Tampa Electric 10-Q 13 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 08, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Trading Symbol	ck0000096271
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, 2017	Dec. 31, 2016
Property, plant and equipment
Utility plant, at original costs	$ 10,295	$ 10,019
Construction work in progress	271	892
Accumulated depreciation	(2,967)	(2,826)
Utility plant, net	7,328	7,193
Other property	11	10
Total property, plant and equipment, net	7,339	7,203
Current assets
Cash and cash equivalents	18	10
Receivables, less allowance for uncollectibles of $1 at both September 30, 2017 and December 31, 2016	283	206
Due from affiliates	2	7
Inventories, at average cost
Derivative assets	0	15
Regulatory assets	38	28
Prepayments and other current assets	18	21
Total current assets	530	450
Deferred debits
Regulatory assets	397	393
Other	40	37
Total deferred debits	437	430
Total assets	8,306	8,083
Capitalization
Common stock	2,554	2,456
Accumulated other comprehensive loss	(2)	(3)
Retained earnings	373	311
Total capital	2,925	2,764
Long-term debt	1,859	2,163
Total capitalization	4,784	4,927
Current liabilities
Long-term debt due within one year	304	0
Notes payable	255	170
Accounts payable	226	262
Due to affiliates	13	25
Customer deposits	131	146
Regulatory liabilities	65	154
Accrued interest	41	16
Accrued taxes	66	12
Other	10	11
Total current liabilities	1,111	796
Deferred credits
Deferred income taxes	1,539	1,407
Investment tax credits	22	11
Regulatory liabilities	516	591
Deferred credits and other liabilities	334	351
Total deferred credits	2,411	2,360
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	8,306	8,083
Fuel [Member]
Inventories, at average cost
Utility inventories	77	77
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	94	86
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	8,444	7,624
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,580	$ 1,503

Consolidated Condensed Balance3

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 1	$ 1

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues
Electric	$ 597	$ 586	$ 1,581	$ 1,509
Gas	96	103	309	330
Total revenues	693	689	1,890	1,839
Expenses
Fuel	158	173	454	426
Purchased power	21	39	36	81
Cost of natural gas sold	44	40	115	126
Operations and maintenance	127	134	386	388
Depreciation and amortization	89	83	262	245
Taxes, other than income	53	53	151	149
Total expenses	492	522	1,404	1,415
Income from operations	201	167	486	424
Other income
Allowance for equity funds used during construction	0	6	1	18
Other income, net	2	2	6	4
Total other income	2	8	7	22
Interest charges
Interest on long-term debt	27	28	83	85
Other interest	3	2	7	4
Allowance for borrowed funds used during construction	0	(4)	(1)	(9)
Total interest charges	30	26	89	80
Income before provision for income taxes	173	149	404	366
Provision for income taxes	67	49	156	127
Net income	106	100	248	239
Other comprehensive income, net of tax
Gain on cash flow hedges	0	1	1	1
Total other comprehensive income, net of tax	0	1	1	1
Comprehensive income	$ 106	$ 101	$ 249	$ 240

Consolidated Condensed Stateme5

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities
Net income	$ 248	$ 239
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	262	245
Deferred income taxes and investment tax credits	151	70
Allowance for equity funds used during construction	(1)	(18)
Deferred recovery clauses	(73)	54
Receivables, less allowance for uncollectibles	(70)	(25)
Inventories	(8)	18
Taxes accrued	45	123
Interest accrued	25	23
Accounts payable	(20)	19
Regulatory assets and liabilities	(67)	(6)
Other	(30)	(40)
Cash flows from operating activities	462	702
Cash flows from investing activities
Capital expenditures	(451)	(518)
Net proceeds from sale of assets	0	9
Cash flows used in investing activities	(451)	(509)
Cash flows from financing activities
Equity contributions	98	90
Repayment of long-term debt	0	(83)
Net increase (decrease) in short-term debt	85	(12)
Dividends	(185)	(182)
Other financing activities	(1)	0
Cash flows used in financing activities	(3)	(187)
Net increase in cash and cash equivalents	8	6
Cash and cash equivalents at beginning of period	10	9
Cash and cash equivalents at end of period	18	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (25)	$ (20)

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TEC’s Annual Report on Form 10-K for the year ended December 31, 2016 for a complete discussion of accounting policies. The significant accounting policies for TEC include: Principles of Consolidation and Basis of Presentation For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. Intercompany balances and transactions within the divisions 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 September 30, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017. 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. TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. Revenues As of September 30, 2017 and December 31, 2016, unbilled revenues of $71 million and $54 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 rates 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 million and $86 million for the three and nine months ended September 30, 2017, respectively, and $33 million and $89 million for the three and nine months ended September 30, 2016, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2017
Accounting Changes And Error Corrections [Abstract]
New Accounting Pronouncements	2. New Accounting Pronouncements Future Accounting Pronouncements TEC considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the FASB. The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2016, with the exception of the items noted below. Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers TEC implemented a revenue recognition project plan in 2016. In the first quarter of 2017, TEC concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In the second quarter of 2017, TEC completed an analysis of material regulated revenue streams and collectibility risk and concluded that there will be no material changes on adoption of this standard. In the third quarter of 2017, TEC evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on TEC’s information gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by TEC for financial reporting purposes. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities Leases In February 2016, the FASB issued ASU 2016-02, Leases Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities

Regulatory

Regulatory	9 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Regulatory	3. Regulatory Tampa Electric Base Rates-2013 Agreement Tampa Electric’s results reflect the stipulation and settlement agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement. This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provided that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software beginning on January 1, 2013. Tampa Electric Base Rates-2017 Agreement On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaces the existing 2013 base rate settlement agreement discussed above and extends it another four years through 2021. The FPSC approved the agreement on November 6, 2017. The amended agreement provides for solar base rate adjustments (SoBRAs) for TEC’s substantial investments in solar generation. It includes the following SoBRAs: $31 million for 150 MWs effective September 1, 2018, $51 million for 250 MWs effective January 1, 2019, $31 million for 150 MWs effective January 1, 2020, and an additional $10 million for 50 MWs effective on January 1, 2021. In order for each tranche of SoBRA to take effect, Tampa Electric must show they are cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to build the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1475/kWac. The agreement includes a sharing provision that allows Tampa Electric to retain 25% of any cost savings for projects below $1500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects over four years and will accrue AFUDC during construction. The agreement maintains Tampa Electric’s allowed regulatory ROE at a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2022, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure remains at 54%. The agreement contains certain customer protections related to potential changes in federal tax policy. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are crossed is also included and Tampa Electric agrees to a five-year financial hedging moratorium for natural gas and no investments in gas reserves. Tampa Electric Storm Restoration Cost Recovery Prior to the September 6, 2013 stipulation and settlement agreement, Tampa Electric was accruing $8 million annually to an FPSC-approved self-insured storm reserve. Effective November 1, 2013, Tampa Electric ceased accruing for this storm reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. As of December 31, 2016, the balance of the self-insured storm reserve was $56 million. As a result of several named storms, including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $10 million of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million of storm costs to the storm reserve. This resulted in a storm reserve balance of $46 million as of March 31, 2017. Tampa Electric was impacted by Hurricane Irma in the third quarter of 2017 and has currently estimated the total incurred incremental cost of restoration to be approximately $70 million, of which $60 million was charged to the storm reserve, $4 million was charged to O&M expense, and $6 million was charged to capital expenditures. At September 30, 2017, the amount of $60 million charged to the storm reserve exceeded the $46 million balance by $14 million, which is currently recorded as a regulatory asset on the balance sheet. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory asset. Tampa Electric expects to petition the FPSC in early 2018 for recovery of the storm costs in excess of the reserve as well as replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of $70 million. See the Regulatory Assets and Liabilities table below. PGS Base Rates On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The settlement agreement provided that the bottom of the ROE range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the ROE range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement. As part of the settlement, PGS and OPC agreed Regulatory Assets and Liabilities Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Areas of applicability include: 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 restoration or the future removal of property. Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) September 30, 2017 December 31, 2016 Regulatory assets: Regulatory tax asset (1) $ 83 $ 86 Cost-recovery clauses - deferred balances (2) 7 8 Environmental remediation (3) 33 37 Postretirement benefits (4) 276 272 Storm reserve (5) 14 0 Other 22 18 Total regulatory assets 435 421 Less: Current portion 38 28 Long-term regulatory assets $ 397 $ 393 Regulatory liabilities: Regulatory tax liability $ 12 $ 6 Cost-recovery clauses - deferred balances (2) 38 112 Cost-recovery clauses - offsets to derivative assets (2) 0 17 Storm reserve (5) 0 56 Accumulated reserve - cost of removal (6) 524 547 Other 7 7 Total regulatory liabilities 581 745 Less: Current portion 65 154 Long-term regulatory liabilities $ 516 $ 591 (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 the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory liability related to derivative assets, refund occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at MGP 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 based on a settlement agreement approved by the FPSC. (4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (5) See Tampa Electric Storm Restoration Cost Recovery above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered over a 12-month period. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	4. Income Taxes Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. Prior to the Merger, TEC was included in the filing of a consolidated federal income tax return with TECO Energy and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements of TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2014 and forward. The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able to participate in the CAP through its short tax year ending June 30, 2016. TEC’s effective tax rates for the three months ended September 30, 2017 and 2016 were 38.73% and 32.53%, respectively. TEC’s effective tax rates for the nine months ended September 30, 2017 and 2016 were 38.61% and 34.59%, respectively. The increase in the three-month and nine-month effective tax rates in 2017 versus the same period in 2016 is primarily due to lower AFUDC-equity, production deduction and R&D tax credit tax benefits. TEC’s effective tax rate for the nine months ended September 30, 2017 differs from the statutory rate principally due to state income taxes. TEC’s effective tax rate for the nine months ended September 30, 2016 differs from the statutory rate principally due to state income taxes offset by tax benefits related to AFUDC-equity, production deduction and R&D tax credits. As of September 30, 2017, the amount of unrecognized tax benefits was $7 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC believes that the total unrecognized tax benefits will decrease and be recognized within the next twelve months due to the ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $7 million of unrecognized tax benefits at September 30, 2017, that, if recognized, would reduce TEC’s effective tax rate.

Employee Postretirement Benefit

Employee Postretirement Benefits	9 Months Ended
	Sep. 30, 2017
Compensation And Retirement Disclosure [Abstract]
Employee Postretirement Benefits	5. Employee Postretirement Benefits TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic benefit cost for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP. TECO Energy Benefit Cost (millions) Pension Benefits Other Postretirement Benefits Three months ended September 30, 2017 2016 2017 2016 Components of net periodic benefit cost Service cost $ 5 $ 5 $ 0 $ 1 Interest cost 8 7 2 2 Expected return on assets (12 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 (1 ) Actuarial (gain) loss 4 5 (1 ) 0 Net periodic benefit cost $ 5 $ 5 $ 1 $ 2 Nine months ended September 30, Components of net periodic benefit cost Service cost $ 15 $ 14 $ 1 $ 1 Interest cost 24 23 6 6 Expected return on assets (36 ) (34 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 (2 ) Actuarial (gain) loss 12 12 (2 ) 0 Curtailment cost 0 1 0 0 Settlement cost 7 (1) 1 0 0 Net periodic benefit cost $ 22 $ 17 $ 5 $ 5 (1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements. TEC’s portion of the net periodic benefit cost for the three months ended September 30, 2017 and 2016, respectively, was $3 million and $4 million for pension benefits, and $1 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the nine months ended September 30, 2017 and 2016, respectively, was $10 million for each period for pension benefits, and $4 million and $5 million for other postretirement benefits. For 2017, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.16% for pension benefits under its qualified pension plan. For the January 1, 2017 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.28%. TECO Energy made contributions of $46 million and $37 million to its qualified pension plan in the nine months ended September 30, 2017 and 2016, respectively. TEC’s portion of these contributions was $36 million and $31 million, respectively. Included in the benefit cost discussed above, for the three and nine months ended September 30, 2017, TEC reclassified $3 million and $8 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses from regulatory assets to net income, compared with $3 million and $8 million for the three and nine months ended September 30, 2016, respectively.

Short-Term Debt

Short-Term Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Short-Term Debt	6. Short-Term Debt Details of the credit facilities and related borrowings are presented in the following table: September 30, 2017 December 31, 2016 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 $ 170 $ 1 $ 325 $ 40 $ 1 3-year accounts receivable facility (3) 150 85 0 150 130 0 Total $ 475 $ 255 $ 1 $ 475 $ 170 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 23, 2018. At September 30, 2017, 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 September 30, 2017 and December 31, 2016 was 2.07% and 1.49%, respectively. Tampa Electric Company Credit Facilities On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); (ii) included a $50 million letter of credit facility; and (iii) made other technical changes. On November 2, 2017, TEC entered into a 364-day, $300 million credit agreement with a maturity date of November 1, 2018. See Note 13

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At September 30, 2017, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,377 million. At December 31, 2016, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,345 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities determined using Level 1 measurements was $56 million and $58 million at September 30, 2017 and December 31, 2016, respectively. The fair value of the remaining debt securities is determined using Level 2 measurements Note 11

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
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. TEC believes the final disposition of these proceedings will not have a material effect on its results of operations, cash flows or financial position. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of September 30, 2017, TEC has estimated its ultimate financial liability to be $30 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 are expected to be paid over many years. 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 currently assessed 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. See Note 3 Long-Term Commitments TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment, heavy equipment, other purchase obligations, long-term service agreements and capital projects. In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at September 30, 2017: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2017 $ 3 $ 1 $ 38 $ 124 $ 166 2018 10 3 173 282 468 2019 0 2 74 187 263 2020 0 2 7 163 172 2021 0 2 7 133 142 Thereafter 0 38 29 1,159 1,226 Total future minimum payments $ 13 $ 48 $ 328 $ 2,048 $ 2,437 Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements and has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2017, TEC was in compliance with all required financial covenants.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information	9. Segment Information (millions) Tampa Tampa Electric Three months ended September 30, Electric PGS Eliminations Company 2017 Revenues - external $ 597 $ 96 $ 0 $ 693 Intracompany sales 1 14 (15 ) 0 Total revenues 598 110 (15 ) 693 Total interest charges 26 4 0 30 Net income $ 98 $ 8 $ 0 $ 106 2016 Revenues - external $ 586 $ 103 $ 0 $ 689 Intracompany sales 0 1 (1 ) 0 Total revenues 586 104 (1 ) 689 Total interest charges 22 4 0 26 Net income $ 94 $ 6 $ 0 $ 100 Nine months ended September 30, 2017 Revenues - external $ 1,581 $ 309 $ 0 $ 1,890 Intracompany sales 2 17 (19 ) 0 Total revenues 1,583 326 (19 ) 1,890 Total interest charges 78 11 0 89 Net income $ 217 $ 31 $ 0 $ 248 2016 Revenues - external $ 1,509 $ 330 $ 0 $ 1,839 Intracompany sales 1 7 (8 ) 0 Total revenues 1,510 337 (8 ) 1,839 Total interest charges 69 11 0 80 Net income $ 213 $ 26 $ 0 $ 239 Total assets at September 30, 2017 $ 7,544 $ 1,253 $ (491 ) (1) $ 8,306 Total assets at December 31, 2016 $ 7,357 $ 1,191 $ (465 ) (1) $ 8,083 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 customers. 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. In November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. In September 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement, which replaces the existing 2013 base rate settlement agreement and includes a provision for a five-year moratorium on hedging of natural gas purchases. The FPSC approved the agreement on November 6, 2017 (see Note 3 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 September 30, 2017, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. The derivatives that are designated as cash flow hedges at September 30, 2017 and December 31, 2016 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. There were approximately zero derivative assets and liabilities as of September 30, 2017 and $17 million of derivative assets as of December 31, 2016. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties at September 30, 2017 and December 31, 2016. All of the derivative asset and liabilities at September 30, 2017 and December 31, 2016 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at September 30, 2017, there are no net pre-tax reductions in fuel costs that are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. 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 September 30, 2017 and 2016, 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 September 30, 2017 and 2016 is $1 million or less for each period. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense. The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to November 30, 2018 for financial natural gas contracts. Due to low hedging volumes and low natural gas price volatility, TEC’s financial natural gas contracts resulted in zero derivative assets and liabilities as of September 30, 2017. The following table presents TEC’s derivative volumes that, as of September 30, 2017, are expected to settle during the 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2017 0 3 2018 0 7 Total 0 10 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 September 30, 2017, 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 standardized master arrangements in the electric and gas industry. 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, 2017
Fair Value Disclosures [Abstract]
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 a basis for considering assumptions that market participants would use in pricing an asset or liability, 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. 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. Recurring Derivative Fair Value Measures As of September 30, 2017 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 0 $ 0 $ 0 As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 17 $ 0 $ 17 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. As of September 30, 2017, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented. As of September 30, 2017 and December 31, 2016, the carrying value of TEC’s short-term debt was not materially different from the fair value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value of TEC’s short-term debt is determined using Level 2 measurements. See Note 7

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Variable Interest Entities	12. Variable Interest Entities A VIE is an entity that a company has a controlling financial interest in, and that controlling interest is determined through means other than a majority voting interest. The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $5 million and $13 million under these PPAs for the three and nine months ended September 30, 2017, respectively, and $19 million and $48 million for the three and nine months ended September 30, 2016, 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.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2017
Subsequent Events [Abstract]
Subsequent Events	13. Subsequent Events On November 2, 2017, TEC entered into a 364-day, $300 million credit agreement with a consortium of banks. The credit agreement has a maturity date of November 1, 2018; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. Intercompany balances and transactions within the divisions 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 September 30, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017. 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. TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.
Revenues	Revenues As of September 30, 2017 and December 31, 2016, unbilled revenues of $71 million and $54 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipts	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 rates 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 million and $86 million for the three and nine months ended September 30, 2017, respectively, and $33 million and $89 million for the three and nine months ended September 30, 2016, respectively.

Regulatory (Tables)

Regulatory (Tables)	9 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) September 30, 2017 December 31, 2016 Regulatory assets: Regulatory tax asset (1) $ 83 $ 86 Cost-recovery clauses - deferred balances (2) 7 8 Environmental remediation (3) 33 37 Postretirement benefits (4) 276 272 Storm reserve (5) 14 0 Other 22 18 Total regulatory assets 435 421 Less: Current portion 38 28 Long-term regulatory assets $ 397 $ 393 Regulatory liabilities: Regulatory tax liability $ 12 $ 6 Cost-recovery clauses - deferred balances (2) 38 112 Cost-recovery clauses - offsets to derivative assets (2) 0 17 Storm reserve (5) 0 56 Accumulated reserve - cost of removal (6) 524 547 Other 7 7 Total regulatory liabilities 581 745 Less: Current portion 65 154 Long-term regulatory liabilities $ 516 $ 591 (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 the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory liability related to derivative assets, refund occurs in the year following the settlement of the derivative position. (3) This asset is related to costs associated with environmental remediation primarily at MGP 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 based on a settlement agreement approved by the FPSC. (4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (5) See Tampa Electric Storm Restoration Cost Recovery above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered over a 12-month period. (6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

Employee Postretirement Benef21

Employee Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2017
Compensation And Retirement Disclosure [Abstract]
Schedule of Net Periodic Benefit Cost	The following table presents detail related to TECO Energy’s periodic benefit cost for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP. TECO Energy Benefit Cost (millions) Pension Benefits Other Postretirement Benefits Three months ended September 30, 2017 2016 2017 2016 Components of net periodic benefit cost Service cost $ 5 $ 5 $ 0 $ 1 Interest cost 8 7 2 2 Expected return on assets (12 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 (1 ) Actuarial (gain) loss 4 5 (1 ) 0 Net periodic benefit cost $ 5 $ 5 $ 1 $ 2 Nine months ended September 30, Components of net periodic benefit cost Service cost $ 15 $ 14 $ 1 $ 1 Interest cost 24 23 6 6 Expected return on assets (36 ) (34 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 (2 ) Actuarial (gain) loss 12 12 (2 ) 0 Curtailment cost 0 1 0 0 Settlement cost 7 (1) 1 0 0 Net periodic benefit cost $ 22 $ 17 $ 5 $ 5 (1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Short-Term Debt Credit Facilities and Related Borrowings	Details of the credit facilities and related borrowings are presented in the following table: September 30, 2017 December 31, 2016 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 $ 170 $ 1 $ 325 $ 40 $ 1 3-year accounts receivable facility (3) 150 85 0 150 130 0 Total $ 475 $ 255 $ 1 $ 475 $ 170 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 23, 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Schedule of Long-term Commitments	The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at September 30, 2017: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2017 $ 3 $ 1 $ 38 $ 124 $ 166 2018 10 3 173 282 468 2019 0 2 74 187 263 2020 0 2 7 163 172 2021 0 2 7 133 142 Thereafter 0 38 29 1,159 1,226 Total future minimum payments $ 13 $ 48 $ 328 $ 2,048 $ 2,437

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Schedule of Segment Information	(millions) Tampa Tampa Electric Three months ended September 30, Electric PGS Eliminations Company 2017 Revenues - external $ 597 $ 96 $ 0 $ 693 Intracompany sales 1 14 (15 ) 0 Total revenues 598 110 (15 ) 693 Total interest charges 26 4 0 30 Net income $ 98 $ 8 $ 0 $ 106 2016 Revenues - external $ 586 $ 103 $ 0 $ 689 Intracompany sales 0 1 (1 ) 0 Total revenues 586 104 (1 ) 689 Total interest charges 22 4 0 26 Net income $ 94 $ 6 $ 0 $ 100 Nine months ended September 30, 2017 Revenues - external $ 1,581 $ 309 $ 0 $ 1,890 Intracompany sales 2 17 (19 ) 0 Total revenues 1,583 326 (19 ) 1,890 Total interest charges 78 11 0 89 Net income $ 217 $ 31 $ 0 $ 248 2016 Revenues - external $ 1,509 $ 330 $ 0 $ 1,839 Intracompany sales 1 7 (8 ) 0 Total revenues 1,510 337 (8 ) 1,839 Total interest charges 69 11 0 80 Net income $ 213 $ 26 $ 0 $ 239 Total assets at September 30, 2017 $ 7,544 $ 1,253 $ (491 ) (1) $ 8,306 Total assets at December 31, 2016 $ 7,357 $ 1,191 $ (465 ) (1) $ 8,083 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Accounting for Derivative Ins25

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Volumes Expected to Settle	The following table presents TEC’s derivative volumes that, as of September 30, 2017, are expected to settle during the 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2017 0 3 2018 0 7 Total 0 10

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Schedule of Recurring Fair Value Measurements	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. Recurring Derivative Fair Value Measures As of September 30, 2017 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 0 $ 0 $ 0 As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 17 $ 0 $ 17

Summary of Significant Accoun27

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Accounting Policies [Abstract]
Unbilled revenues	$ 71		$ 71		$ 54
Franchise fees and gross receipts taxes	$ 31	$ 33	$ 86	$ 89

Regulatory - Additional Informa

Regulatory - Additional Information (Detail)

Sep. 27, 2017USD ($)$ / kWacMW

Dec. 15, 2016USD ($)

Jun. 28, 2016

Sep. 30, 2017USD ($)

Nov. 30, 2016

Sep. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Sep. 30, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2013

Oct. 31, 2013USD ($)

Sep. 05, 2013USD ($)

Public Utilities General Disclosures [Line Items]

Percentage of ROE

10.25%

Return on equity range

Range of plus or minus 1%

Potential increase in ROE

10.50%

Allowed equity in the capital structure

54.00%

Storm costs incurred

$ 10,000,000

$ 10,000,000

$ 10,000,000

Storm costs applied to storm reserve

$ 10,000,000

Storm damage reserve

$ 46,000,000

$ 56,000,000

Regulatory assets

435,000,000

435,000,000

$ 435,000,000

$ 421,000,000

PGS and OPC [Member]

Public Utilities General Disclosures [Line Items]

Settlement agreement, approval date

Feb. 7, 2017

Regulatory assets

$ 32,000,000

32,000,000

$ 32,000,000

Reduction in annual depreciation expense

$ 16,000,000

Date new bottom of return on equity range will remain in effect

Dec. 31, 2020

Amortization expenses

1,000,000

$ 4,000,000

16,000,000

Regulatory asset amortization beginning period

2,016

Regulatory asset amortization ending period

2,020

PGS and OPC [Member] | Maximum [Member]

Public Utilities General Disclosures [Line Items]

Decrease bottom return on equity

9.75%

PGS and OPC [Member] | Minimum [Member]

Public Utilities General Disclosures [Line Items]

Amortization period of Regulatory Asset

2 years

Decrease bottom return on equity

9.25%

Amortization expenses

$ 21,000,000

PGS [Member]

Public Utilities General Disclosures [Line Items]

Percentage of ROE

10.75%

PGS [Member] | Maximum [Member]

Public Utilities General Disclosures [Line Items]

Return on equity

11.75%

Hurricane Irma [Member]

Public Utilities General Disclosures [Line Items]

Incremental storm restoration costs incurred

70,000,000

Hurricane Irma [Member] | Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Incremental storm restoration costs incurred

60,000,000

Hurricane Irma [Member] | O&M Expenses [Member]

Public Utilities General Disclosures [Line Items]

Incremental storm restoration costs incurred

4,000,000

Hurricane Irma [Member] | Capital Expenditures [Member]

Public Utilities General Disclosures [Line Items]

Incremental storm restoration costs incurred

6,000,000

Natural Gas [Member]

Public Utilities General Disclosures [Line Items]

Financial hedging moratorium period

5 years

1 year

Solar Project Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

Percentage of ROE

10.25%

Return on equity range

range of plus or minus 1%

Potential increase in ROE

10.50%

Allowed equity in the capital structure

54.00%

Settlement agreement, extended terms

four years through 2021

Settlement agreement, approval date

Nov. 6, 2017

Cost cap of project | $ / kWac

1,500

Cost savings retention percentage for projects below cost cap

25.00%

Solar generation capacity investments

$ 850,000,000

Solar project investment term

4 years

Investments in gas reserves

$ 0

Solar Project Cost Recovery [Member] | Natural Gas [Member]

Public Utilities General Disclosures [Line Items]

Financial hedging moratorium period

5 years

Solar Project Cost Recovery [Member] | Effective September 1, 2018 [Member]

Public Utilities General Disclosures [Line Items]

Solar base rate adjustments

$ 31,000,000

Solar energy capacity | MW

150

Solar Project Cost Recovery [Member] | Effective January 1, 2019 [Member]

Public Utilities General Disclosures [Line Items]

Solar base rate adjustments

$ 51,000,000

Solar energy capacity | MW

250

Solar Project Cost Recovery [Member] | Effective January 1, 2020 [Member]

Public Utilities General Disclosures [Line Items]

Solar base rate adjustments

$ 31,000,000

Solar energy capacity | MW

150

Solar Project Cost Recovery [Member] | Effective January 1, 2021 [Member]

Public Utilities General Disclosures [Line Items]

Solar base rate adjustments

$ 10,000,000

Solar energy capacity | MW

50

Solar Project Cost Recovery [Member] | First Two Tranches [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

400

Maximum cost to be constructed to build last tranche | $ / kWac

1,475

Storm Restoration Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

Annual accrual, storm damage reserve

$ 8,000,000

Minimum cost recovery period

12 months

Replenishment reserve for recovery of cost

$ 56,000,000

Self-insured storm reserve

56,000,000

Recovery cost in excess of reserve and replenishment of self-insured storm reserve

$ 70,000,000

70,000,000

$ 70,000,000

Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Regulatory assets

14,000,000

14,000,000

14,000,000

$ 0

November 1, 2013 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

58,000,000

58,000,000

58,000,000

November 1, 2014 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

8,000,000

8,000,000

8,000,000

November 1, 2015 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

5,000,000

5,000,000

5,000,000

January 16, 2017 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

$ 110,000,000

$ 110,000,000

$ 110,000,000

Condition One [Member]

Public Utilities General Disclosures [Line Items]

ROE upper range limit

11.25%

ROE lower range limit

9.25%

Condition One [Member] | Solar Project Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

ROE upper range limit

11.25%

ROE lower range limit

9.25%

Condition Two [Member]

Public Utilities General Disclosures [Line Items]

ROE upper range limit

11.50%

ROE lower range limit

9.50%

Condition Two [Member] | Solar Project Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

ROE upper range limit

11.50%

ROE lower range limit

9.50%

Computer Software [Member]

Public Utilities General Disclosures [Line Items]

Amortization period of Regulatory Asset

15 years

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Regulatory assets:
Regulatory assets	$ 435	$ 421
Less: Current portion	38	28
Long-term regulatory assets	397	393
Regulatory liabilities:
Regulatory liabilities	581	745
Less: Current portion	65	154
Long-term regulatory liabilities	516	591
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	83	86
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	7	8
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	33	37
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	276	272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	14	0
Other [Member]
Regulatory assets:
Regulatory assets	22	18
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	12	6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory liabilities:
Regulatory liabilities	38	112
Cost-Recovery Clauses - Offsets to Derivative Assets [Member]
Regulatory liabilities:
Regulatory liabilities	0	17
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	0	56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	524	547
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 7	$ 7

Regulatory - Schedule of Regu30

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	9 Months Ended
	Sep. 30, 2017
Minimum [Member] | Storm Reserve [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory asset recovery period	12 months

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Taxes [Line Items]
Unrecognized tax benefits	$ 7		$ 7
Tampa Electric Company [Member]
Income Taxes [Line Items]
Effective tax rate	38.73%	32.53%	38.61%	34.59%

Employee Postretirement Benef32

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017		Sep. 30, 2016
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 3	$ 4	$ 10		$ 10
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	1	2	4		5
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	5	5	15		14
Interest cost	8	7	24		23
Expected return on assets	(12)	(12)	(36)		(34)
Amortization of:
Prior service (benefit) cost	0	0	0		0
Actuarial (gain) loss	4	5	12		12
Curtailment cost			0		1
Settlement cost			7	[1]	1
Net periodic benefit cost	5	5	22		17
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1	1		1
Interest cost	2	2	6		6
Expected return on assets	0	0	0		0
Amortization of:
Prior service (benefit) cost	0	(1)	0		(2)
Actuarial (gain) loss	(1)	0	(2)		0
Curtailment cost			0		0
Settlement cost			0		0
Net periodic benefit cost	$ 1	$ 2	$ 5		$ 5
[1]	Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera.

Employee Postretirement Benef33

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	Jan. 01, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit cost		$ 3	$ 3	$ 8	$ 8
TECO Energy [Member] | Scenario Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA						7.00%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		3	4	10	10
Employer contributions				36	31
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		5	5	22	17
Employer contributions				46	37
Pension Benefits [Member] | TECO Energy [Member] | Scenario Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate						4.16%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		1	2	4	5
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		$ 1	$ 2	$ 5	$ 5
Discount rate	4.28%

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Sep. 30, 2017	Mar. 22, 2017	Dec. 31, 2016
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000	$ 50,000,000	$ 475,000,000
Borrowings Outstanding	255,000,000		170,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000		325,000,000
Borrowings Outstanding	170,000,000		40,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000		150,000,000
Borrowings Outstanding	85,000,000		130,000,000
Letters of Credit Outstanding	$ 0		$ 0

Short-Term Debt - Credit Faci35

Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2022	Mar. 22, 2022
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2018	Mar. 23, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Nov. 02, 2017	Mar. 22, 2017	Sep. 30, 2017	Dec. 31, 2016
Line Of Credit Facility [Line Items]
Weighted-average interest rate			2.07%	1.49%
Line of credit facility maximum borrowing capacity		$ 50,000,000	$ 475,000,000	$ 475,000,000
364-day Credit Agreement [Member] | Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity	$ 300,000,000
Credit facility maturity period	364 days
Credit facility maturity date	Nov. 1, 2018
Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity		$ 325,000,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage			0.125%
Minimum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Dec. 17, 2018
Maximum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage			0.30%
Maximum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Mar. 22, 2022

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 2,163
Long-term debt, carrying amount	1,859	$ 2,163
Estimated fair value	2,377	2,345
Level 1 [Member]
Debt Instrument [Line Items]
Fair value of debt securities	$ 56	$ 58

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Sep. 30, 2017USD ($)
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 30

Commitments and Contingencies39

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Sep. 30, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2017	$ 3
Future Minimum Purchased Power Payments Due, 2018	10
Future Minimum Purchased Power Payments Due, 2019	0
Future Minimum Purchased Power Payments Due, 2020	0
Future Minimum Purchased Power Payments Due, 2021	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	13
Future Minimum Operating Leases Payments Due, 2017	1
Future Minimum Operating Leases Payments Due, 2018	3
Future Minimum Operating Leases Payments Due, 2019	2
Future Minimum Operating Leases Payments Due, 2020	2
Future Minimum Operating Leases Payments Due, 2021	2
Future Minimum Operating Leases Payments Due, Thereafter	38
Total future minimum operating leases payments due	48
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2017	38
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	173
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	74
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	29
Total future minimum long-term service agreements/capital projects payments due	328
Future Minimum Clause Recoverable Commitments Payments Due, 2017	124
Future Minimum Clause Recoverable Commitments Payments Due, 2018	282
Future Minimum Clause Recoverable Commitments Payments Due, 2019	187
Future Minimum Clause Recoverable Commitments Payments Due, 2020	163
Future Minimum Clause Recoverable Commitments Payments Due, 2021	133
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,159
Total future minimum clause recoverable commitments payments due	2,048
Future Minimum Payments Due, 2017	166
Future Minimum Payments Due, 2018	468
Future Minimum Payments Due, 2019	263
Future Minimum Payments Due, 2020	172
Future Minimum Payments Due, 2021	142
Future Minimum Payments Due, Thereafter	1,226
Total future minimum payments	$ 2,437

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total revenues	$ 693	$ 689	$ 1,890	$ 1,839
Total interest charges	30	26	89	80
Net income	106	100	248	239
Total assets	8,306		8,306		$ 8,083
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	693	689	1,890	1,839
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(15)	(1)	(19)	(8)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(491)		(491)		(465)
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Eliminations [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	(15)	(1)	(19)	(8)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	598	586	1,583	1,510
Total interest charges	26	22	78	69
Net income	98	94	217	213
Total assets	7,544		7,544		7,357
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	597	586	1,581	1,509
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	0	2	1
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	110	104	326	337
Total interest charges	4	4	11	11
Net income	8	6	31	26
Total assets	1,253		1,253		$ 1,191
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	96	103	309	330
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 14	$ 1	$ 17	$ 7

Accounting for Derivative Ins41

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	1 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2017	Nov. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Derivative [Line Items]
Derivative assets	$ 0		$ 0		$ 0		$ 17,000,000
Derivative liabilities	0		0		0
Cash collateral posted with or received from any counterparties	0		0		0		$ 0
Net pre-tax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months					0
Gain on cash flow hedges			0	$ 1,000,000	1,000,000	$ 1,000,000
Natural Gas Contracts [Member]
Derivative [Line Items]
Derivative assets	0		0		0
Derivative liabilities	$ 0		0		$ 0
Maximum length of time hedging in future cash flow					Nov. 30, 2018
Maximum [Member]
Derivative [Line Items]
Gain on cash flow hedges			$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000
Natural Gas [Member]
Derivative [Line Items]
Financial hedging moratorium period	5 years	1 year

Accounting for Derivative Ins42

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Sep. 30, 2017MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,000,000
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,000,000
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,000,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 0	$ 17,000,000
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	17,000,000
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0	17,000,000
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 17,000,000
Derivative liabilities	0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	$ 0

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)MW	Sep. 30, 2016USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 21	$ 39	$ 36	$ 81
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 5	$ 19	$ 13	$ 48
Minimum [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			250

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($)	Nov. 02, 2017	Sep. 30, 2017	Mar. 22, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Line of credit facility maximum borrowing capacity		$ 475,000,000	$ 50,000,000	$ 475,000,000
Subsequent Event [Member] | 364-day Credit Agreement [Member]
Subsequent Event [Line Items]
Credit facility maturity period	364 days
Line of credit facility maximum borrowing capacity	$ 300,000,000
Credit facility maturity date	Nov. 1, 2018