquisition [Line Items]
Business acquisition, effective date	2-Sep-14
Aggregate purchase price	950
NMGC [Member]
Business Acquisition [Line Items]
Senior secured notes	200
Number of employees	720
Minimum number of customers served	513,000
Customer rate of credit	2
Increase in rate of credit	4
Goodwill expected tax deductible amount		146.1
NM [Member]
Business Acquisition [Line Items]
Number of counties in which entity operates	23
Number of countries	33
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Revenue		137.5
Net income		($8.20)

Acquisition_of_New_Mexico_Gas_3

Acquisition of New Mexico Gas Company - Consideration in Acquisition (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Sep. 02, 2014
Business Combinations [Abstract]
Cash paid to seller	$530.10
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

Acquisition_of_New_Mexico_Gas_4

Acquisition of New Mexico Gas Company - Purchase Price Allocation (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 02, 2014
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 02, 2014
Business Acquisition [Line Items]
Goodwill	$408.30	$0	$0	$55.40
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Current assets					48.7
Property, plant and equipment					616.5
OPEB regulatory asset					6.4
Debt-related regulatory asset					23.9
Goodwill					408.3
Deferred tax assets					52.8
Other assets					29.3
Total assets					1,185.90
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

Acquisition_of_New_Mexico_Gas_5

Acquisition of New Mexico Gas Company - Preliminary Purchase Price Allocation (Parenthetical) (Detail) (NMGI and NMGC [Member], USD $)	Sep. 02, 2014
In Millions, unless otherwise specified	Sep. 02, 2014
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Accounts receivables	$18.90
Gross contract value	19.6
Contractual receivables not expected to be collected	$0.70

Acquisition_of_New_Mexico_Gas_6

Acquisition of New Mexico Gas Company - Pro Forma Earning (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Revenues	$2,806.60	$2,704
Net income from continuing operations	$223.80	$216.80
Basic and diluted EPS from continuing operations	$0.96	$0.93

Acquisition_of_New_Mexico_Gas_7

Acquisition of New Mexico Gas Company - After tax Transaction and Integration Charges Recognized Upon Closing of Acquisition and Included Consolidated Statements of Operations (Detail) (TECO Energy [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
TECO Energy [Member]
Business Acquisition [Line Items]
Legal and other consultants	$8
Bridge loan costs	3.3
Severance and relocation costs	2.8
Other costs and tax benefit	-5.5
Total accounting charges	$8.60

Quarterly_Data_Schedule_of_Fin

Quarterly Data - Schedule of Financial Data by Quarter (Detail) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$695.50	$687.20	$605.70	$578	$562.20	$642.10	$607.50	$543.30	$2,566.40	$2,355.10	$2,387.70
Income from operations	112.1	145.7	132	115.6	95	141.7	118.1	99.8	505.4	454.6	486.3
Net income from continuing operations	27.4	73	57.6	48.4	35.4	64.3	50.7	38.3	206.4	188.7	197
Net income attributable to TECO Energy	$10.80	$11.10	$58.40	$50.10	$42	$62.80	$51.40	$41.50	$130.40	$197.70	$212.70
EPSbBasic
Earnings per share from continuing operations - Basic	$0.11	$0.32	$0.27	$0.22	$0.17	$0.30	$0.24	$0.17	$0.92	$0.88	$0.92
Net income	$0.04	$0.04	$0.27	$0.23	$0.20	$0.29	$0.24	$0.19	$0.58	$0.92	$0.99
EPSbDiluted
Earnings per share from continuing operations - Diluted	$0.11	$0.32	$0.27	$0.22	$0.17	$0.30	$0.24	$0.17	$0.92	$0.88	$0.92
Net income	$0.04	$0.04	$0.27	$0.23	$0.20	$0.29	$0.24	$0.19	$0.58	$0.92	$0.99
Dividends paid per common share outstanding	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.22	$0.88	$0.88	$0.88

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Feb. 03, 2015	Dec. 31, 2014	Sep. 02, 2014	Dec. 31, 2013	Dec. 17, 2013	Feb. 05, 2015
Subsequent Event [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity		$900	$40	$675
Tampa Electric Company [Member]
Subsequent Event [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity		475		475	200
Subsequent Event [Member]
Subsequent Event [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	150
Debt instrument maturity date	4/14/15
Purchase price						80
Contingent Payments						60
Subsequent Event [Member] \| Tampa Electric Company [Member]
Subsequent Event [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	$150
Debt instrument maturity date	4/14/15

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Uncollectible Accounts
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$4.70		$4.20		$2.60
Charged to Income	1.4		3.3		4.8
Other Charges	0.7		0		0
Payments & Deductions	4.7	[1]	2.8	[1]	3.2	[1]
Balance at End of Period	2.1		4.7		4.2
Allowance for Uncollectible Accounts \| Tampa Electric Company [Member]
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	2		1.5		1.3
Charged to Income	2.7		3.3		3.4
Other Charges	0		0		0
Payments & Deductions	3.3	[1]	2.8	[1]	3.2	[1]
Balance at End of Period	1.4		2		1.5
Deferred Tax Valuation Allowance
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	0		3		9.7
Charged to Income	4.6		0		1.1
Other Charges	0		0		0
Payments & Deductions	0	[1],[2]	3	[1],[2]	7.8	[1],[2]
Balance at End of Period	$4.60		$0		$3

[1]	Write-off of individual bad debt accounts
[2]	Valuation allowance is no longer required