Tampa Electric 10-Q 5 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 31, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	350,563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,230,760
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	96,271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 55.4	$ 25.4
Receivables, less allowance for uncollectibles	270.7	299.8
Inventories, at average cost
Derivative assets	0.2	0
Regulatory assets	43.1	53.6
Deferred income taxes	68.2	72.8
Prepayments and other current assets	36.9	22.6
Assets held for sale	0	109.6
Total current assets	687.8	755.6
Property, plant and equipment
Construction work in progress	725.6	640
Other property	15.2	14.5
Property, plant and equipment, at original costs	10,076.5	9,733.9
Accumulated depreciation	(2,750.1)	(2,645.7)
Total property, plant and equipment, net	7,326.4	7,088.2
Other assets
Regulatory assets	330.8	348.5
Goodwill	408.4	408.3
Deferred charges and other assets	63.5	65.8
Assets held for sale	0	59.8
Total other assets	802.7	882.4
Total assets	8,816.9	8,726.2
Current liabilities
Long-term debt due within one year	333.3	274.5
Notes payable	128	139
Accounts payable	216.1	288.6
Customer deposits	179.9	176.2
Regulatory liabilities	69.1	57
Derivative liabilities	23.9	36.6
Interest accrued	54.5	39.9
Taxes accrued	60.8	29.9
Other	18.3	16.8
Liabilities associated with assets held for sale	0	39.4
Total current liabilities	1,083.9	1,097.9
Other liabilities
Deferred income taxes	609.1	519.2
Investment tax credits	8.8	9
Regulatory liabilities	716.2	729
Derivative liabilities	2.7	6.1
Deferred credits and other liabilities	316.9	370.9
Liabilities associated with assets held for sale	0	65.4
Long-term debt, less amount due within one year	3,517.7	3,354
Total other liabilities	$ 5,171.4	$ 5,053.6
Commitments and contingencies (see Note 10)
Capital
Common equity	$ 235.2	$ 234.9
Additional paid in capital	1,891.2	1,875.9
Retained earnings	443.8	479.6
Accumulated other comprehensive loss	(8.6)	(15.7)
Total capital	2,561.6	2,574.7
Long-term debt	3,517.7	3,354
Total liabilities and capital	8,816.9	8,726.2
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	33.2	10.4
Receivables, less allowance for uncollectibles	258.6	227.2
Inventories, at average cost
Taxes receivable from affiliate	0	43.3
Regulatory assets	39.7	52.1
Deferred income taxes	22.9	24.8
Prepayments and other current assets	25.3	17.4
Total current assets	581.5	532.6
Property, plant and equipment
Construction work in progress	703.6	624.2
Utility plant in service, at original costs	9,336	9,027.9
Accumulated depreciation	(2,719.6)	(2,633.8)
Utility plant in service, net	6,616.4	6,394.1
Other property	9.3	8.6
Total property, plant and equipment, net	6,625.7	6,402.7
Other assets
Unamortized debt expense	18.5	16.8
Regulatory assets	305.4	319.6
Deferred charges and other assets	325.3	339
Other	1.4	2.6
Total assets	7,532.5	7,274.3
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	0	58
Accounts payable	192.3	242.3
Customer deposits	174.2	170.4
Regulatory liabilities	65.7	54.7
Derivative liabilities	23.9	36.6
Interest accrued	41.5	17
Taxes accrued	62.7	12.4
Other	9.9	10
Total current liabilities	653.5	684.7
Other liabilities
Deferred income taxes	1,266.8	1,209.1
Investment tax credits	8.8	9
Regulatory liabilities	605.7	623.4
Derivative liabilities	2.7	6.1
Deferred credits and other liabilities	244.1	299.1
Long-term debt, less amount due within one year	2,179.9	2,013.8
Total other liabilities	$ 2,128.1	$ 2,146.7
Commitments and contingencies (see Note 10)
Capital
Common equity	$ 2,218.4	$ 2,130.4
Retained earnings	356.4	305.8
Accumulated other comprehensive loss	(3.8)	(7.1)
Total capital	2,571	2,429.1
Long-term debt	2,179.9	2,013.8
Total capitalization	4,750.9	4,442.9
Total liabilities and capital	7,532.5	7,274.3
Fuel [Member]
Inventories, at average cost
Utility inventories	135.9	96.4
Fuel [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	127.7	85.2
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	77.4	75.4
Materials and Supplies [Member] | Tampa Electric Company [Member]
Inventories, at average cost
Utility inventories	74.1	72.2
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,258.9	7,094.8
Electric [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,258.9	7,094.8
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	2,076.8	1,984.6
Gas [Member] | Tampa Electric Company [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,373.5	$ 1,308.9

Consolidated Condensed Balance3

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Allowance for uncollectibles	$ 2.2	$ 2.1
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	235,200,000	234,900,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 1.5	$ 1.4

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Regulated electric and gas	$ 690.8	$ 685.1	$ 2,058.9	$ 1,864.4
Unregulated	3	2.1	8.5	6.5
Total revenues	693.8	687.2	2,067.4	1,870.9
Expenses
Fuel	176.6	204.5	492.5	523.8
Purchased power	23.8	21	60.5	59.1
Cost of natural gas sold	42	34.3	194.1	110.5
Other	149.4	137.9	448.5	385.3
Operations and maintenance other expense	16.1	14.8	18.8	22.6
Depreciation and amortization	87.8	78.6	260.3	230
Taxes, other than income	51.5	50.4	156.6	146.3
Total expenses	547.2	541.5	1,631.3	1,477.6
Income from operations	146.6	145.7	436.1	393.3
Other income
Allowance for other funds used during construction	4.7	2.9	12.2	7.3
Other income, net	1.4	1	4.4	(0.4)
Total other income	6.1	3.9	16.6	6.9
Interest charges
Interest expense	48.4	44.4	146.4	126.8
Allowance for borrowed funds used during construction	(2.3)	(1.5)	(6)	(3.6)
Total interest charges	46.1	42.9	140.4	123.2
Income from continuing operations before provision for income taxes	106.6	106.7	312.3	277
Provision for income taxes	41.7	33.7	122.1	98
Net income from continuing operations	64.9	73	190.2	179
Discontinued operations
Loss from discontinued operations	(17.8)	(98.8)	(105.5)	(97.6)
Benefit from income taxes	(6.1)	(36.9)	(38.3)	(38.2)
Loss on discontinued operations, net	(11.7)	(61.9)	(67.2)	(59.4)
Net income	$ 53.2	$ 11.1	$ 123	$ 119.6
Average common shares outstanding - Basic	233.2	227.8	233	220.3
Average common shares outstanding - Diluted	234.7	228.3	234.4	220.8
Earnings per share from continuing operations - Basic	$ 0.28	$ 0.32	$ 0.81	$ 0.81
Earnings per share from continuing operations - Diluted	0.28	0.32	0.81	0.81
Earnings per share from discontinued operations - Basic	(0.05)	(0.28)	(0.28)	(0.27)
Earnings per share from discontinued operations - Diluted	(0.05)	(0.28)	(0.28)	(0.27)
Earnings per share - Basic	0.23	0.04	0.53	0.54
Earnings per share - Diluted	0.23	0.04	0.53	0.54
Dividends paid per common share outstanding	$ 0.225	$ 0.220	$ 0.675	$ 0.66

Consolidated Condensed Stateme5

Consolidated Condensed Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net income		$ 53.2		$ 11.1		$ 123		$ 119.6
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2		0.1		3.3		0.4
Amortization of unrecognized benefit costs	[1]	0.2		0.2		1.8		1.6
Change in benefit obligation due to valuation		(5.7)		(0.7)		(5.7)		(0.7)
Recognized cost due to settlement		7.7	[2]	0		7.7	[2]	0
Increase in unrecognized postemployment costs		0		0	[3]	0		(8.2)	[3]
Other comprehensive income (loss), net of tax		2.4		(0.4)		7.1		(6.9)
Comprehensive income		$ 55.6		$ 10.7		$ 130.1		$ 112.7
[1]	Related to postretirement and postemployment benefits. See Note 5 for additional information.
[2]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 5 and 15 for additional information.
[3]	Amounts reflect an out-of-period adjustment related to TECO Coal's unfunded black lung liability.

Consolidated Condensed Stateme6

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities
Net income	$ 123	$ 119.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	261.5	255.7
Depreciation and amortization	260.3	230
Deferred income taxes and investment tax credits	84.6	58.4
Allowance for other funds used during construction	(12.2)	(7.3)
Non-cash stock compensation	10.1	10.2
Loss (gain) on sales of business/assets, pretax	10	(0.2)
Deferred recovery clauses	13.1	(5.5)
Asset impairment, pretax	78.6	98.4
Receivables, less allowance for uncollectibles	46.1	(25.9)
Inventories	(45.7)	(9.6)
Prepayments and other current assets	(14.2)	(5.5)
Taxes accrued	31.6	48.6
Interest accrued	14.7	27.8
Accounts payable	(85.7)	(29.4)
Other	(36.1)	(29.1)
Cash flows from operating activities	479.4	506.2
Cash flows from investing activities
Capital expenditures	(523.2)	(491.8)
Allowance for other funds used during construction	12.2	7.3
Purchase of NMGI, net of cash acquired	0	(752.5)
Other investing activities	(0.2)	0.3
Cash flows used in investing activities	(511.2)	(1,236.7)
Cash flows from financing activities
Dividends	(158.8)	(147.5)
Proceeds from the sale of common stock	6.4	296.6
Proceeds from long-term debt issuance	499.7	564.2
Repayment of long-term debt	(274.5)	(83.3)
Net decrease in short-term debt	(11)	(12)
Cash flows from financing activities	61.8	618
Net increase (decrease) in cash and cash equivalents	30	(112.5)
Cash and cash equivalents at beginning of the period	25.4	185.2
Cash and cash equivalents at end of the period	55.4	72.7
Supplemental disclosure of non-cash activities
Debt assumed in NMGI acquisition	0	200
Change in accrued capital expenditures	(8.1)	10.2
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	226.4	214
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	233.8	225.9
Deferred income taxes and investment tax credits	52.6	50.1
Allowance for other funds used during construction	(12.1)	(7.3)
Deferred recovery clauses	13.7	(6)
Receivables, less allowance for uncollectibles	(31.4)	(39.2)
Inventories	(44.4)	18
Prepayments	(7.9)	(6.6)
Taxes accrued	93.6	113.3
Interest accrued	24.5	24.3
Accounts payable	(39.8)	(24.1)
Other	(34.4)	(23.3)
Cash flows from operating activities	474.6	539.1
Cash flows from investing activities
Capital expenditures	(485.9)	(475.8)
Allowance for other funds used during construction	12.1	7.3
Cash flows used in investing activities	(473.8)	(468.5)
Cash flows from financing activities
Dividends	(175.9)	(169.8)
Proceeds from the sale of common stock	88	19.5
Proceeds from long-term debt issuance	251.2	296.3
Repayment of long-term debt	(83.3)	(83.3)
Net decrease in short-term debt	(58)	(84)
Cash flows from financing activities	22	(21.3)
Net increase (decrease) in cash and cash equivalents	22.8	49.3
Cash and cash equivalents at beginning of the period	10.4	9.8
Cash and cash equivalents at end of the period	33.2	59.1
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (10.1)	$ 11

Consolidated Condensed Stateme7

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Total revenues	$ 693.8	$ 687.2	$ 2,067.4	$ 1,870.9
Expenses
Fuel	176.6	204.5	492.5	523.8
Purchased power	23.8	21	60.5	59.1
Cost of natural gas sold	42	34.3	194.1	110.5
Other	149.4	137.9	448.5	385.3
Depreciation and amortization	87.8	78.6	260.3	230
Taxes, other than income	51.5	50.4	156.6	146.3
Total expenses	547.2	541.5	1,631.3	1,477.6
Income from operations	146.6	145.7	436.1	393.3
Other income
Allowance for other funds used during construction	4.7	2.9	12.2	7.3
Other income, net	1.4	1	4.4	(0.4)
Total other income	6.1	3.9	16.6	6.9
Interest charges
Interest on long-term debt	48.4	44.4	146.4	126.8
Allowance for borrowed funds used during construction	(2.3)	(1.5)	(6)	(3.6)
Total interest charges	46.1	42.9	140.4	123.2
Income from continuing operations before provision for income taxes	106.6	106.7	312.3	277
Provision for income taxes	41.7	33.7	122.1	98
Net income	53.2	11.1	123	119.6
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.1	3.3	0.4
Other comprehensive income (loss), net of tax	2.4	(0.4)	7.1	(6.9)
Comprehensive income	55.6	10.7	130.1	112.7
Tampa Electric Company [Member]
Revenues
Electric	560.1	581.6	1,542.9	1,547.3
Gas	88.1	86.9	302	300
Total revenues	648.2	668.5	1,844.9	1,847.3
Expenses
Fuel	176.6	204.5	492.5	523.8
Purchased power	23.8	21	60.5	59.1
Cost of natural gas sold	28.5	28.4	101.9	104.6
Other	128.7	130.9	384.8	378
Depreciation and amortization	79	75.4	233.8	225.9
Taxes, other than income	47.8	49.1	144.9	144.1
Total expenses	484.4	509.3	1,418.4	1,435.5
Income from operations	163.8	159.2	426.5	411.8
Other income
Allowance for other funds used during construction	4.6	2.9	12.1	7.3
Other income, net	1.2	1.2	3.6	3.5
Total other income	5.8	4.1	15.7	10.8
Interest charges
Interest on long-term debt	29	27.7	84.5	79.8
Other Interest	1	1	3.3	3.1
Allowance for borrowed funds used during construction	(2.2)	(1.4)	(5.8)	(3.5)
Total interest charges	27.8	27.3	82	79.4
Income from continuing operations before provision for income taxes	141.8	136	360.2	343.2
Provision for income taxes	53.5	51.5	133.8	129.2
Net income	88.3	84.5	226.4	214
Other comprehensive income, net of tax
Gain on cash flow hedges	0.2	0.3	3.3	0.5
Other comprehensive income (loss), net of tax	0.2	0.3	3.3	0.5
Comprehensive income	$ 88.5	$ 84.8	$ 229.7	$ 214.5

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TECO Energy, Inc.’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for all utility and diversified operations include: Principles of Consolidation and Basis of Presentation Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Sept. 30, 2015. In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges and gains at Parent and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 15 On Sept. 4, 2015, TECO Energy and Emera entered into an agreement and plan of merger (Merger Agreement). Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 16 Revenues As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $66.7 million and $86.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Accounting for Franchise Fees and Gross Receipt Taxes Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.
Tampa Electric Company [Member]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TEC’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include: Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13 Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 14 Revenues As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $60.0 million and $49.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2015
New Accounting Pronouncements	2. New Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant. Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Sept. 30, 2015, $29.0 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet. Disclosure of Investments Using Net Asset Value In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in Note 5 2014 Annual Report on Form 10-K Measurement Period Adjustments in Business Combinations In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The company will assess the potential impact of the guidance on future transactions.
Tampa Electric Company [Member]
New Accounting Pronouncements	2. New Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant. Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Sept. 30, 2015, $18.5 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet. Disclosure of Investments Using Net Asset Value In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in Note 5 2014 Annual Report on Form 10-K Measurement Period Adjustments in Business Combinations In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for TEC beginning in 2016 and will be applied prospectively. TEC will assess the potential impact of the guidance on future transactions.

Regulatory

Regulatory	9 Months Ended
	Sep. 30, 2015
Regulatory	3. Regulatory Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. Regulatory Assets and Liabilities Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2015 Dec. 31, 2014 Regulatory assets: Regulatory tax asset (1) $ 73.1 $ 69.2 Cost-recovery clauses - deferred balances (2) 2.8 1.9 Cost-recovery clauses - offsets to derivative liabilities (2) 28.1 43.2 Environmental remediation (3) 52.6 53.1 Postretirement benefits (4) 177.4 194.0 Deferred bond refinancing costs (5) 6.6 7.2 Debt basis adjustment (6) 18.3 20.9 Competitive rate adjustment (2) 2.4 2.8 Other 12.6 9.8 Total regulatory assets 373.9 402.1 Less: Current portion 43.1 53.6 Long-term regulatory assets $ 330.8 $ 348.5 Regulatory liabilities: Regulatory tax liability $ 6.2 $ 6.9 Cost-recovery clauses 40.2 25.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (7) 682.1 695.2 Other 0.7 1.9 Total regulatory liabilities 785.3 786.0 Less: Current portion 69.1 57.0 Long-term regulatory liabilities $ 716.2 $ 729.0 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets are related to FPSC and NMPRC clauses and riders. They are recovered through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.
Tampa Electric Company [Member]
Regulatory	3. Regulatory Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. Regulatory Assets and Liabilities Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2015 Dec. 31, 2014 Regulatory assets: Regulatory tax asset (1) $ 73.0 $ 69.2 Cost-recovery clauses - deferred balances (2) 0.1 0.9 Cost-recovery clauses - offsets to derivative liabilities (2) 27.4 42.7 Environmental remediation (3) 52.6 53.1 Postretirement benefit costs (4) 172.0 187.8 Deferred bond refinancing costs (5) 6.6 7.2 Competitive rate adjustment (2) 2.4 2.8 Other 11.0 8.0 Total regulatory assets 345.1 371.7 Less: Current portion 39.7 52.1 Long-term regulatory assets $ 305.4 $ 319.6 Regulatory liabilities: Regulatory tax liability $ 4.3 $ 5.1 Cost-recovery clauses 36.6 23.5 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (6) 573.7 591.5 Other 0.7 1.9 Total regulatory liabilities 671.4 678.1 Less: Current portion 65.7 54.7 Long-term regulatory liabilities $ 605.7 $ 623.4 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets are related to FPSC clauses and riders. They are recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Taxes	4. Income Taxes The effective tax rate increased to 39.10% for the nine months ended Sept. 30, 2015 from 35.38% for the same period in 2014 primarily due to higher state taxes and tax expense related to long-term incentive compensation shares that vested below target levels. The nine months ended Sept. 30, 2014 included a favorable state tax adjustment related to the acquisition of NMGC. The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward.
Tampa Electric Company [Member]
Income Taxes	4. Income Taxes TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the nine months ended Sept. 30, 2015 and 2014 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity. The IRS concluded its examination of TECO Energy’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.

Employee Postretirement Benefit

Employee Postretirement Benefits	9 Months Ended
	Sep. 30, 2015
Employee Postretirement Benefits	5. Employee Postretirement Benefits Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP. Pension Expense (millions) Pension Benefits Other Postretirement Benefits Three months ended Sept. 30, 2015 2014 2015 2014 Components of net periodic benefit expense Service cost $ 6.7 $ 4.6 $ 0.6 $ 0.6 Interest cost 6.5 8.0 2.0 2.7 Expected return on assets (9.1 ) (10.5 ) (0.3 ) (0.1 ) Amortization of: Prior service (benefit) cost (0.1 ) (0.1 ) (0.6 ) 0.0 Actuarial loss 3.2 3.3 0.0 0.0 Regulatory asset 0.0 0.0 0.3 0.1 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 7.2 $ 5.3 $ 2.0 $ 3.3 Nine months ended Sept. 30, Components of net periodic benefit expense Service cost $ 17.6 $ 12.9 $ 1.7 $ 1.8 Interest cost 22.6 24.4 6.1 7.9 Expected return on assets (32.4 ) (31.2 ) (0.8 ) (0.1 ) Amortization of: Prior service (benefit) cost (0.2 ) (0.3 ) (1.8 ) (0.1 ) Actuarial loss 11.4 10.0 0.0 0.1 Regulatory asset 0.0 0.0 0.8 0.1 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 19.0 $ 15.8 $ 6.0 $ 9.7 For the fiscal 2015 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.256% for pension benefits under its qualified pension plan. For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.206% for the Florida-based plan and 4.243% for the NMGC plan. TECO Energy made contributions of $55.0 million and $47.5 million to its pension plan for the nine months ended Sept. 30, 2015 and 2014, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2015. In addition, in October 2015, TECO Energy made a contribution of $43.4 million to the SERP’s trust in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus all benefits that would become payable under the SERP to current participants. For the three and nine months ended Sept. 30, 2015, TECO Energy and its subsidiaries reclassified $0.2 million and $2.4 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense, compared with $0.7 million and $2.0 million for the three and nine months ended Sept. 30, 2014, respectively. In addition, during the three and nine months ended Sept. 30, 2015, the regulated companies reclassified $2.6 million and $7.8 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.7 million and $7.9 million during the three and nine months ended Sept. 30, 2014, respectively. Black Lung Liability As discussed in Note 15 In accordance with ASC 715, an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations recorded in AOCI was recognized as a loss from discontinued operations upon completion of the sale of TECO Coal.
Tampa Electric Company [Member]
Employee Postretirement Benefits	5. Employee Postretirement Benefits TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5 Employee Postretirement Benefits Notes to Consolidated Condensed Financial Statements For the fiscal 2015 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.256%. For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.206%. Additionally, TECO Energy made contributions of $55.0 million and $47.5 million to its pension plan in the nine months ended Sept. 30, 2015 and 2014, respectively. TEC’s portion of the contributions was $43.9 million and $38.2 million, respectively. In addition, in October 2015, TECO Energy made a contribution of $43.4 million to the SERP’s trust in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus all benefits that would become payable under the SERP to current participants. TEC’s portion of the SERP contribution was $14.9 million. Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2015, TEC reclassified $2.3 million and $7.0 million, respectively, of prior service benefit and actuarial losses from regulatory assets to net income, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2014, respectively.

Short-Term Debt

Short-Term Debt	9 Months Ended
	Sep. 30, 2015
Short-Term Debt	6. Short-Term Debt At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities Sept. 30, 2015 Dec. 31, 2014 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 12.0 $ 0.6 3-year accounts receivable facility (3) 150.0 0.0 0.0 150.0 46.0 0.0 TECO Energy/TECO Finance: 5-year facility (2)(4) 300.0 118.0 0.0 300.0 50.0 0.0 New Mexico Gas Company: 5-year facility (2) 125.0 10.0 1.7 125.0 31.0 1.7 Total $ 900.0 $ 128.0 $ 2.2 $ 900.0 $ 139.0 $ 2.3 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. (4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility. At Sept. 30, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sept. 30, 2015 and Dec. 31, 2014 was 1.28% and 1.16%, respectively. Tampa Electric Company Accounts Receivable Facility On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Sept. 30, 2015, TEC and TRC were in compliance with the requirements of the agreement.
Tampa Electric Company [Member]
Short-Term Debt	6. Short-Term Debt At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities Sept. 30, 2015 Dec. 31, 2014 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 12.0 $ 0.6 3-year accounts receivable facility (3) 150.0 0.0 0.0 150.0 46.0 0.0 Total $ 475.0 $ 0.0 $ 0.5 $ 475.0 $ 58.0 $ 0.6 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. At Sept. 30, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2014 was 0.7%. There were no outstanding borrowings at Sept. 30, 2015. Tampa Electric Company Accounts Receivable Facility On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Sept. 30, 2015, TEC and TRC were in compliance with the requirements of the agreement.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At Sept. 30, 2015, total long-term debt had a carrying amount of $3,851.0 million and an estimated fair market value of $4,126.1 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 13 Issuance of TEC 4.20% Notes due 2045 On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the Notes). The Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the 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 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 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption. Issuance of TECO Finance Floating Rate Notes due 2018 On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018, The 2018 Notes will bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points, which is payable quarterly on Jan. 10, Apr. 10, July 10 and Oct. 10 of each year, beginning July 10, 2015. Interest on the 2018 Notes will be computed on the basis of the actual number of days elapsed over a 360-day year. The 2018 Notes will not be subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness. TECO Finance is a wholly owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy. The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment at maturity of $191 million of TECO Finance notes due in May 2015.
Tampa Electric Company [Member]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At Sept. 30, 2015, TEC’s total long-term debt had a carrying amount of $2,263.2 million and an estimated fair market value of $2,466.3 million. At Dec. 31, 2014, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 11 Issuance of TEC 4.20% Notes due 2045 On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the Notes). The Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the 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 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 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Other Comprehensive Income

Other Comprehensive Income	9 Months Ended
	Sep. 30, 2015
Other Comprehensive Income	8. Other Comprehensive Income TECO Energy reported the following OCI for the three and nine months ended Sept. 30, 2015 and 2014, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans: Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.9 (1.1 ) 1.8 Change in benefit obligation due to valuation (3) (8.7 ) 3.0 (5.7 ) (8.7 ) 3.0 (5.7 ) Recognized cost due to settlement (4) 12.1 (4.4 ) 7.7 12.1 (4.4 ) 7.7 Total other comprehensive income (loss) $ 4.1 $ (1.7 ) $ 2.4 $ 11.6 $ (4.5 ) $ 7.1 2014 Unrealized loss on cash flow hedges $ (0.3 ) $ 0.1 $ (0.2 ) $ (0.3 ) $ 0.1 $ (0.2 ) Reclassification from AOCI to net income (1) 0.4 (0.1 ) 0.3 0.9 (0.3 ) 0.6 Gain on cash flow hedges 0.1 0.0 0.1 0.6 (0.2 ) 0.4 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.4 (0.8 ) 1.6 Increase in unrecognized postemployment costs (5) 0.0 0.0 0.0 (12.9 ) 4.7 (8.2 ) Change in benefit obligation due to remeasurement (1.1 ) 0.4 (0.7 ) (1.1 ) 0.4 (0.7 ) Total other comprehensive income (loss) $ (0.6 ) $ 0.2 $ (0.4 ) $ (11.0 ) $ 4.1 $ (6.9 ) (1) Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations. (2) Related to postretirement and postemployment benefits. See Note 5 (3) Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI. (4) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 5 15 (5) Amounts reflect an out-of-period adjustment related to TECO Coal's unfunded black lung liability. Accumulated Other Comprehensive Loss (millions) Sept. 30, 2015 Dec. 31, 2014 Unamortized pension loss and prior service credit (1) $ (25.8 ) $ (22.5 ) Unamortized other benefit gains, prior service costs and transition obligations (2) 21.0 13.9 Net unrealized gains (losses) from cash flow hedges (3) (3.8 ) (7.1 ) Total accumulated other comprehensive loss $ (8.6 ) $ (15.7 ) (1) Net of tax benefit of $16.2 million and $13.8 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. (2) Net of tax expense of $13.2 million and $8.3 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. (3) Net of tax benefit of $2.4 million and $4.5 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	12. Other Comprehensive Income Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 5.3 $ (2.0 ) $ 3.3 2014 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 0.4 (0.1 ) 0.3 0.8 (0.3 ) 0.5 Gain on cash flow hedges 0.4 (0.1 ) 0.3 0.8 (0.3 ) 0.5 Total other comprehensive income $ 0.4 $ (0.1 ) $ 0.3 $ 0.8 $ (0.3 ) $ 0.5 Accumulated Other Comprehensive Loss (millions) Sept. 30, 2015 Dec. 31, 2014 Net unrealized losses from cash flow hedges (1) $ (3.8 ) $ (7.1 ) Total accumulated other comprehensive loss $ (3.8 ) $ (7.1 ) (1) Net of tax benefit of $2.4 million and $4.5 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Earnings Per Share	9. Earnings Per Share For the three months ended Sept. 30, For the nine months ended Sept. 30, (millions, except per share amounts) 2015 2014 (1) 2015 2014 (1) Basic earnings per share Net income from continuing operations $ 64.9 $ 73.0 $ 190.2 $ 179.0 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Income before discontinued operations available to common shareholders - Basic $ 64.7 $ 72.8 $ 189.6 $ 178.4 Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Amount allocated to nonvested participating shareholders 0.0 0.0 0.0 0.0 Loss from discontinued operations available to common shareholders - Basic $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Net income $ 53.2 $ 11.1 $ 123.0 $ 119.6 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Net income available to common shareholders - Basic $ 53.0 $ 10.9 $ 122.4 $ 119.0 Average common shares outstanding - Basic 233.2 227.8 233.0 220.3 Earnings per share from continuing operations available to common shareholders - Basic $ 0.28 $ 0.32 $ 0.81 $ 0.81 Earnings per share from discontinued operations available to common shareholders - Basic $ (0.05 ) $ (0.28 ) $ (0.28 ) $ (0.27 ) Earnings per share available to common shareholders - Basic $ 0.23 $ 0.04 $ 0.53 $ 0.54 Diluted earnings per share Net income from continuing operations $ 64.9 $ 73.0 $ 190.2 $ 179.0 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Income before discontinued operations available to common shareholders - Diluted $ 64.7 $ 72.8 $ 189.6 $ 178.4 Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Amount allocated to nonvested participating shareholders 0.0 0.0 0.0 0.0 Loss from discontinued operations available to common shareholders - Diluted $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Net income $ 53.2 $ 11.1 $ 123.0 $ 119.6 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Net income available to common shareholders - Diluted $ 53.0 $ 10.9 $ 122.4 $ 119.0 Unadjusted average common shares outstanding - Diluted 233.2 227.8 233.0 220.3 Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net 1.5 0.5 1.4 0.5 Average common shares outstanding - Diluted 234.7 228.3 234.4 220.8 Earnings per share from continuing operations available to common shareholders - Diluted $ 0.28 $ 0.32 $ 0.81 $ 0.81 Earnings per share from discontinued operations available to common shareholders - Diluted $ (0.05 ) $ (0.28 ) $ (0.28 ) $ (0.27 ) Earnings per share available to common shareholders - Diluted $ 0.23 $ 0.04 $ 0.53 $ 0.54 Anti-dilutive shares 0.0 0.0 0.0 0.0 (1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 15

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies	10. Commitments and Contingencies Legal Contingencies From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. Tampa Electric Legal Proceedings A thirty-six year old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and fourteen other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. On Aug. 6, 2015, Tampa Electric agreed to a settlement which resolved the case in its entirety. A thirty-three year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence. Plaintiffs' case against Tampa Electric alleges, among other things, negligence and loss of consortium. Discovery is currently ongoing in the case. Peoples Gas Legal Proceedings In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in 2016. New Mexico Gas Company Legal Proceedings In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business). In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.” In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. In addition to the two settled class actions described above, eighteen insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. These subrogation matters are pending and discovery is proceeding. NMGC has filed motions to dismiss, and the motions are pending. TECO Guatemala Holdings, LLC v. The Republic of Guatemala On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding. While the duration of the annulment proceedings is uncertain, a hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision. Proceedings in connection with the Pending Merger with Emera Eleven securities class action lawsuits were filed in September and October 2015 against the company and its directors by holders of TECO Energy securities. These suits, which were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida, allege that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and seek to enjoin the Merger. In addition, several of these suits allege that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. The court's order also indicates that any future actions with allegations and claims substantially similar to those in the initial lawsuits will also be consolidated. The company also received two separate shareholder demand letters from purported shareholders of the company. Both of these letters demand that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices. One of the letters also demands that the company refrain from consummating the transaction with Emera. The outcome of the lawsuits and the demand letters cannot be predicted with any certainty. The company believes that the claims asserted are without merit. 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 Sept. 30, 2015, 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 “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. Guarantees and Letters of Credit A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Sept. 30, 2015 is as follows: (millions) Year of expiration Maximum After (1) Theoretical Liabilities Recognized Guarantees for the Benefit of: 2015 2016 2017-2019 2019 Obligation at Sept. 30, 2015 (2) TECO Energy Fuel sales and transportation $ 0.0 $ 0.0 $ 0.0 $ 92.9 $ 92.9 $ 0.0 Letters of indemnity - coal mining permits (3) $ 0.0 $ 93.8 $ 0.0 $ 0.0 $ 93.8 $ 0.0 Maximum (millions) After (1) Theoretical Liabilities Recognized Letters of Credit for the Benefit of: 2015 2016 2017-2019 2019 Obligation at Sept. 30, 2015 (4) TEC $ 0.0 $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 NMGC $ 0.0 $ 0.0 $ 0.0 $ 1.7 $ 1.7 $ 0.0 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Sept. 30, 2015. See Note 12 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15 (4) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Sept. 30, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims. Financial Covenants In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2015, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.
Tampa Electric Company [Member]
Commitments and Contingencies	8. Commitments and Contingencies Legal Contingencies From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. Tampa Electric Legal Proceedings A thirty-six year old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and fourteen other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. On Aug. 6, 2015, Tampa Electric agreed to a settlement which resolved the case in its entirety. A thirty-three year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence. Plaintiffs' case against Tampa Electric alleges, among other things, negligence and loss of consortium. Discovery is currently ongoing in the case. Peoples Gas Legal Proceedings In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in 2016. 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 Sept. 30, 2015, 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 “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. Guarantees and Letters of Credit A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2015 is as follows: Letters of Credit - Tampa Electric Company (millions) After (1) Liabilities Recognized Letters of Credit for the Benefit of: 2015 2016-2019 2019 Total at Sept. 30, 2015 TEC (2) $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 (1) (2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Sept. 30, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims Financial Covenants In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2015, TEC was in compliance with all applicable financial covenants.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2015
Segment Information	11. Segment Information TECO Energy is an electric and gas utility holding company with diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments. Segment Information (1) (millions) Tampa Peoples New Mexico TECO TECO Three months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) (3) Eliminations (3) Energy 2015 Revenues - external $ 559.4 $ 88.1 $ 43.7 $ 0.0 $ 2.6 $ 0.0 $ 693.8 Sales to affiliates 0.8 2.0 0.0 0.0 0.0 (2.8 ) 0.0 Total revenues 560.2 90.1 43.7 0.0 2.6 (2.8 ) 693.8 Depreciation and amortization 64.6 14.4 8.5 0.0 0.3 0.0 87.8 Total interest charges 24.1 3.7 3.2 0.0 15.4 (0.3 ) 46.1 Internally allocated interest 0.0 0.0 0.0 0.0 0.3 (0.3 ) 0.0 Provision (benefit) for income taxes 50.0 3.5 (1.9 ) 0.0 (9.9 ) 0.0 41.7 Net income (loss) from continuing operations 82.1 6.2 (2.8 ) 0.0 (20.6 ) 0.0 64.9 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (12.1 ) 0.4 0.0 (11.7 ) Net income (loss) $ 82.1 $ 6.2 $ (2.8 ) $ (12.1 ) $ (20.2 ) $ 0.0 $ 53.2 2014 Revenues - external $ 581.5 $ 86.9 $ 16.2 $ 0.0 $ 2.6 $ 0.0 $ 687.2 Sales to affiliates 0.3 0.0 0.0 0.0 0.1 (0.4 ) 0.0 Total revenues 581.8 86.9 16.2 0.0 2.7 (0.4 ) 687.2 Depreciation and amortization 61.8 13.6 2.8 0.0 0.4 0.0 78.6 Total interest charges 23.8 3.5 1.1 0.0 15.9 (1.4 ) 42.9 Internally allocated interest 0.0 0.0 0.0 0.0 1.9 (1.9 ) 0.0 Provision (benefit) for income taxes 48.5 3.0 (0.5 ) 0.0 (17.3 ) 0.0 33.7 Net income (loss) from continuing operations 79.7 4.8 (0.9 ) 0.0 (10.6 ) 0.0 73.0 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (64.8 ) 2.9 0.0 (61.9 ) Net income (loss) $ 79.7 $ 4.8 $ (0.9 ) $ (64.8 ) $ (7.7 ) $ 0.0 11.1 (millions) Tampa Peoples New Mexico TECO TECO Nine months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) (3) Eliminations (3) Energy 2015 Revenues - external $ 1,540.8 $ 302.0 $ 216.7 $ 0.0 $ 7.9 $ 0.0 $ 2,067.4 Sales to affiliates 2.4 4.5 0.0 0.0 0.1 (7.0 ) 0.0 Total revenues 1,543.2 306.5 216.7 0.0 8.0 (7.0 ) 2,067.4 Depreciation and amortization 191.5 42.3 25.3 0.0 1.2 0.0 260.3 Total interest charges 71.2 10.8 9.8 0.0 49.6 (1.0 ) 140.4 Internally allocated interest 0.0 0.0 0.0 0.0 1.0 (1.0 ) 0.0 Provision (benefit) for income taxes 116.3 17.5 7.1 0.0 (18.8 ) 0.0 122.1 Net income (loss) from continuing operations 198.0 28.4 11.0 0.0 (47.2 ) 0.0 190.2 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (69.6 ) 2.4 0.0 (67.2 ) Net income (loss) $ 198.0 $ 28.4 $ 11.0 $ (69.6 ) $ (44.8 ) $ 0.0 $ 123.0 2014 Revenues - external $ 1,546.9 $ 300.0 $ 16.2 $ 0.0 $ 7.8 $ 0.0 $ 1,870.9 Sales to affiliates 0.8 0.6 0.0 0.0 0.1 (1.5 ) 0.0 Total revenues 1,547.7 300.6 16.2 0.0 7.9 (1.5 ) 1,870.9 Depreciation and amortization 185.6 40.3 2.8 0.0 1.3 0.0 230.0 Total interest charges 69.1 10.3 1.1 0.0 46.4 (3.7 ) 123.2 Internally allocated interest 0.0 0.0 0.0 0.0 3.7 (3.7 ) 0.0 Provision (benefit) for income taxes 112.2 17.0 (0.5 ) 0.0 (30.7 ) 0.0 98.0 Net income (loss) from continuing operations 187.1 26.9 (0.9 ) 0.0 (34.1 ) 0.0 179.0 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (65.6 ) 6.2 0.0 (59.4 ) Net income (loss) $ 187.1 $ 26.9 $ (0.9 ) $ (65.6 ) $ (27.9 ) $ 0.0 $ 119.6 At Sept. 30, 2015 Total assets $ 6,804.2 $ 1,099.0 $ 1,188.7 $ 0.0 $ 5,819.6 $ (6,094.6 ) $ 8,816.9 At Dec. 31, 2014 Total assets $ 6,565.4 $ 1,082.8 $ 1,237.2 $ 227.7 $ 1,611.6 $ (1,998.5 ) 8,726.2 (1) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15 (2) NMGI is included in the Other segment. (3) Certain prior year amounts have been reclassified to conform to current year presentation.
Tampa Electric Company [Member]
Segment Information	9. Segment Information (millions) Tampa Peoples Tampa Electric Three months ended Sept. 30, Electric Gas Eliminations Company 2015 Revenues - external $ 560.1 $ 88.1 $ 0.0 $ 648.2 Intracompany sales 0.1 2.0 (2.1 ) 0.0 Total revenues 560.2 90.1 (2.1 ) 648.2 Depreciation and amortization 64.6 14.4 0.0 79.0 Total interest charges 24.1 3.7 0.0 27.8 Provision for income taxes 50.0 3.5 0.0 53.5 Net income 82.1 6.2 0.0 88.3 2014 Revenues - external $ 581.6 $ 86.9 $ 0.0 $ 668.5 Intracompany sales 0.2 0.0 (0.2 ) 0.0 Total revenues 581.8 86.9 (0.2 ) 668.5 Depreciation and amortization 61.8 13.6 0.0 75.4 Total interest charges 23.8 3.5 0.0 27.3 Provision for income taxes 48.5 3.0 0.0 51.5 Net income $ 79.7 $ 4.8 $ 0.0 $ 84.5 Nine months ended Sept. 30, 2015 Revenues - external $ 1,542.9 $ 302.0 $ 0.0 $ 1,844.9 Intracompany sales 0.3 4.5 (4.8 ) 0.0 Total revenues 1,543.2 306.5 (4.8 ) 1,844.9 Depreciation and amortization 191.5 42.3 0.0 233.8 Total interest charges 71.2 10.8 0.0 82.0 Provision for income taxes 116.3 17.5 0.0 133.8 Net income $ 198.0 $ 28.4 $ 0.0 $ 226.4 2014 Revenues - external $ 1,547.3 $ 300.0 $ 0.0 $ 1,847.3 Intracompany sales 0.4 0.6 (1.0 ) 0.0 Total revenues 1,547.7 300.6 (1.0 ) 1,847.3 Depreciation and amortization 185.6 40.3 0.0 225.9 Total interest charges 69.1 10.3 0.0 79.4 Provision for income taxes 112.2 17.0 0.0 129.2 Net income $ 187.1 $ 26.9 $ 0.0 $ 214.0 Total assets at Sept. 30, 2015 $ 6,469.5 $ 1,065.6 $ (2.6 ) $ 7,532.5 Total assets at Dec. 31, 2014 6,234.4 1,047.0 (7.1 ) 7,274.3

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2015
Accounting for Derivative Instruments and Hedging Activities	12. Accounting for Derivative Instruments and Hedging Activities From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes: · To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; and · To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates. TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 13 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 Sept. 30, 2015, all of the company’s physical contracts qualify for the NPNS exception. The derivatives that are designated as cash flow hedges at Sept. 30, 2015 and Dec. 31, 2014 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.2 million and $0.0 as of Sept. 30, 2015 and Dec. 31, 2014, respectively, and derivative liabilities totaled $26.6 million and $42.7 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. All of the derivative assets and liabilities at Sept. 30, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2015, net pretax losses of $23.7 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. The Sept. 30, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2015 and 2014 is presented in Note 8 The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years: Derivative Volumes Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2015 0.0 13.5 2016 0.0 35.8 2017 0.0 4.2 Total 0.0 53.5 The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Sept. 30, 2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated. The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination. The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.
Tampa Electric Company [Member]
Accounting for Derivative Instruments and Hedging Activities	10. 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 11 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 Sept. 30, 2015, all of TEC’s physical contracts qualify for the NPNS exception. The derivatives that are designated as cash flow hedges at Sept. 30, 2015 and Dec. 31, 2014 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 as of Sept. 30, 2015 and Dec. 31, 2014, and derivative liabilities totaled $26.6 million and $42.7 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. All of the derivative assets and liabilities at Sept. 30, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Sept. 30, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. The Sept. 30, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and nine months ended Sept. 30, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three and nine months ended Sept. 30, 2015 and 2014 is presented in Note 12 The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Sept.30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2015 0.0 8.6 2016 0.0 27.1 2017 0.0 4.2 Total 0.0 39.9 TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Sept. 30, 2015, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated. TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination. TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
Fair Value Measurements	13. 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 Sept. 30, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Recurring Fair Value Measures As of Sept. 30, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.6 $ 0.0 $ 26.6 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas derivatives $ 0.0 $ 42.7 $ 0.0 $ 42.7 The natural gas derivatives are OTC swap and option instruments. Fair values of swaps and options are estimated utilizing the market and income approach, respectively. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap and option positions to determine the fair value (see Note 12 The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Sept. 30, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.
Tampa Electric Company [Member]
Fair Value Measurements	11. 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, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sept. 30, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Recurring Derivative Fair Value Measures As of Sept. 30, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.6 $ 0.0 $ 26.6 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 42.7 $ 0.0 $ 42.7 Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10 TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Sept. 30, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2015
Variable Interest Entities	14. Variable Interest Entities In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. 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 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. 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, and have 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 $10.7 million and $26.0 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2015, respectively, and $8.1 million and $20.9 million for the three and nine months ended Sept. 30, 2014, respectively. The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.
Tampa Electric Company [Member]
Variable Interest Entities	13. Variable Interest Entities In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. 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 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. 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, and have 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 $10.7 million and $26.0 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2015, respectively, and $8.1 million and $20.9 million for the three and nine months ended Sept. 30, 2014, respectively. TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

Discontinued Operations and Ass

Discontinued Operations and Asset Impairments	9 Months Ended
	Sep. 30, 2015
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations, Assets Held for Sale and Asset Impairments	15. Discontinued Operations and Asset Impairments TECO Coal On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian Coal Corporation. The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid between 2015 and 2019 if certain coal benchmark prices reach certain levels. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 10 Note 5 In September 2014, the Board of Directors of TECO Energy authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal. In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded, which included the estimated selling costs associated with this transaction. Since the closing of the sale, TECO Energy will not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance. The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items: Assets held for sale (millions) Sept. 30, 2015 Dec. 31, 2014 Current assets $ 0.0 $ 109.6 Property, plant and equipment, net and other long-term assets 0.0 59.8 Total assets held for sale $ 0.0 $ 169.4 Liabilities associated with assets held for sale (millions) Sept. 30, 2015 Dec. 31, 2014 Current liabilities $ 0.0 $ 39.4 Long-term liabilities 0.0 65.4 Total liabilities associated with assets held for sale $ 0.0 $ 104.8 TECO Guatemala In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 10 Combined Components of Discontinued Operations The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala: Components of income from discontinued operations Three months ended Nine months ended Sept. 30, Sept. 30, (millions) 2015 2014 2015 2014 Revenues—TECO Coal $ 51.6 $ 101.6 $ 200.4 $ 328.3 Loss from operations—TECO Coal (7.4 ) (0.4 ) (16.4 ) (4.2 ) Loss on sale—TECO Coal (10.0 ) 0.0 (10.0 ) 0.0 Loss on impairment—TECO Coal 0.0 (98.4 ) (78.6 ) (98.4 ) Income (loss) from operations—TECO Guatemala (0.4 ) 0.0 (0.5 ) 5.0 Loss from discontinued operations—TECO Coal (17.4 ) (98.8 ) (105.0 ) (102.6 ) Income (loss) from discontinued operations—TECO Guatemala (0.4 ) 0.0 (0.5 ) 5.0 Loss from discontinued operations (17.8 ) (98.8 ) (105.5 ) (97.6 ) Benefit from income taxes (6.1 ) (36.9 ) (38.3 ) (38.2 ) Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 )

Mergers and Acquisitions

Mergers and Acquisitions	9 Months Ended
	Sep. 30, 2015
Mergers and Acquisitions	16. Mergers and Acquisitions Pending Merger with Emera Inc. On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned subsidiary of Emera. Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation. Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur by mid-2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt. The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States, (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement. The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals. In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing. TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties, except under limited circumstances to permit TECO Energy’s board of directors to comply with its fiduciary duties. The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million. During the three months ended Sept. 30, 2015, TECO Energy incurred approximately $15.4 million pretax of transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income. Acquisition of New Mexico Gas Company 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. Current Quarter and Year-to-Date Impact of NMGI Acquisition The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2015 was an increase of $43.7 million and $216.7 million, respectively, compared with an increase of $16.2 million for the three and nine months ended Sept. 30, 2014. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2015 was a decrease of $3.9 million and an increase of $7.6 million, respectively, compared with a decrease of $2.0 million for the three and nine months ended Sept. 30, 2014. Pro Forma Impact of the NMGI 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 $0.9 million and $5.7 million for the three and nine months ended Sept. 30, 2014. Pro Forma Impact of Acquisition Three months ended Nine months ended (millions, except per share amounts) Sept. 30, 2014 Sept. 30, 2014 Revenues $ 720.0 $ 2,111.0 Net income from continuing operations $ 70.8 $ 199.3 Basic and Diluted EPS from continuing operations $ 0.31 $ 0.86 Transaction and Integration Costs The following after-tax transaction and integration charges were recognized in connection with the NMGI acquisition and are included in the TECO Energy Consolidated Statements of Operations for the three and nine months ended Sept. 30, 2015 and 2014. Transaction and Integration Costs Three months ended Sept. 30, Nine months ended Sept. 30, (millions) 2015 2014 2015 2014 Legal and other consultants $ 0.1 $ 5.3 $ 0.4 $ 7.2 Bridge loan costs 0.0 0.4 0.0 2.9 Severance and relocation costs 0.0 1.7 0.5 1.7 Other costs and tax benefit 0.1 (6.5 ) 0.3 (6.1 ) Total accounting charges $ 0.2 $ 0.9 $ 1.2 $ 5.7 The company has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period. In conjunction with the acquisition, in September 2014, TECO Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the severance plan began in the third quarter of 2014, and substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Sept. 30, 2015 and Dec. 31, 2014, the obligations associated with the severance benefits costs were $0.3 million and $2.6 million, respectively.
Tampa Electric Company [Member]
Mergers and Acquisitions	14. Mergers and Acquisitions Pending Merger with Emera Inc. On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned subsidiary of Emera. Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation. Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur by mid-2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion). The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States, (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement. TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties, except under limited circumstances to permit TECO Energy’s board of directors to comply with its fiduciary duties. The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Sept. 30, 2015. In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges and gains at Parent and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 15 On Sept. 4, 2015, TECO Energy and Emera entered into an agreement and plan of merger (Merger Agreement). Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 16
Revenues	Revenues As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $66.7 million and $86.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipt Taxes	Accounting for Franchise Fees and Gross Receipt Taxes Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.
Tampa Electric Company [Member]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13 Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Sept. 30, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Sept. 30, 2015 and 2014. The results of operations for the three and nine months ended Sept. 30, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 14
Revenues	Revenues As of Sept. 30, 2015 and Dec. 31, 2014, unbilled revenues of $60.0 million and $49.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipt Taxes	Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $88.3 million, respectively, for the three and nine months ended Sept. 30, 2015, compared to $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014.

Regulatory (Tables)

Regulatory (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2015 Dec. 31, 2014 Regulatory assets: Regulatory tax asset (1) $ 73.1 $ 69.2 Cost-recovery clauses - deferred balances (2) 2.8 1.9 Cost-recovery clauses - offsets to derivative liabilities (2) 28.1 43.2 Environmental remediation (3) 52.6 53.1 Postretirement benefits (4) 177.4 194.0 Deferred bond refinancing costs (5) 6.6 7.2 Debt basis adjustment (6) 18.3 20.9 Competitive rate adjustment (2) 2.4 2.8 Other 12.6 9.8 Total regulatory assets 373.9 402.1 Less: Current portion 43.1 53.6 Long-term regulatory assets $ 330.8 $ 348.5 Regulatory liabilities: Regulatory tax liability $ 6.2 $ 6.9 Cost-recovery clauses 40.2 25.9 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (7) 682.1 695.2 Other 0.7 1.9 Total regulatory liabilities 785.3 786.0 Less: Current portion 69.1 57.0 Long-term regulatory liabilities $ 716.2 $ 729.0 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets are related to FPSC and NMPRC clauses and riders. They are recovered through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instrument. (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.
Tampa Electric Company [Member]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of Sept. 30, 2015 and Dec. 31, 2014 are presented in the following table: Regulatory Assets and Liabilities (millions) Sept. 30, 2015 Dec. 31, 2014 Regulatory assets: Regulatory tax asset (1) $ 73.0 $ 69.2 Cost-recovery clauses - deferred balances (2) 0.1 0.9 Cost-recovery clauses - offsets to derivative liabilities (2) 27.4 42.7 Environmental remediation (3) 52.6 53.1 Postretirement benefit costs (4) 172.0 187.8 Deferred bond refinancing costs (5) 6.6 7.2 Competitive rate adjustment (2) 2.4 2.8 Other 11.0 8.0 Total regulatory assets 345.1 371.7 Less: Current portion 39.7 52.1 Long-term regulatory assets $ 305.4 $ 319.6 Regulatory liabilities: Regulatory tax liability $ 4.3 $ 5.1 Cost-recovery clauses 36.6 23.5 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve - cost of removal (6) 573.7 591.5 Other 0.7 1.9 Total regulatory liabilities 671.4 678.1 Less: Current portion 65.7 54.7 Long-term regulatory liabilities $ 605.7 $ 623.4 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets are related to FPSC clauses and riders. They are recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. (4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants. (5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

Employee Postretirement Benef26

Employee Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2015
Compensation And Retirement Disclosure [Abstract]
Schedule of Net Periodic Benefit Cost	Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP. Pension Expense (millions) Pension Benefits Other Postretirement Benefits Three months ended Sept. 30, 2015 2014 2015 2014 Components of net periodic benefit expense Service cost $ 6.7 $ 4.6 $ 0.6 $ 0.6 Interest cost 6.5 8.0 2.0 2.7 Expected return on assets (9.1 ) (10.5 ) (0.3 ) (0.1 ) Amortization of: Prior service (benefit) cost (0.1 ) (0.1 ) (0.6 ) 0.0 Actuarial loss 3.2 3.3 0.0 0.0 Regulatory asset 0.0 0.0 0.3 0.1 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 7.2 $ 5.3 $ 2.0 $ 3.3 Nine months ended Sept. 30, Components of net periodic benefit expense Service cost $ 17.6 $ 12.9 $ 1.7 $ 1.8 Interest cost 22.6 24.4 6.1 7.9 Expected return on assets (32.4 ) (31.2 ) (0.8 ) (0.1 ) Amortization of: Prior service (benefit) cost (0.2 ) (0.3 ) (1.8 ) (0.1 ) Actuarial loss 11.4 10.0 0.0 0.1 Regulatory asset 0.0 0.0 0.8 0.1 Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income $ 19.0 $ 15.8 $ 6.0 $ 9.7

Short-Term Debt (Tables)

Short-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Short-Term Debt Credit Facilities	At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities Sept. 30, 2015 Dec. 31, 2014 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 12.0 $ 0.6 3-year accounts receivable facility (3) 150.0 0.0 0.0 150.0 46.0 0.0 TECO Energy/TECO Finance: 5-year facility (2)(4) 300.0 118.0 0.0 300.0 50.0 0.0 New Mexico Gas Company: 5-year facility (2) 125.0 10.0 1.7 125.0 31.0 1.7 Total $ 900.0 $ 128.0 $ 2.2 $ 900.0 $ 139.0 $ 2.3 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. (4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
Tampa Electric Company [Member]
Short-Term Debt Credit Facilities	At Sept. 30, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed: Credit Facilities Sept. 30, 2015 Dec. 31, 2014 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325.0 $ 0.0 $ 0.5 $ 325.0 $ 12.0 $ 0.6 3-year accounts receivable facility (3) 150.0 0.0 0.0 150.0 46.0 0.0 Total $ 475.0 $ 0.0 $ 0.5 $ 475.0 $ 58.0 $ 0.6 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures Dec. 17, 2018. (3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2015
Other Comprehensive Income	TECO Energy reported the following OCI for the three and nine months ended Sept. 30, 2015 and 2014, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans: Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income (1) 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.9 (1.1 ) 1.8 Change in benefit obligation due to valuation (3) (8.7 ) 3.0 (5.7 ) (8.7 ) 3.0 (5.7 ) Recognized cost due to settlement (4) 12.1 (4.4 ) 7.7 12.1 (4.4 ) 7.7 Total other comprehensive income (loss) $ 4.1 $ (1.7 ) $ 2.4 $ 11.6 $ (4.5 ) $ 7.1 2014 Unrealized loss on cash flow hedges $ (0.3 ) $ 0.1 $ (0.2 ) $ (0.3 ) $ 0.1 $ (0.2 ) Reclassification from AOCI to net income (1) 0.4 (0.1 ) 0.3 0.9 (0.3 ) 0.6 Gain on cash flow hedges 0.1 0.0 0.1 0.6 (0.2 ) 0.4 Amortization of unrecognized benefit costs (2) 0.4 (0.2 ) 0.2 2.4 (0.8 ) 1.6 Increase in unrecognized postemployment costs (5) 0.0 0.0 0.0 (12.9 ) 4.7 (8.2 ) Change in benefit obligation due to remeasurement (1.1 ) 0.4 (0.7 ) (1.1 ) 0.4 (0.7 ) Total other comprehensive income (loss) $ (0.6 ) $ 0.2 $ (0.4 ) $ (11.0 ) $ 4.1 $ (6.9 ) (1) Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations. (2) Related to postretirement and postemployment benefits. See Note 5 (3) Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI. (4) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 5 15 (5) Amounts reflect an out-of-period adjustment related to TECO Coal's unfunded black lung liability.
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) Sept. 30, 2015 Dec. 31, 2014 Unamortized pension loss and prior service credit (1) $ (25.8 ) $ (22.5 ) Unamortized other benefit gains, prior service costs and transition obligations (2) 21.0 13.9 Net unrealized gains (losses) from cash flow hedges (3) (3.8 ) (7.1 ) Total accumulated other comprehensive loss $ (8.6 ) $ (15.7 ) (1) Net of tax benefit of $16.2 million and $13.8 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. (2) Net of tax expense of $13.2 million and $8.3 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively. (3) Net of tax benefit of $2.4 million and $4.5 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.
Tampa Electric Company [Member]
Other Comprehensive Income	Other Comprehensive Income Three months ended Sept. 30, Nine months ended Sept. 30, (millions) Gross Tax Net Gross Tax Net 2015 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 0.3 (0.1 ) 0.2 1.0 (0.5 ) 0.5 Gain on cash flow hedges 0.3 (0.1 ) 0.2 5.3 (2.0 ) 3.3 Total other comprehensive income $ 0.3 $ (0.1 ) $ 0.2 $ 5.3 $ (2.0 ) $ 3.3 2014 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 0.4 (0.1 ) 0.3 0.8 (0.3 ) 0.5 Gain on cash flow hedges 0.4 (0.1 ) 0.3 0.8 (0.3 ) 0.5 Total other comprehensive income $ 0.4 $ (0.1 ) $ 0.3 $ 0.8 $ (0.3 ) $ 0.5
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) Sept. 30, 2015 Dec. 31, 2014 Net unrealized losses from cash flow hedges (1) $ (3.8 ) $ (7.1 ) Total accumulated other comprehensive loss $ (3.8 ) $ (7.1 ) (1) Net of tax benefit of $2.4 million and $4.5 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share	For the three months ended Sept. 30, For the nine months ended Sept. 30, (millions, except per share amounts) 2015 2014 (1) 2015 2014 (1) Basic earnings per share Net income from continuing operations $ 64.9 $ 73.0 $ 190.2 $ 179.0 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Income before discontinued operations available to common shareholders - Basic $ 64.7 $ 72.8 $ 189.6 $ 178.4 Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Amount allocated to nonvested participating shareholders 0.0 0.0 0.0 0.0 Loss from discontinued operations available to common shareholders - Basic $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Net income $ 53.2 $ 11.1 $ 123.0 $ 119.6 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Net income available to common shareholders - Basic $ 53.0 $ 10.9 $ 122.4 $ 119.0 Average common shares outstanding - Basic 233.2 227.8 233.0 220.3 Earnings per share from continuing operations available to common shareholders - Basic $ 0.28 $ 0.32 $ 0.81 $ 0.81 Earnings per share from discontinued operations available to common shareholders - Basic $ (0.05 ) $ (0.28 ) $ (0.28 ) $ (0.27 ) Earnings per share available to common shareholders - Basic $ 0.23 $ 0.04 $ 0.53 $ 0.54 Diluted earnings per share Net income from continuing operations $ 64.9 $ 73.0 $ 190.2 $ 179.0 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Income before discontinued operations available to common shareholders - Diluted $ 64.7 $ 72.8 $ 189.6 $ 178.4 Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Amount allocated to nonvested participating shareholders 0.0 0.0 0.0 0.0 Loss from discontinued operations available to common shareholders - Diluted $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 ) Net income $ 53.2 $ 11.1 $ 123.0 $ 119.6 Amount allocated to nonvested participating shareholders (0.2 ) (0.2 ) (0.6 ) (0.6 ) Net income available to common shareholders - Diluted $ 53.0 $ 10.9 $ 122.4 $ 119.0 Unadjusted average common shares outstanding - Diluted 233.2 227.8 233.0 220.3 Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net 1.5 0.5 1.4 0.5 Average common shares outstanding - Diluted 234.7 228.3 234.4 220.8 Earnings per share from continuing operations available to common shareholders - Diluted $ 0.28 $ 0.32 $ 0.81 $ 0.81 Earnings per share from discontinued operations available to common shareholders - Diluted $ (0.05 ) $ (0.28 ) $ (0.28 ) $ (0.27 ) Earnings per share available to common shareholders - Diluted $ 0.23 $ 0.04 $ 0.53 $ 0.54 Anti-dilutive shares 0.0 0.0 0.0 0.0 (1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 15

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2015
Letters of Credit and Guarantees	A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Sept. 30, 2015 is as follows: (millions) Year of expiration Maximum After (1) Theoretical Liabilities Recognized Guarantees for the Benefit of: 2015 2016 2017-2019 2019 Obligation at Sept. 30, 2015 (2) TECO Energy Fuel sales and transportation $ 0.0 $ 0.0 $ 0.0 $ 92.9 $ 92.9 $ 0.0 Letters of indemnity - coal mining permits (3) $ 0.0 $ 93.8 $ 0.0 $ 0.0 $ 93.8 $ 0.0 Maximum (millions) After (1) Theoretical Liabilities Recognized Letters of Credit for the Benefit of: 2015 2016 2017-2019 2019 Obligation at Sept. 30, 2015 (4) TEC $ 0.0 $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 NMGC $ 0.0 $ 0.0 $ 0.0 $ 1.7 $ 1.7 $ 0.0 (1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2019. (2) The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Sept. 30, 2015. See Note 12 (3) These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15 (4) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Sept. 30, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.
Tampa Electric Company [Member]
Letters of Credit and Guarantees	A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2015 is as follows: Letters of Credit - Tampa Electric Company (millions) After (1) Liabilities Recognized Letters of Credit for the Benefit of: 2015 2016-2019 2019 Total at Sept. 30, 2015 TEC (2) $ 0.0 $ 0.0 $ 0.5 $ 0.5 $ 0.1 (1) (2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Sept. 30, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Segment Information	Segment Information (1) (millions) Tampa Peoples New Mexico TECO TECO Three months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) (3) Eliminations (3) Energy 2015 Revenues - external $ 559.4 $ 88.1 $ 43.7 $ 0.0 $ 2.6 $ 0.0 $ 693.8 Sales to affiliates 0.8 2.0 0.0 0.0 0.0 (2.8 ) 0.0 Total revenues 560.2 90.1 43.7 0.0 2.6 (2.8 ) 693.8 Depreciation and amortization 64.6 14.4 8.5 0.0 0.3 0.0 87.8 Total interest charges 24.1 3.7 3.2 0.0 15.4 (0.3 ) 46.1 Internally allocated interest 0.0 0.0 0.0 0.0 0.3 (0.3 ) 0.0 Provision (benefit) for income taxes 50.0 3.5 (1.9 ) 0.0 (9.9 ) 0.0 41.7 Net income (loss) from continuing operations 82.1 6.2 (2.8 ) 0.0 (20.6 ) 0.0 64.9 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (12.1 ) 0.4 0.0 (11.7 ) Net income (loss) $ 82.1 $ 6.2 $ (2.8 ) $ (12.1 ) $ (20.2 ) $ 0.0 $ 53.2 2014 Revenues - external $ 581.5 $ 86.9 $ 16.2 $ 0.0 $ 2.6 $ 0.0 $ 687.2 Sales to affiliates 0.3 0.0 0.0 0.0 0.1 (0.4 ) 0.0 Total revenues 581.8 86.9 16.2 0.0 2.7 (0.4 ) 687.2 Depreciation and amortization 61.8 13.6 2.8 0.0 0.4 0.0 78.6 Total interest charges 23.8 3.5 1.1 0.0 15.9 (1.4 ) 42.9 Internally allocated interest 0.0 0.0 0.0 0.0 1.9 (1.9 ) 0.0 Provision (benefit) for income taxes 48.5 3.0 (0.5 ) 0.0 (17.3 ) 0.0 33.7 Net income (loss) from continuing operations 79.7 4.8 (0.9 ) 0.0 (10.6 ) 0.0 73.0 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (64.8 ) 2.9 0.0 (61.9 ) Net income (loss) $ 79.7 $ 4.8 $ (0.9 ) $ (64.8 ) $ (7.7 ) $ 0.0 11.1 (millions) Tampa Peoples New Mexico TECO TECO Nine months ended Sept. 30, Electric Gas Gas Co. (2) Coal (1) Other (2) (3) Eliminations (3) Energy 2015 Revenues - external $ 1,540.8 $ 302.0 $ 216.7 $ 0.0 $ 7.9 $ 0.0 $ 2,067.4 Sales to affiliates 2.4 4.5 0.0 0.0 0.1 (7.0 ) 0.0 Total revenues 1,543.2 306.5 216.7 0.0 8.0 (7.0 ) 2,067.4 Depreciation and amortization 191.5 42.3 25.3 0.0 1.2 0.0 260.3 Total interest charges 71.2 10.8 9.8 0.0 49.6 (1.0 ) 140.4 Internally allocated interest 0.0 0.0 0.0 0.0 1.0 (1.0 ) 0.0 Provision (benefit) for income taxes 116.3 17.5 7.1 0.0 (18.8 ) 0.0 122.1 Net income (loss) from continuing operations 198.0 28.4 11.0 0.0 (47.2 ) 0.0 190.2 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (69.6 ) 2.4 0.0 (67.2 ) Net income (loss) $ 198.0 $ 28.4 $ 11.0 $ (69.6 ) $ (44.8 ) $ 0.0 $ 123.0 2014 Revenues - external $ 1,546.9 $ 300.0 $ 16.2 $ 0.0 $ 7.8 $ 0.0 $ 1,870.9 Sales to affiliates 0.8 0.6 0.0 0.0 0.1 (1.5 ) 0.0 Total revenues 1,547.7 300.6 16.2 0.0 7.9 (1.5 ) 1,870.9 Depreciation and amortization 185.6 40.3 2.8 0.0 1.3 0.0 230.0 Total interest charges 69.1 10.3 1.1 0.0 46.4 (3.7 ) 123.2 Internally allocated interest 0.0 0.0 0.0 0.0 3.7 (3.7 ) 0.0 Provision (benefit) for income taxes 112.2 17.0 (0.5 ) 0.0 (30.7 ) 0.0 98.0 Net income (loss) from continuing operations 187.1 26.9 (0.9 ) 0.0 (34.1 ) 0.0 179.0 Income (loss) from discontinued operations, net (1) 0.0 0.0 0.0 (65.6 ) 6.2 0.0 (59.4 ) Net income (loss) $ 187.1 $ 26.9 $ (0.9 ) $ (65.6 ) $ (27.9 ) $ 0.0 $ 119.6 At Sept. 30, 2015 Total assets $ 6,804.2 $ 1,099.0 $ 1,188.7 $ 0.0 $ 5,819.6 $ (6,094.6 ) $ 8,816.9 At Dec. 31, 2014 Total assets $ 6,565.4 $ 1,082.8 $ 1,237.2 $ 227.7 $ 1,611.6 $ (1,998.5 ) 8,726.2 (1) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15 (2) NMGI is included in the Other segment. (3) Certain prior year amounts have been reclassified to conform to current year presentation.
Tampa Electric Company [Member]
Schedule of Segment Information	(millions) Tampa Peoples Tampa Electric Three months ended Sept. 30, Electric Gas Eliminations Company 2015 Revenues - external $ 560.1 $ 88.1 $ 0.0 $ 648.2 Intracompany sales 0.1 2.0 (2.1 ) 0.0 Total revenues 560.2 90.1 (2.1 ) 648.2 Depreciation and amortization 64.6 14.4 0.0 79.0 Total interest charges 24.1 3.7 0.0 27.8 Provision for income taxes 50.0 3.5 0.0 53.5 Net income 82.1 6.2 0.0 88.3 2014 Revenues - external $ 581.6 $ 86.9 $ 0.0 $ 668.5 Intracompany sales 0.2 0.0 (0.2 ) 0.0 Total revenues 581.8 86.9 (0.2 ) 668.5 Depreciation and amortization 61.8 13.6 0.0 75.4 Total interest charges 23.8 3.5 0.0 27.3 Provision for income taxes 48.5 3.0 0.0 51.5 Net income $ 79.7 $ 4.8 $ 0.0 $ 84.5 Nine months ended Sept. 30, 2015 Revenues - external $ 1,542.9 $ 302.0 $ 0.0 $ 1,844.9 Intracompany sales 0.3 4.5 (4.8 ) 0.0 Total revenues 1,543.2 306.5 (4.8 ) 1,844.9 Depreciation and amortization 191.5 42.3 0.0 233.8 Total interest charges 71.2 10.8 0.0 82.0 Provision for income taxes 116.3 17.5 0.0 133.8 Net income $ 198.0 $ 28.4 $ 0.0 $ 226.4 2014 Revenues - external $ 1,547.3 $ 300.0 $ 0.0 $ 1,847.3 Intracompany sales 0.4 0.6 (1.0 ) 0.0 Total revenues 1,547.7 300.6 (1.0 ) 1,847.3 Depreciation and amortization 185.6 40.3 0.0 225.9 Total interest charges 69.1 10.3 0.0 79.4 Provision for income taxes 112.2 17.0 0.0 129.2 Net income $ 187.1 $ 26.9 $ 0.0 $ 214.0 Total assets at Sept. 30, 2015 $ 6,469.5 $ 1,065.6 $ (2.6 ) $ 7,532.5 Total assets at Dec. 31, 2014 6,234.4 1,047.0 (7.1 ) 7,274.3

Accounting for Derivative Ins32

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Volumes Expected to Settle	The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Sept. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years: Derivative Volumes Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2015 0.0 13.5 2016 0.0 35.8 2017 0.0 4.2 Total 0.0 53.5
Tampa Electric Company [Member]
Derivative Volumes Expected to Settle	The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Sept.30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Sept. 30, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2015 0.0 8.6 2016 0.0 27.1 2017 0.0 4.2 Total 0.0 39.9

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Recurring Fair Value Measurements	Recurring Fair Value Measures As of Sept. 30, 2015 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas derivatives $ 0.0 $ 0.2 $ 0.0 $ 0.2 Liabilities Natural gas derivatives $ 0.0 $ 26.6 $ 0.0 $ 26.6 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas derivatives $ 0.0 $ 42.7 $ 0.0 $ 42.7
Tampa Electric Company [Member]
Schedule of Recurring Fair Value Measurements	Recurring Derivative Fair Value Measures As of Sept. 30, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.6 $ 0.0 $ 26.6 As of Dec. 31, 2014 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 42.7 $ 0.0 $ 42.7

Discontinued Operations and A34

Discontinued Operations and Asset Impairments (Tables)	9 Months Ended
	Sep. 30, 2015
TECO Coal [Member]
Components of Discontinued Operations	The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items: Assets held for sale (millions) Sept. 30, 2015 Dec. 31, 2014 Current assets $ 0.0 $ 109.6 Property, plant and equipment, net and other long-term assets 0.0 59.8 Total assets held for sale $ 0.0 $ 169.4 Liabilities associated with assets held for sale (millions) Sept. 30, 2015 Dec. 31, 2014 Current liabilities $ 0.0 $ 39.4 Long-term liabilities 0.0 65.4 Total liabilities associated with assets held for sale $ 0.0 $ 104.8
TECO Coal and TECO Guatemala [Member]
Components of Discontinued Operations	The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala: Components of income from discontinued operations Three months ended Nine months ended Sept. 30, Sept. 30, (millions) 2015 2014 2015 2014 Revenues—TECO Coal $ 51.6 $ 101.6 $ 200.4 $ 328.3 Loss from operations—TECO Coal (7.4 ) (0.4 ) (16.4 ) (4.2 ) Loss on sale—TECO Coal (10.0 ) 0.0 (10.0 ) 0.0 Loss on impairment—TECO Coal 0.0 (98.4 ) (78.6 ) (98.4 ) Income (loss) from operations—TECO Guatemala (0.4 ) 0.0 (0.5 ) 5.0 Loss from discontinued operations—TECO Coal (17.4 ) (98.8 ) (105.0 ) (102.6 ) Income (loss) from discontinued operations—TECO Guatemala (0.4 ) 0.0 (0.5 ) 5.0 Loss from discontinued operations (17.8 ) (98.8 ) (105.5 ) (97.6 ) Benefit from income taxes (6.1 ) (36.9 ) (38.3 ) (38.2 ) Loss from discontinued operations, net $ (11.7 ) $ (61.9 ) $ (67.2 ) $ (59.4 )

Mergers and Acquisitions (Table

Mergers and Acquisitions (Tables) - NMGI [Member]	9 Months Ended
	Sep. 30, 2015
Pro Forma Financial Information	Pro Forma Impact of Acquisition Three months ended Nine months ended (millions, except per share amounts) Sept. 30, 2014 Sept. 30, 2014 Revenues $ 720.0 $ 2,111.0 Net income from continuing operations $ 70.8 $ 199.3 Basic and Diluted EPS from continuing operations $ 0.31 $ 0.86
After-tax transaction and integration charges recognized in connection with the acquisition	The following after-tax transaction and integration charges were recognized in connection with the NMGI acquisition and are included in the TECO Energy Consolidated Statements of Operations for the three and nine months ended Sept. 30, 2015 and 2014. Transaction and Integration Costs Three months ended Sept. 30, Nine months ended Sept. 30, (millions) 2015 2014 2015 2014 Legal and other consultants $ 0.1 $ 5.3 $ 0.4 $ 7.2 Bridge loan costs 0.0 0.4 0.0 2.9 Severance and relocation costs 0.0 1.7 0.5 1.7 Other costs and tax benefit 0.1 (6.5 ) 0.3 (6.1 ) Total accounting charges $ 0.2 $ 0.9 $ 1.2 $ 5.7

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	$ 66.7		$ 66.7		$ 86.6
Franchise fees and gross receipts taxes	31.7	$ 31.7	88.3	$ 86.7
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	60		60		$ 49.3
Franchise fees and gross receipts taxes	$ 31.7	$ 31.7	$ 88.3	$ 86.7

New Accounting Pronouncements -

New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	$ 18.5	$ 16.8
Deferred Charges And Other Assets [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	29
Deferred Charges And Other Assets [Member] | Tampa Electric Company [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	$ 18.5

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Regulatory assets:
Regulatory assets	$ 373.9	$ 402.1
Less: Current portion	43.1	53.6
Long-term regulatory assets	330.8	348.5
Regulatory liabilities:
Regulatory liabilities	785.3	786
Less: Current portion	69.1	57
Long-term regulatory liabilities	716.2	729
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	345.1	371.7
Less: Current portion	39.7	52.1
Long-term regulatory assets	305.4	319.6
Regulatory liabilities:
Regulatory liabilities	671.4	678.1
Less: Current portion	65.7	54.7
Long-term regulatory liabilities	605.7	623.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	73.1	69.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	73	69.2
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	2.8	1.9
Cost-Recovery Clauses - Deferred Balances [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	0.1	0.9
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	28.1	43.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	27.4	42.7
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	52.6	53.1
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	52.6	53.1
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	177.4	194
Postretirement Benefit Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	172	187.8
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	6.6	7.2
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	6.6	7.2
Debt Basis Adjustment [Member]
Regulatory assets:
Regulatory assets	18.3	20.9
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.4	2.8
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.4	2.8
Other [Member]
Regulatory assets:
Regulatory assets	12.6	9.8
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	11	8
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	6.2	6.9
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	4.3	5.1
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	40.2	25.9
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	36.6	23.5
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	682.1	695.2
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	573.7	591.5
Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.7	1.9
Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	$ 0.7	$ 1.9

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Income Taxes [Line Items]
Effective tax rate	39.10%	35.38%
Income tax examination period	1 year
Tampa Electric Company [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
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

Employee Postretirement Benef40

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 6.7	$ 4.6	$ 17.6	$ 12.9
Interest cost	6.5	8	22.6	24.4
Expected return on assets	(9.1)	(10.5)	(32.4)	(31.2)
Amortization of:
Prior service (benefit) cost	(0.1)	(0.1)	(0.2)	(0.3)
Actuarial loss	3.2	3.3	11.4	10
Regulatory asset	0	0	0	0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	7.2	5.3	19	15.8
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.6	0.6	1.7	1.8
Interest cost	2	2.7	6.1	7.9
Expected return on assets	(0.3)	(0.1)	(0.8)	(0.1)
Amortization of:
Prior service (benefit) cost	(0.6)	0	(1.8)	(0.1)
Actuarial loss	0	0	0	0.1
Regulatory asset	0.3	0.1	0.8	0.1
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 2	$ 3.3	$ 6	$ 9.7

Employee Postretirement Benef41

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Oct. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Jan. 01, 2015
Defined Benefit Plan Disclosure [Line Items]
Reclassification of AOCI to net income as part of periodic benefit expense		$ 0.2		$ 2.4
Reclassification of regulatory assets to net income as part of periodic benefit expense		2.6	$ 2.7	7.8	$ 7.9
Accumulated Other Comprehensive Income Defined Benefit Plans Amortization Period Increase Decrease			0.7		2
TECO Coal [Member]
Defined Benefit Plan Disclosure [Line Items]
Expenses related to black lung liability		0	0	0	0
Settlement charge, related to unfunded black lung obligations				$ 7.7
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA				7.00%
Reclassification of regulatory assets to net income as part of periodic benefit expense		$ 2.3	2.6	$ 7	7.8
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA				7.00%
Discount rate		4.256%		4.256%
Employer contributions				$ 55	47.5
Net pension expense		$ 7.2	5.3	$ 19	15.8
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.256%		4.256%
Employer contributions				$ 43.9	38.2
Net pension expense		$ 3.3	3.6	10.1	11.3
Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate						4.206%
Other Postretirement Benefits, NMGC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate						4.243%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension expense		2	3.3	6	9.7
Other Postretirement Benefits [Member] | New Mexico Gas Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				2.7
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate						4.206%
Net pension expense		$ 1.4	$ 2.6	$ 4.3	$ 7.8
SERP [Member] | Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 43.4
SERP [Member] | Tampa Electric Company [Member] | Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 14.9

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Line Of Credit Facility [Line Items]
Credit Facilities	$ 900,000,000	$ 900,000,000
Borrowings Outstanding	128,000,000	139,000,000
Letters of Credit Outstanding	2,200,000	2,300,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	475,000,000	475,000,000
Borrowings Outstanding	0	58,000,000
Letters of Credit Outstanding	500,000	600,000
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000	325,000,000
Borrowings Outstanding	0	12,000,000
Letters of Credit Outstanding	500,000	600,000
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000	150,000,000
Borrowings Outstanding	0	46,000,000
Letters of Credit Outstanding	0	0
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000	300,000,000
Borrowings Outstanding	118,000,000	50,000,000
Letters of Credit Outstanding	0	0
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	125,000,000	125,000,000
Borrowings Outstanding	10,000,000	31,000,000
Letters of Credit Outstanding	$ 1,700,000	$ 1,700,000

Short-Term Debt - Credit Faci43

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Tampa Electric Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member] | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018
TECO Energy [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
New Mexico Gas Company [Member] | 5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Mar. 24, 2015	Sep. 30, 2015	Dec. 31, 2014
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity		$ 900,000,000	$ 900,000,000
Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate			0.70%
Line of Credit Facility maximum borrowing capacity		475,000,000	$ 475,000,000
Outstanding borrowings		0
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility maximum borrowing capacity		$ 150,000,000
Credit facility maturity date	Mar. 23, 2018
Credit Facility amendment date	Mar. 24, 2015
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member] | Before Amendment and Restatement
Line Of Credit Facility [Line Items]
Credit facility maturity date	Apr. 14, 2015
TECO Energy [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.28%	1.16%
TECO Finance [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.28%	1.16%
New Mexico Gas Company [Member]
Line Of Credit Facility [Line Items]
Weighted-average interest rate		1.28%	1.16%
Minimum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Maximum [Member] | Tampa Electric Company [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.30%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	May. 20, 2015	Apr. 10, 2015	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, carrying amount			$ 3,851	$ 3,628.5
Estimated fair value			4,126.1	3,987.8
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount			2,263.2	2,097.1
Estimated fair value			$ 2,466.3	$ 2,372.2
TECO Finance [Member] | Floating Rate Notes Due 2018 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$ 250
Net proceeds from offering		$ 248.6
Debt instrument, offering date		Apr. 10, 2015
Basis spread on federal funds rate		0.60%
Debt instrument maturity date		Apr. 10, 2018
Interest rate, description			The 2018 Notes will bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points, which is payable quarterly on Jan. 10, Apr. 10, July 10 and Oct. 10 of each year, beginning July 10, 2015.
The Notes | Tampa Electric Company [Member] | 4.20% Notes Due 2045 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 250
Interest at the initial term rate per annum	4.20%
Debt instrument principal amount market price percentage	99.814%
Net proceeds from offering	$ 246.8
Redeemable principal amount percentage	100.00%
Debt instrument, offering date	May 20, 2015
Debt instrument, start date of redemption	Nov. 15, 2044
Debt instrument, maturity year	2,045
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	0.20%
Debt instrument maturity date	May 15, 2045
The Notes | TECO Finance [Member] | Notes Due in May 2015 [Member]
Debt Instrument [Line Items]
Payment of notes		$ 191

Other Comprehensive Income - Ac

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Income) (Detail) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross		$ 0		$ (0.3)		$ 4.3		$ (0.3)
Reclassification from AOCI to net income, Gross	[1]	0.3		0.4		1		0.9
Gain on cash flow hedges, Gross		0.3		0.1		5.3		0.6
Amortization of unrecognized benefit costs, Gross	[2]	0.4		0.4		2.9		2.4
Increase in unrecognized postemployment costs, Gross	[3]			0				(12.9)
Change in benefit obligation due to valuation, Gross		(8.7)	[4]	(1.1)		(8.7)	[4]	(1.1)
Recognized cost due to settlement, Gross	[5]	12.1				12.1
Total other comprehensive income (loss), Gross		4.1		(0.6)		11.6		(11)
Unrealized gain (loss) on cash flow hedges, Tax		0		0.1		(1.5)		0.1
Reclassification from AOCI to net income, Tax	[1]	(0.1)		(0.1)		(0.5)		(0.3)
Gain on cash flow hedges, Tax		(0.1)		0		(2)		(0.2)
Amortization of unrecognized benefit costs, Tax	[2]	(0.2)		(0.2)		(1.1)		(0.8)
Increase in unrecognized postemployment costs, Tax	[3]			0				4.7
Change in benefit obligation due to valuation, Tax		3	[4]	0.4		3	[4]	0.4
Recognized cost due to settlement, Tax	[5]	(4.4)				(4.4)
Total other comprehensive income (loss), Tax		(1.7)		0.2		(4.5)		4.1
Unrealized gain (loss) on cash flow hedges, Net		0		(0.2)		2.8		(0.2)
Reclassification from AOCI to net income, Net	[1]	0.2		0.3		0.5		0.6
Gain on cash flow hedges, Net		0.2		0.1		3.3		0.4
Amortization of unrecognized benefit costs, Net	[2]	0.2		0.2		1.8		1.6
Increase in unrecognized postemployment costs		0		0	[3]	0		(8.2)	[3]
Change in benefit obligation due to valuation, Net		(5.7)	[4]	(0.7)		(5.7)	[4]	(0.7)
Recognized cost due to settlement, Net		7.7	[5]	0		7.7	[5]	0
Other comprehensive income (loss), net of tax		2.4		(0.4)		7.1		(6.9)
Unamortized pension loss and prior service credit	[6]	(25.8)				(25.8)				$ (22.5)
Unamortized other benefit gains, prior service costs and transition obligations	[7]	21				21				13.9
Net unrealized gains (losses) from cash flow hedges	[8]	(3.8)				(3.8)				(7.1)
Total accumulated other comprehensive loss		(8.6)				(8.6)				(15.7)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross		0		0		4.3		0
Reclassification from AOCI to net income, Gross		0.3		0.4		1		0.8
Gain on cash flow hedges, Gross		0.3		0.4		5.3		0.8
Total other comprehensive income (loss), Gross		0.3		0.4		5.3		0.8
Unrealized gain (loss) on cash flow hedges, Tax		0		0		(1.5)		0
Reclassification from AOCI to net income, Tax		(0.1)		(0.1)		(0.5)		(0.3)
Gain on cash flow hedges, Tax		(0.1)		(0.1)		(2)		(0.3)
Total other comprehensive income (loss), Tax		(0.1)		(0.1)		(2)		(0.3)
Unrealized gain (loss) on cash flow hedges, Net		0		0		2.8		0
Reclassification from AOCI to net income, Net		0.2		0.3		0.5		0.5
Gain on cash flow hedges, Net		0.2		0.3		3.3		0.5
Other comprehensive income (loss), net of tax		0.2		$ 0.3		3.3		$ 0.5
Net unrealized gains (losses) from cash flow hedges	[8]	(3.8)				(3.8)				(7.1)
Total accumulated other comprehensive loss		$ (3.8)				$ (3.8)				$ (7.1)
[1]	Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations.
[2]	Related to postretirement and postemployment benefits. See Note 5 for additional information.
[3]	Amounts reflect an out-of-period adjustment related to TECO Coal's unfunded black lung liability.
[4]	Related to the transfer of employees and their associated postretirement benefits from TEC to the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas the shared services company recognized them in AOCI.
[5]	Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Notes 5 and 15 for additional information.
[6]	Net of tax benefit of $16.2 million and $13.8 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.
[7]	Net of tax expense of $13.2 million and $8.3 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.
[8]	Net of tax benefit of $2.4 million and $4.5 million as of Sept. 30, 2015 and Dec. 31, 2014, respectively.

Other Comprehensive Income - 47

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 2.4	$ 4.5
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	2.4	4.5
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)	16.2	13.8
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)	$ 13.2	$ 8.3

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Basic earnings per share
Net income from continuing operations	$ 64.9	$ 73	$ 190.2	$ 179
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.6)	(0.6)
Income before discontinued operations available to common shareholders - Basic	64.7	72.8	189.6	178.4
Loss from discontinued operations, net	(11.7)	(61.9)	(67.2)	(59.4)
Amount allocated to nonvested participating shareholders	0	0	0	0
Loss from discontinued operations available to common shareholders - Basic	(11.7)	(61.9)	(67.2)	(59.4)
Net income	53.2	11.1	123	119.6
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.6)	(0.6)
Net income available to common shareholders - Basic	$ 53	$ 10.9	$ 122.4	$ 119
Average common shares outstanding - Basic	233.2	227.8	233	220.3
Earnings per share from continuing operations available to common shareholders - Basic	$ 0.28	$ 0.32	$ 0.81	$ 0.81
Earnings per share from discontinued operations available to common shareholders - Basic	(0.05)	(0.28)	(0.28)	(0.27)
Earnings per share - Basic	$ 0.23	$ 0.04	$ 0.53	$ 0.54
Diluted earnings per share
Net income from continuing operations	$ 64.9	$ 73	$ 190.2	$ 179
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.6)	(0.6)
Income before discontinued operations available to common shareholders - Diluted	64.7	72.8	189.6	178.4
Loss from discontinued operations, net	(11.7)	(61.9)	(67.2)	(59.4)
Amount allocated to nonvested participating shareholders	0	0	0	0
Loss from discontinued operations available to common shareholders - Diluted	(11.7)	(61.9)	(67.2)	(59.4)
Net income	53.2	11.1	123	119.6
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.6)	(0.6)
Net income available to common shareholders - Diluted	$ 53	$ 10.9	$ 122.4	$ 119
Average common shares outstanding - Basic	233.2	227.8	233	220.3
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net	1.5	0.5	1.4	0.5
Average common shares outstanding - Diluted	234.7	228.3	234.4	220.8
Earnings per share from continuing operations available to common shareholders - Diluted	$ 0.28	$ 0.32	$ 0.81	$ 0.81
Earnings per share from discontinued operations available to common shareholders - Diluted	(0.05)	(0.28)	(0.28)	(0.27)
Earnings per share - Diluted	$ 0.23	$ 0.04	$ 0.53	$ 0.54
Anti-dilutive shares	0	0	0	0

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Dec. 19, 2013USD ($)	Feb. 08, 2011CustomerLawsuitInsuranceCarrier	Sep. 30, 2015USD ($)Claims	Mar. 31, 2011Customer
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers | Customer				32,000
Number of claims dismissed | Claims			2
Number of lawsuits for insurance carriers | Lawsuit		2
Number of insurance carriers | InsuranceCarrier		18
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			$ 33.3
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Long Term Commitments [Line Items]
Litigation settlement amount	$ 7.5
Damages awarded	$ 21.1
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member] | U.S. prime rate plus [Member]
Long Term Commitments [Line Items]
Litigation settlement interest	2.00%
Gas Shortages [Member]
Long Term Commitments [Line Items]
Gas supply disruption of high utility customers | Customer		28,700

Commitments and Contingencies50

Commitments and Contingencies - Letters of Credit and Guarantees (Detail)	Sep. 30, 2015USD ($)
Tampa Electric Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2015	$ 0
Year of expiration 2016	0
Year of expiration 2017-2019	0
Year of expiration After 2019	500,000
Maximum Theoretical Obligation	500,000
Liabilities Recognized at June 30, 2015	100,000
Year of expiration 2016-2019	0
New Mexico Gas Company [Member] | Letters Of Credit [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2015	0
Year of expiration 2016	0
Year of expiration 2017-2019	0
Year of expiration After 2019	1,700,000
Maximum Theoretical Obligation	1,700,000
Liabilities Recognized at June 30, 2015	0
Fuel Sales and Transportation [Member]
Guarantee Obligations [Line Items]
Year of Expiration 2015	0
Year of expiration 2016	0
Year of expiration 2017-2019	0
Year of expiration After 2019	92,900,000
Maximum Theoretical Obligation	92,900,000
Liabilities Recognized at June 30, 2015	0
Letters of Indemnity - Coal Mining Permits
Guarantee Obligations [Line Items]
Year of Expiration 2015	0
Year of expiration 2016	93,800,000
Year of expiration 2017-2019	0
Year of expiration After 2019	0
Maximum Theoretical Obligation	93,800,000
Liabilities Recognized at June 30, 2015	$ 0

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 693.8	$ 687.2	$ 2,067.4	$ 1,870.9
Depreciation and amortization	87.8	78.6	260.3	230
Total interest charges	46.1	42.9	140.4	123.2
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	41.7	33.7	122.1	98
Net income from continuing operations	64.9	73	190.2	179
Income (loss) from discontinued operations, net	(11.7)	(61.9)	(67.2)	(59.4)
Net income	53.2	11.1	123	119.6
Total assets	8,816.9		8,816.9		$ 8,726.2
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	648.2	668.5	1,844.9	1,847.3
Depreciation and amortization	79	75.4	233.8	225.9
Total interest charges	27.8	27.3	82	79.4
Provision (benefit) for income taxes	53.5	51.5	133.8	129.2
Net income	88.3	84.5	226.4	214
Total assets	7,532.5		7,532.5		7,274.3
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(2.8)	(0.4)	(7)	(1.5)
Depreciation and amortization	0	0	0	0
Total interest charges	(0.3)	(1.4)	(1)	(3.7)
Internally allocated interest	(0.3)	(1.9)	(1)	(3.7)
Provision (benefit) for income taxes	0	0	0	0
Net income from continuing operations	0	0	0	0
Income (loss) from discontinued operations, net	0	0	0	0
Net income	0	0	0	0
Total assets	(6,094.6)		(6,094.6)		(1,998.5)
Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	(2.1)	(0.2)	(4.8)	(1)
Depreciation and amortization	0	0	0	0
Total interest charges	0	0	0	0
Provision (benefit) for income taxes	0	0	0	0
Net income	0	0	0	0
Total assets	(2.6)		(2.6)		(7.1)
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	693.8	687.2	2,067.4	1,870.9
Revenues - External [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	648.2	668.5	1,844.9	1,847.3
Revenues - External [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Revenues - External [Member] | Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Sales to Affiliates [Member] | Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(2.8)	(0.4)	(7)	(1.5)
Intracompany Sales [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Intracompany Sales [Member] | Eliminations [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	(2.1)	(0.2)	(4.8)	(1)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	560.2	581.8	1,543.2	1,547.7
Depreciation and amortization	64.6	61.8	191.5	185.6
Total interest charges	24.1	23.8	71.2	69.1
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	50	48.5	116.3	112.2
Net income from continuing operations	82.1	79.7	198	187.1
Income (loss) from discontinued operations, net	0	0	0	0
Net income	82.1	79.7	198	187.1
Total assets	6,804.2		6,804.2		6,565.4
Tampa Electric [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	560.2	581.8	1,543.2	1,547.7
Depreciation and amortization	64.6	61.8	191.5	185.6
Total interest charges	24.1	23.8	71.2	69.1
Provision (benefit) for income taxes	50	48.5	116.3	112.2
Net income	82.1	79.7	198	187.1
Total assets	6,469.5		6,469.5		6,234.4
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	559.4	581.5	1,540.8	1,546.9
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	560.1	581.6	1,542.9	1,547.3
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.8	0.3	2.4	0.8
Tampa Electric [Member] | Intracompany Sales [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0.1	0.2	0.3	0.4
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	90.1	86.9	306.5	300.6
Depreciation and amortization	14.4	13.6	42.3	40.3
Total interest charges	3.7	3.5	10.8	10.3
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	3.5	3	17.5	17
Net income from continuing operations	6.2	4.8	28.4	26.9
Income (loss) from discontinued operations, net	0	0	0	0
Net income	6.2	4.8	28.4	26.9
Total assets	1,099		1,099		1,082.8
PGS [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	90.1	86.9	306.5	300.6
Depreciation and amortization	14.4	13.6	42.3	40.3
Total interest charges	3.7	3.5	10.8	10.3
Provision (benefit) for income taxes	3.5	3	17.5	17
Net income	6.2	4.8	28.4	26.9
Total assets	1,065.6		1,065.6		1,047
PGS [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	88.1	86.9	302	300
PGS [Member] | Revenues - External [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	88.1	86.9	302	300
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	2	0	4.5	0.6
PGS [Member] | Intracompany Sales [Member] | Operating Segments [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	2	0	4.5	0.6
NMGC [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	43.7	16.2	216.7	16.2
Depreciation and amortization	8.5	2.8	25.3	2.8
Total interest charges	3.2	1.1	9.8	1.1
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	(1.9)	(0.5)	7.1	(0.5)
Net income from continuing operations	(2.8)	(0.9)	11	(0.9)
Income (loss) from discontinued operations, net	0	0	0	0
Net income	(2.8)	(0.9)	11	(0.9)
Total assets	1,188.7		1,188.7		1,237.2
NMGC [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	43.7	16.2	216.7	16.2
NMGC [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Depreciation and amortization	0	0	0	0
Total interest charges	0	0	0	0
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	0	0	0	0
Net income from continuing operations	0	0	0	0
Income (loss) from discontinued operations, net	(12.1)	(64.8)	(69.6)	(65.6)
Net income	(12.1)	(64.8)	(69.6)	(65.6)
Total assets	0		0		227.7
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	0	0	0	0
Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.6	2.7	8	7.9
Depreciation and amortization	0.3	0.4	1.2	1.3
Total interest charges	15.4	15.9	49.6	46.4
Internally allocated interest	0.3	1.9	1	3.7
Provision (benefit) for income taxes	(9.9)	(17.3)	(18.8)	(30.7)
Net income from continuing operations	(20.6)	(10.6)	(47.2)	(34.1)
Income (loss) from discontinued operations, net	0.4	2.9	2.4	6.2
Net income	(20.2)	(7.7)	(44.8)	(27.9)
Total assets	5,819.6		5,819.6		$ 1,611.6
Other [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2.6	2.6	7.9	7.8
Other [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates/Intracompany sales	$ 0	$ 0.1	$ 0.1	$ 0.1

Accounting for Derivative Ins52

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative assets	$ 200,000	$ 0
Derivative liabilities	26,600,000	42,700,000
Cash collateral posted with or received from any counterparties	0	0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities	(23,700,000)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets	0	0
Derivative liabilities	26,600,000	42,700,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities	$ (23,900,000)
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2017
Natural Gas Contracts [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Sep. 30, 2017

Accounting for Derivative Ins53

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) - Natural Gas Contracts [Member] MMBTU in Millions	Sep. 30, 2015MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	53.5
Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	39.9
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	13.5
2015 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8.6
2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2016 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35.8
2016 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	27.1
2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2017 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4.2
2017 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4.2

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 0.2	$ 0
Natural gas derivative liabilities	26.6	42.7
Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0	0
Natural gas derivative liabilities	26.6	42.7
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0.2
Natural gas derivative liabilities	26.6	42.7
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	26.6	42.7
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0
Natural gas derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 1 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0.2
Natural gas derivative liabilities	26.6	42.7
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 2 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	26.6	42.7
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0
Natural gas derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member] | Level 3 [Member] | Tampa Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 0	$ 0

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)MW	Sep. 30, 2014USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$ 23.8	$ 21	$ 60.5	$ 59.1
Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	23.8	21	60.5	59.1
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	10.7	8.1	26	20.9
Power Purchase Agreements [Member] | Variable Interest Entities [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$ 10.7	$ 8.1	$ 26	$ 20.9
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			117
Minimum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			117
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			157
Maximum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW			157

Discontinued Operations and A56

Discontinued Operations and Asset Impairments - Additional Information (Detail) - TECO Coal [Member] - USD ($) $ in Millions	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2014	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Sep. 21, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Contingent Payments								$ 60
Loss on sale, pretax	$ (10)		$ 0		$ (10)	$ 0
Settlement charge, related to unfunded black lung obligations					$ 7.7
Transaction costs, pretax				$ 12.3
Legal and other consultant costs				2.5
Severance and other employee costs				$ 9.8
Total pretax impairment charges		$ 78.6					$ 115.9

Discontinued Operations and A57

Discontinued Operations and Asset Impairments - Carrying Amount of Assets and Liabilities Held for Sale (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets	$ 0	$ 109.6
Property, plant and equipment, net and other long-term assets	0	59.8
Current liabilities	0	39.4
Long-term liabilities	0	65.4
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Current assets	0	109.6
Property, plant and equipment, net and other long-term assets	0	59.8
Total assets held for sale	0	169.4
Current liabilities	0	39.4
Long-term liabilities	0	65.4
Total liabilities associated with assets held for sale	$ 0	$ 104.8

Discontinued Operations and A58

Discontinued Operations and Asset Impairments - Components of Discontinued Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from operations	$ (7.4)	$ (0.4)	$ (16.4)	$ (4.2)
Loss from discontinued operations	(17.8)	(98.8)	(105.5)	(97.6)
Benefit from income taxes	(6.1)	(36.9)	(38.3)	(38.2)
Loss on discontinued operations, net	(11.7)	(61.9)	(67.2)	(59.4)
TECO Coal [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues	51.6	101.6	200.4	328.3
Loss on sale	(10)	0	(10)	0
Loss on impairment	0	(98.4)	(78.6)	(98.4)
Loss from discontinued operations	(17.4)	(98.8)	(105)	(102.6)
TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss from operations	(0.4)	0	(0.5)	5
Loss from discontinued operations	(0.4)	0	(0.5)	5
TECO Coal and TECO Guatemala [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Benefit from income taxes	$ (6.1)	$ (36.9)	$ (38.3)	$ (38.2)

Mergers and Acquisitions - Addi

Mergers and Acquisitions - Additional Information (Detail) - USD ($)	Sep. 04, 2015	Sep. 02, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Business Acquisition [Line Items]
Termination fee payable by company	$ 212,500,000
Business combination transaction related costs			$ 15,400,000
Obligations associated with severance benefits costs			300,000		$ 300,000		$ 2,600,000
Tampa Electric Company [Member]
Business Acquisition [Line Items]
Termination fee payable by company	$ 212,500,000
Emera Inc. [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Emera Inc. [Member] | Tampa Electric Company [Member]
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding	$ 27.55
Aggregate purchase price	$ 10,400,000,000
Senior secured notes	$ 3,900,000,000
Merger agreement termination extension regulatory approval period	6 months
Termination fee payable by acquirer	$ 326,900,000
Senior secured notes	$ 2,300,000,000
NMGI [Member]
Business Acquisition [Line Items]
Aggregate purchase price		$ 950,000,000
Business combination transaction related costs			200,000	$ 900,000	1,200,000	$ 5,700,000
Business acquisition, effective date		Sep. 2, 2014
After-tax non-recurring acquisition consummation, integration and other costs				900,000		5,700,000
New Mexico Gas Company [Member]
Business Acquisition [Line Items]
Senior secured notes		$ 200,000,000
NMGI and NMGC [Member]
Business Acquisition [Line Items]
Revenue			43,700,000	16,200,000	216,700,000	16,200,000
Net income			$ (3,900,000)	$ (2,000,000)	$ 7,600,000	$ (2,000,000)

Mergers and Acquisitions - Pro

Mergers and Acquisitions - Pro Forma Earning (Detail) - NMGI [Member] - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Business Acquisition Pro Forma Information Nonrecurring Adjustment [Line Items]
Revenues	$ 720	$ 2,111
Net income from continuing operations	$ 70.8	$ 199.3
Basic and Diluted EPS from continuing operations	$ 0.31	$ 0.86

Mergers and Acquisitions - Afte

Mergers and Acquisitions - After-tax Transaction and Integration Charges Recognized Upon Closing of Acquisition and Included Consolidated Statements of Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Business Acquisition [Line Items]
Total accounting charges	$ 15.4
NMGI [Member]
Business Acquisition [Line Items]
Legal and other consultants	0.1	$ 5.3	$ 0.4	$ 7.2
Bridge loan costs	0	0.4	0	2.9
Severance and relocation costs	0	1.7	0.5	1.7
Other costs and tax benefit	0.1	(6.5)	0.3	(6.1)
Total accounting charges	$ 0.2	$ 0.9	$ 1.2	$ 5.7