10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2017

OR

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File No.	Exact name of each Registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-1111

Securities registered pursuant to Section 12(b) of the Act: NONE

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if Tampa Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES  ☐    NO  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YES  ☐    NO  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES  ☒    NO  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES  ☒    NO  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark whether Tampa Electric Company has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Act).

YES  ☐    NO  ☒

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of June 30, 2017 was zero.

As of February 8, 2018, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc, an indirect wholly-owned subsidiary of Emera Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

DEFINITIONS

Acronyms and defined terms used in this and other filings with the U.S. Securities and Exchange Commission include the following:

Term	Meaning
ABS	asset-backed security
AFUDC	allowance for funds used during construction
AFUDC-debt	debt component of allowance for funds used during construction
AFUDC-equity	equity component of allowance for funds used during construction
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
ASC	Accounting Standards Codification
BACT	Best Available Control Technology
CAD	Canadian dollars
CAIR	Clean Air Interstate Rule
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
ECRC	environmental cost recovery clause
EEI	Edison Electric Institute
EGWP	Employee Group Waiver Plan
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
EUSHI	Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPSC	Florida Public Service Commission
GHG	greenhouse gas(es)
HAFTA	Highway and Transportation Funding Act
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ITCs	investment tax credits
KW	kilowatt(s)
kWac	kilowatt on an alternating current basis
MAP-21	Moving Ahead for Progress in the 21st Century Act
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	Merger of Merger Sub Company with and into TECO Energy, with TECO Energy as the surviving corporation
MGP	manufactured gas plant
Merger Agreement	Agreement and Plan of Merger dated September 4, 2015, by and among TECO Energy, Emera and Merger Sub Company
Merger Sub Company	Emera US Inc., a Florida corporation
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board

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Term	Meaning
NAV	net asset value
Note	Note to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
OPC	Office of Public Counsel
OPEB	other postretirement benefits
OTC	over-the-counter
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
ROW	rights-of-way
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SoBRAs	solar base rate adjustments
SERP	Supplemental Executive Retirement Plan
STIF	short-term investment fund
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company
TECO Energy	TECO Energy, Inc., the direct parent company of Tampa Electric Company
TSI	TECO Services, Inc.
U.S. GAAP	generally accepted accounting principles in the United States
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

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PART I

Item 1. BUSINESS

Tampa Electric Company, referred to as TEC, was incorporated in Florida in 1899 and was reincorporated in 1949. TEC is a public utility operating within the State of Florida. TEC has two operating segments. Its electric division, referred to as Tampa Electric, provides retail electric service to approximately 750,000 customers in West Central Florida with a net winter system generating capacity of 5,218 MW at December 31, 2017. The gas division of TEC, referred to as PGS, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With approximately 375,000 customers, PGS has operations in Florida’s major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2017 was approximately 1.8 billion therms. TEC had approximately 2,650 employees as of December 31, 2017. All of TEC’s common stock is owned by TECO Energy, a holding company.

TEC makes its SEC (www.sec.gov) filings available free of charge on Tampa Electric’s website (www.tampaelectric.com/company/about/) as soon as reasonably practicable after they are filed with or furnished to the SEC. The public may read and copy any reports or other information that TEC files with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Merger with Emera

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC became an indirect wholly owned subsidiary of Emera as of July 1, 2016. See Note 8 to the 2017 Annual TEC Consolidated Financial Statements for further information regarding the Merger.

TEC Revenues

(millions)	2017			2016			2015
Tampa Electric division	$	2,054		$	1,965		$	2,018
PGS division		438			439			407
Eliminations		(22	)		(8	)		(6	)
Total revenues	$	2,470		$	2,396		$	2,419

TEC’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other sales volumes consist primarily of off-system sales to other utilities and revenues from street lighting.

For additional financial information regarding TEC’s business segments, see Note 11 to the 2017 Annual TEC Consolidated Financial Statements.

TAMPA ELECTRIC – Electric Operations

TEC’s Tampa Electric division is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has two generating stations in or near Tampa, one generating station in southwestern Polk County, Florida and three photovoltaic power stations, two in or near Tampa and one in Winter Haven, Florida. Tampa Electric had approximately 2,100 employees as of December 31, 2017, of which 780 were represented by the International Brotherhood of Electrical Workers and 230 were represented by the Office and Professional Employees International Union.

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In 2017, Tampa Electric’s total operating revenue was derived approximately 49% from residential sales, 28% from commercial sales, 8% from industrial sales and 15% from other sales, including bulk power sales for resale. The sources of operating revenue and MWH sales were as follows:

Tampa Electric Operating Revenue

(millions)	2017		2016			2015
Residential	$	1,006	$	1,036		$	1,040
Commercial		578		593			608
Industrial		158		161			160
Other retail sales of electricity		168		175			177
Total retail		1,910		1,965			1,985
Sales for resale		8		6			4
Other		136		(6	)		29
Total operating revenues	$	2,054	$	1,965		$	2,018

Megawatt-hour Sales

(thousands)	2017		2016		2015
Residential		9,029		9,188		9,045
Commercial		6,362		6,310		6,301
Industrial		2,024		1,928		1,870
Other retail sales of electricity		1,771		1,808		1,791
Total retail		19,186		19,234		19,007
Sales for resale		239		206		115
Total energy sold		19,425		19,440		19,122

No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on Tampa Electric. Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric space heating, fewer daylight hours and colder temperatures and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.

Regulation

Base Rates

Tampa Electric’s retail operations are regulated by the FPSC. The FPSC’s pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its prudently incurred costs of providing service to customers, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel, conservation costs, purchased power and certain environmental costs, are recovered through base rates. These costs include O&M expenses, depreciation, taxes, and a return on investment in assets providing electric service (rate base). The rate of return on rate base, which is intended to approximate a company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes (at a zero cost rate) and an allowed ROE. Base rates are determined in FPSC rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other interested parties.

Tampa Electric’s results for the past three years reflect the stipulation and settlement agreement entered into on September 6, 2013, which resolved all matters in Tampa Electric’s 2013 base rate proceeding.

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 an expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. The agreement provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, any party to the agreement other than Tampa Electric could seek a review of its base rates. In addition, Tampa Electric is required to file a depreciation study no fewer than 60 days but no more than one year before filing its next base rate request. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital, and Tampa Electric also began using a 15-year amortization period for all computer software

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beginning on January 1, 2013.

On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the existing 2013 base rate settlement agreement described above and extended it another four years through 2021. The FPSC approved the agreement on November 6, 2017.

The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue requirement adjustments for the 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 SoBRAs 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 receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction.

On December 12, 2017, TEC filed its petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the spring of 2018.

The agreement further maintains Tampa Electric’s allowed regulatory ROE and allowed equity in the capital structure and extends the rate freeze date from January 1, 2018 to December 31, 2021, subject to the same ROE thresholds. The agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law (see Note 4 to the 2017 Annual TEC Consolidated Financial Statements for further information on tax reform). Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. 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 agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make no investments in gas reserves.

As a result of several named storms, including Hurricane Irma, Tropical Storm Erika, Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, the amount of estimated costs charged to the storm reserve regulatory liability in 2017 exceeded the balance in the storm reserve by $47 million, which is recorded as a regulatory asset on the balance sheet. In January 2018, Tampa Electric petitioned the FPSC for recovery of estimated storm costs in excess of the reserve and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. For additional information regarding storm costs, see Note 3 to the 2017 Annual TEC Consolidated Financial Statements.

On January 30, 2018, Tampa Electric filed an implementation settlement agreement with the FPSC that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4 to the 2017 Annual TEC Consolidated Financial Statements) while keeping customer rates stable in 2018.  If approved by the FPSC, the agreement authorizes Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. Tampa Electric’s final storm costs and final impact of tax reform on its base rates pursuant to the 2017 agreement will be determined in separate regulatory proceedings.  Any difference will be trued up and recovered from or returned to customers in 2019.  In addition, beginning in January 2019, Tampa Electric will reflect the full impact of tax reform on its base rates, provided that the FPSC’s determinations have been finalized.  A decision is expected in March 2018.

Other Cost Recovery

Tampa Electric has four additional cost recovery clauses.

(1) Tampa Electric has a fuel recovery clause allowing recovery of actual fuel costs from customers through annual fuel rate adjustments. Differences between actual prudently incurred fuel costs and amounts recovered from customers in a year are recovered from or returned to customers in a subsequent year.

(2) Tampa Electric has a capacity recovery clause allowing recovery of firm demand payments associated with purchased power agreements.

(3) Tampa Electric has an environmental cost recovery clause which allows it to earn a return on investments in new facilities to comply with new environmental regulations and to recover the costs to operate and maintain these facilities.

(4) Through its conservation cost recovery clause, Tampa Electric offers its customers a comprehensive array of residential and commercial programs that have enabled it to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.

In October 2017, the FPSC approved cost-recovery rates for the above clauses for 2018.

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FERC and Other Regulations

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

Non-power goods and services transactions between Tampa Electric and its affiliate, TSI (TECO Energy’s centralized service company), are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may be disallowed for recovery from Tampa Electric’s retail and wholesale customers, respectively.

Tampa Electric is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section of the MD&A).

Competition

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. The principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.

Unlike in the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other utilities and other power generators. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Tampa Electric is not a major participant in the wholesale market because it uses its lower-cost generation primarily to serve its retail customers rather than the wholesale market.

FPSC rules promote cost-competitiveness in the building of new steam generating capacity or solar capacity by requiring IOUs, such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle or solar capacity greater than 75 MW. These rules allow independent power producers and others to bid to supply the new generating capacity.

In many areas of the country, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, known as distributed generation, by individual residential, commercial and industrial customers, or by third-party developers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Developers offer attractive financing and leasing arrangements to encourage project development. In Florida, third parties that are not subject to regulation by the FPSC are currently not permitted to make direct sales of electricity to end-use customers.

Generation Sources

In 2017 and 2016, approximately 69% and 56%, respectively, of Tampa Electric’s generation of electricity was natural gas-fired, with coal representing approximately 24% and 38%, respectively, oil/petroleum coke representing 6% in both periods, and solar representing 0.2% in 2017. Generation sources were impacted by the completion of the Polk Power Station expansion in 2017 and running Big Bend Power Station units 1-2 on natural gas in 2017. In 2017 and 2016, Tampa Electric used its generating units to meet approximately 96% and 87%, respectively, of the total system load requirements, with the remaining 4% and 13%, respectively, coming from purchased power. This change is due to completion of the Polk Power Station expansion in 2017 and expiration of a purchased power contract in December 2016. Tampa Electric is required to maintain a generation capacity greater than firm peak demand. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20% reserve margin over firm peak demand. Tampa Electric’s solar initiative will result in the generation of electricity from solar in the next four years increasing substantially from 23 MW capacity today to over 600 MW in 2021 (see the Solar Initiative section of the MD&A).

The table below presents Tampa Electric’s average delivered fuel cost per MMBTU, excluding solar production which has no fuel cost.

Average cost per MMBTU	2017		2016		2015
Natural Gas (1)	$	4.01	$	3.79	$	4.34
Coal (2)		3.30		3.61		3.44
Oil (3)		2.54		2.14		2.36
Composite (4)		3.69		3.61		3.78

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(1) Represents the cost of natural gas, transportation, storage, balancing, hedges for the price of natural gas, and fuel losses for delivery to the energy center.

(2) Represents the cost of coal and transportation.

(3) Represents the cost of oil, including petroleum coke.

(4) Represents the average cost for all fuels listed.

Tampa Electric’s fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, dispatching the lowest cost options first (after solar renewable energy), such that the incremental cost of generation increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, compliance with environmental standards and regulations, and availability of solar resources.

In 2017, Tampa Electric’s generating stations burned fuels as follows: Bayside Station burned natural gas; Big Bend Station, which has SO₂ scrubber capabilities and NO_x reduction systems, burned natural gas and high-sulfur coal; and Polk Power Station burned a blend of low-sulfur coal and petroleum coke (which was gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil.

Natural Gas. As of December 31, 2017, approximately 44% of Tampa Electric’s 1.8 million MMBTU gas storage capacity was full. Tampa Electric has contracted for 48% of its expected gas needs for the April 2018 through October 2018 period. In early March 2018, Tampa Electric expects to issue RFPs to meet its remaining 2018 gas needs and begin contracting for its 2019 requirements. Additional volume requirements in excess of projected gas needs are purchased in the short-term spot market.

Coal. Tampa Electric burned approximately 2.3 million tons of coal during 2017 and estimates that its coal consumption will be about 2.0 million tons in 2018. During 2017, Tampa Electric purchased approximately 82% of its coal under long-term contracts with four suppliers, and approximately 18% of its coal in the spot market. Tampa Electric expects to obtain approximately 37% of its coal requirements in 2018 under long-term contracts with four suppliers and the remaining 63% in the spot market. Due to an uncertain coal burn, Tampa Electric expects to purchase more from the spot market in 2018. Tampa Electric has coal transportation agreements with trucking, rail, barge and ocean vessel companies.  

Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.

In 2017, approximately 95% of Tampa Electric’s coal supply was deep-mined and approximately 5% was surface-mined. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations.

Oil. Tampa Electric purchases low sulfur No. 2 fuel oil and petroleum coke for its Polk Power station on a spot basis.

Franchises and Other Rights

Florida utilities must obtain franchises to operate in certain municipalities. Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way that it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public ROW and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture. Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years.

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from April 2018 through September 2047 and are expected to be renewed under similar terms and conditions.

Franchise fees expense totaled $44 million and $47 million in 2017 and 2016, respectively. Franchise fees are calculated using a formula based primarily on electric revenues and are recovered from customers.

Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.

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Environmental Matters

Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters. TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. See Environmental Compliance section of the MD&A for additional information.

Tampa Electric’s 2017 capital expenditures included approximately $10 million related to environmental compliance and improvement programs, primarily for scrubber and duct work, SCR catalyst replacements and compliance with the new coal combustion residual rules at the Big Bend Power Station. See the Liquidity-Capital Investments section of the MD&A for additional information on estimated future capital expenditures.

PEOPLES GAS SYSTEM – Gas Operations

PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the state of Florida.

Gas is delivered to the PGS distribution system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that serves approximately 375,000 customers. The system includes approximately 12,600 miles of gas mains and 7,200 miles of service lines (see PGS’s Franchises and Other Rights section below).

PGS had approximately 550 employees as of December 31, 2017. Approximately 130 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

In 2017, the total throughput for PGS was approximately 1.8 billion therms. Of this total throughput, 5% was gas purchased and resold to customers by PGS, 84% was third-party supplied gas that was delivered to transportation-only customers and 11% was gas sold off-system (i.e., to customers not connected to PGS’s distribution system). Industrial and power generation customers consumed approximately 59% of PGS’s annual therm volume, commercial customers consumed 26%, off-system sales customers consumed 11% and residential customers consumed 4%.

While the residential market represents only a small percentage of total therm volume, approximately 32% of total revenues were from residential customers in 2017.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also seen interest and development in natural gas vehicles. There are 49 compressed natural gas filling stations connected to the PGS distribution system. See the Outlook and PGS Operating Results sections of the MD&A for information on the impact of natural gas vehicles on PGS’s operations.

Revenues and therms for PGS for the years ended December 31 were as follows:

	Revenues						Therms
(millions)	2017		2016		2015		2017		2016		2015
Residential	$	138	$	140	$	137		77		78		75
Commercial		144		143		139		489		488		471
Industrial		15		13		13		330		321		289
Off-system sales		70		73		50		201		245		166
Power generation		5		5		7		750		760		758
Other revenues		54		53		50		-		-		-
Total	$	426	$	427	$	396		1,847		1,892		1,759

No significant part of PGS’s business is dependent upon a single or limited number of customers where the loss of any one would have a significant adverse effect on PGS. PGS’s business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.

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Regulation

Base Rates

The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC seeks to set rates at a level that provides an opportunity for a utility to collect total revenues (revenue requirements) equal to its prudently incurred costs of providing service to customers, plus a reasonable return on invested capital.

The costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’s weighted cost of capital, primarily includes its cost for debt, deferred income taxes (at a zero cost rate), and an allowed ROE. Base rates are determined in FPSC revenue requirements proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.

PGS’s results reflect base rates established in May 2009 and an ROE range of 9.75% and 11.75%, with base rates set at the middle of the range of 10.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital.

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 bottom of the 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 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 agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million of that amount would be amortized over a two-year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense.  

The PGS settlement does not contain a provision for tax reform. On January 9, 2018, the Florida Office of Public Counsel filed a generic docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS.

Cost Recovery Clauses and Riders

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through a PGA clause. This clause is designed to recover the actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. The last FPSC-approved PGA rate was in November 2017.

In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm charge for energy conservation and pipeline replacement programs as described above. The conservation charge is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are mandated by Florida law and approved and monitored by the FPSC. PGS is also permitted to recover the return on, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. The FPSC approved a replacement program of approximately 5%, or 500 miles, of the PGS system at a cost of approximately $80 million over a 10-year period beginning in 2013. As disclosed above, in February 2017, the FPSC approved an amendment to the cast iron bare steel rider to include certain plastic materials and pipe deemed obsolete by Pipeline and Hazardous Materials Safety Administration, totaling approximately 1,000 miles. PGS projects to have all cast iron and bare steel pipe removed from its system by 2022, with the replacement of obsolete plastic pipe continuing until 2028 under the rider.

FPSC and Other Regulation

The FPSC also requires natural gas utilities to offer transportation-only service to all non-residential customers. In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system.

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PGS is subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section of the MD&A).

Competition

Although PGS is not in direct competition with any other regulated local distributors of natural gas for customers within its service areas, there are other forms of competition. The principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil.

In Florida, gas service is unbundled for all non-residential customers. PGS offers unbundled transportation service to all non-residential customers, and residential customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings effect when a customer shifts to transportation-only sales. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 24,500 transportation-only customers as of December 31, 2017 out of approximately 37,900 eligible customers.

Competition is most prevalent in the large commercial and industrial markets. These classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby bypassing the PGS system. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.

Gas Supplies

PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.

Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.

Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by the FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the PGA clause.

PGS procures natural gas supplies using base-load contracts and swing-supply contracts (i.e., short-term contracts without a specified volume) with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.

Franchises and Other Rights

PGS holds franchise and other rights with 116 municipalities and districts throughout Florida. These franchises govern the placement of PGS’s facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises are irrevocable and are not subject to amendment without the consent of PGS.

Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’s property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

PGS’s franchise agreements have various expiration dates ranging from 2018 through 2047. PGS expects to negotiate 18 franchise renewals in 2018 under similar terms. Franchise fees expense totaled $9 million and $10 million in 2017 and 2016, respectively. Franchise fees are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are recovered on a dollar-for-dollar basis from the respective customers within each franchise area.

Utility operations in areas outside of incorporated municipalities and districts are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commission of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates, and these rights are, therefore, considered perpetual.

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Environmental Matters

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. TEC is one of several PRPs for certain superfund sites and, through PGS, for former MGP sites. See Note 9 to the 2017 Annual TEC Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

During the year ended December 31, 2017, PGS did not incur any material capital expenditures to meet environmental requirements as none were required, nor are any anticipated for the 2018 through 2022 period.

Item 1A. RISK FACTORS

General Risks

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TEC.

The business of TEC is concentrated in Florida. If economic conditions start to decline, retail customer growth rates may stagnate or decline, and customers’ energy usage may further decline, adversely affecting TEC’s results of operations, net income and cash flows. A factor in our customer growth in Florida is net in migration of new residents, both domestic and non-U.S. A slowdown in the U.S. economy could reduce the number of new residents and slow customer growth.

Developments in technology could reduce demand for electricity and gas.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient appliances and equipment. Advances in these or other technologies could reduce the cost of producing electricity or transporting gas, or otherwise make Tampa Electric’s existing generating facilities uneconomic. In addition, advances in such technologies could reduce demand for electricity or natural gas, which could negatively impact the results of operations, net income and cash flows of TEC.

Results at TEC may be affected by changes in customer energy-usage patterns.

For the past several years, at Tampa Electric and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts and improvements in lighting and appliance efficiency.

Forecasts by TEC are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of TEC to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency, economic conditions or other factors.

TEC’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.

TEC’s utility businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by its electric and gas utilities are particularly sensitive to seasonal variations in weather conditions, including unusually mild summer or winter weather that cause lower energy usage for cooling or heating purposes, respectively. Tampa Electric and PGS forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS, which typically has a short but significant winter peak period that is dependent on cold weather, is more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather could negatively impact results at TEC.

TEC’s electric and gas utilities are regulated; changes in regulation or the regulatory environment could reduce revenues, increase costs or competition.

TEC’s electric and gas utilities operate in regulated industries. Retail operations, including the rates charged, are regulated by the FPSC, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on TEC’s financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, indicating an overearnings trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged overearnings could result in credits or refunds to customers, which could reduce future earnings and cash flow.

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The computation of TEC’s provision for income taxes is impacted by changes in tax legislation.  

Any changes in tax legislation could affect TEC’s future cash flows and financial position. The value of TEC’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Some of the specific details related to the U.S. tax reform legislation that was enacted on December 22, 2017 have yet to be clarified. See MD&A-U.S. Tax Reform and Note 4 of the TEC 2017 Annual Consolidated Financial Statements for further information regarding tax reform.

Increased customer use of distributed generation could adversely affect Tampa Electric.

In many areas of the United States, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, known as distributed generation. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation.

Increased usage of distributed generation can reduce utility electricity sales but does not reduce the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

Changes in the environmental laws and regulations affecting its businesses could increase TEC’s costs or curtail its activities.

TEC’s businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TEC, requiring cost-recovery proceedings and/or requiring it to curtail some of its businesses’ activities.

Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.

EPA’s new CCR rule became effective on October 19, 2015. On December 10, 2016, Congress passed the “Water Infrastructure Improvements for the Nation Act” (WIINA), which includes provisions modifying the implementation plan for the federal CCR Rule.  WIINA amends the CCR Rule so that it will now be administered primarily by the states through state-operated permit programs which will be approved and overseen by the EPA.  While this change should effectively eliminate the threat of litigation by private citizens as an enforcement mechanism by placing compliance and enforcement authority in the hands of the state agencies, Tampa Electric cannot ultimately be assured that any increased costs associated with these types of regulations will be eligible for cost-recovery treatment.

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase Tampa Electric’s costs or the rates charged to its customers, which could curtail sales.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new state or federal environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but Tampa Electric cannot be assured that the FPSC would grant such recovery.

On February 9, 2016, the U.S. Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the U.S. Court of Appeals for the District of Columbia Circuit. The timing of the resolution of the legal challenges and the removal of the stay by the U.S. Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018 or later.

Prior to the stay, the Clean Power Plan would have required each state to be responsible for implementing its own regulations to correspond with federal standards. Accordingly, a change in Florida’s regulatory landscape could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on Tampa Electric requiring FPSC cost recovery proceedings and/or requiring it to curtail some of its business activities.

The Clean Power Plan would have established state-specific emission rate- and mass-based goals measured against a 2012 baseline. As Tampa Electric’s investments in lower-GHG production largely occurred before 2012 and are factored into Florida’s baseline generating capacity, if the Clean Power Plan moves forward, Tampa Electric may encounter more difficulty than its competitors in achieving cost-effective GHG emission reductions. Because the ultimate form of Florida’s state plan remains unknown,

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the increased compliance costs that Tampa Electric may face as a result of the Clean Power Plan in its form prior to the stay are currently uncertain.

TEC’s computer systems and the infrastructure of its utility companies are subject to cyber- (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer-, employee-related or other sensitive or critical information or systems, or otherwise adversely affect its business, reputation and financial results and condition.

TEC’s reliance on information technology systems and network infrastructure to manage its business, including controls for interconnected systems of generation, distribution and transmission, exposes TEC to potential risks related to cybersecurity attack.  Attacks can occur over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems outside of the organization.  A cybersecurity attack could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or otherwise adversely affect TEC’s business, reputation and financial results and condition.

TEC has security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure accuracy.  Despite security measures in place, TEC’s systems, assets and information could experience security breaches that could cause system failures, disrupt operations, adversely affect safety, result in loss of service to customers and release of sensitive or confidential information. Should such cybersecurity risks materialize, TEC could suffer costs, losses and damage, all or some of which may not be recoverable through legal, regulatory or other processes.

There have also been physical attacks on critical infrastructure around the world. While the transmission and distribution system infrastructure of TEC’s utility companies are designed and operated in a manner intended to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair and restore systems. These types of events, either impacting TEC’s facilities or the industry in general, could also cause TEC to incur additional security- and insurance-related costs, and could have adverse effects on its business and financial results.

Potential competitive changes may adversely affect TEC.

There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.  

The gas distribution industry has been subject to competitive forces for a number of years. Gas services provided by PGS are unbundled for all non-residential customers. Because PGS earns on the distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’s results. However, future structural changes could adversely affect PGS.

TEC relies on some natural gas transmission assets that it does not own or control to deliver natural gas.

TEC depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations could be adversely affected.

Disruption of fuel supply could have an adverse impact on the financial condition of TEC.

Tampa Electric and PGS depend on third parties to supply fuel, including natural gas, oil and coal. As a result, there are risks of supply interruptions and fuel-price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of transportation facilities, pipeline failures or other events, could impair the ability to deliver electricity and gas or generate electricity and could adversely affect operations. The loss of coal suppliers or the inability to renew existing coal and natural gas contracts at favorable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TEC.

Commodity price changes may affect the operating costs and competitive positions of TEC’s businesses.

TEC’s businesses are sensitive to changes in gas, coal, oil and other commodity prices. Any changes in the availability of these commodities could affect the prices charged by suppliers as well as suppliers’ operating costs and the competitive positions of their products and services.

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In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of natural gas and coal. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales of, and the margins earned on, wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of PGS as compared to electricity, other forms of energy and other gas suppliers.

The facilities and operations of TEC could be affected by natural disasters or other catastrophic events.

TEC’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. hurricanes, floods, high winds, fires and earthquakes), equipment failures, vandalism, a major accident or incident at one of the sites, and other events beyond the control of TEC. The operation of transmission and distribution systems involves certain risks, including gas leaks, fires, explosions, pipeline ruptures and other hazards and risks that may cause unforeseen interruptions, personal injury, death, or property damage. Any such incident could have an adverse effect on TEC, and any costs relating to such events may not be recoverable through insurance or rates.

The franchise rights held by Tampa Electric and PGS could be lost in the event of a breach by such utilities or could expire and not be renewed.

Tampa Electric and PGS hold franchise agreements with counterparties throughout their service areas. In some cases, these rights could be lost in the event of a breach of these agreements by the applicable utility. These agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Some agreements contain provisions allowing municipalities to purchase the portion of the applicable utility’s system located within a given municipality’s boundaries under certain conditions.

Tampa Electric and PGS may not be able to secure adequate rights-of-way to construct transmission lines, gas interconnection lines and distribution-related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

Tampa Electric and PGS rely on federal, state and local governmental agencies to secure rights-of-way and siting permits to construct transmission lines, gas interconnection lines and distribution-related facilities. If adequate rights-of-way and siting permits to build new transportation and transmission lines cannot be secured, then Tampa Electric and PGS:

• May need to remove or abandon its facilities on the property covered by rights-of-way or franchises and seek alternative locations for its transmission or distribution facilities;

• May need to rely on more costly alternatives to provide energy to their customers;

• May not be able to maintain reliability in their service areas; and/or

• May experience a negative impact on their ability to provide electric or gas service to new customers.

Failure to attract and retain an appropriately qualified workforce could adversely affect TEC’s financial results.

Events such as increased retirements due to an aging workforce or the departure of employees for other reasons without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development. Failure to attract and hire employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may cause costs to operate TEC’s systems to rise. If TEC is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

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TEC has indebtedness which could adversely affect its financial condition and financial flexibility.

TEC has indebtedness that it is obligated to pay. The level of TEC’s indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing (see Management’s Discussion & Analysis – Significant Financial Covenants section).

TEC must meet certain financial covenants as defined in the applicable agreements to borrow under its credit facilities. Also, TEC has certain restrictive covenants in specific agreements and debt instruments.

Although TEC was in compliance with all required financial covenants as of December 31, 2017, it cannot assure compliance with these financial covenants in the future. TEC’s failure to comply with any of these covenants or to meet its payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. TEC may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a portion of its outstanding obligations. This may force TEC to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance its indebtedness. TEC’s ability to restructure or refinance its debt would depend on the condition of the capital markets and TEC’s financial condition at such time. Any refinancing of TEC’s debt could be at higher interest rates and may require compliance with more onerous covenants, which could further restrict business operations.

TEC has obligations that do not appear on its balance sheet, such as operating leases and letters of credit.  To the extent material, these obligations are disclosed in the notes to the financial statements.

Financial market conditions could limit TEC’s access to capital and increase TEC’s costs of borrowing or refinancing, or have other adverse effects on its results.

TEC has debt maturing in subsequent years, which may need to be refinanced. Future financial market conditions could limit TEC’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase TEC’s pension expense or the required cash contributions to maintain required levels of funding for its plan.

TEC is a participant in the comprehensive retirement plans of TECO Energy. Under calculation requirements of the Pension Protection Act, as of the January 1, 2018 measurement date, TECO Energy’s pension plan was fully funded. Under MAP 21, TEC is not required to make additional cash contributions over the next five years. Any future declines in the financial markets or interest rates could increase the amount of contributions required to fund its pension plan in the future, and could cause pension expense to increase.

TEC’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast.

For 2018, Tampa Electric is forecasting capital expenditures to support the current levels of customer growth, harden transmission and distribution facilities against storm damage, to maintain transmission and distribution system reliability, invest in solar generation and to maintain generating unit reliability and efficiency. For 2018, PGS is forecasting capital expenditures to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel, cast iron and obsolete plastic pipe.

Total costs may be higher than estimated and there can be no assurance that TEC will be able to recover such expenditures through regulated rates. If TEC’s capital expenditures exceed the forecasted levels, it may need to draw on credit facilities or access the capital markets on unfavorable terms.

TEC’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade.

The senior unsecured debt of TEC is rated by S&P at ‘BBB+’ and by Moody’s at ‘A3’. A downgrade to below investment grade by the rating agencies, which would require a four-notch downgrade by Moody’s and a three-notch downgrade by S&P, may affect TEC’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. Downgrades could adversely affect TEC’s relationships with customers and counterparties.

At current ratings, TEC is able to purchase electricity and gas without providing collateral. If the ratings of TEC decline to below investment grade, Tampa Electric and PGS could be required to post collateral to support their purchases of electricity and gas.

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Item 2. PROPERTIES

TEC believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric are subject to a first mortgage bond indenture under which no bonds are currently outstanding.

TAMPA ELECTRIC

Tampa Electric has three electric generating stations in service, with a December 2017 net winter generating capability of 5,218 MW. Tampa Electric assets include the Big Bend Power Station (1,632 MW capacity from four coal units and 61 MW from a CT), the Bayside Power Station (1,839 MW capacity from two natural gas combined cycle units and 244 MW from four CTs) and the Polk Power Station (220 MW capacity from the IGCC unit and 1,200 MW from a natural gas combined cycle unit). On January 16, 2017, the combined cycle unit at the Polk Power Station was placed in service and expanded the plant by 468 MW.

Tampa Electric has three solar arrays at Tampa International Airport (1.6 MW capacity), LEGOLAND Florida (1.5 MWcapacity), and the Big Bend Power Station (19.4 MW).

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,450 mega volts amps. The transmission system consists of approximately 1,330 total circuit miles of high voltage transmission lines, including underground and double-circuit lines. The distribution system consists of approximately 6,260 circuit miles of overhead lines and approximately 5,270 circuit miles of underground lines. As of December 31, 2017, there were 768,300 meters in service. All of this property is located in Florida.

Tampa Electric’s property, plant and equipment are owned, except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances common to properties of the size and character of those of Tampa Electric.

Tampa Electric has easements or other property rights for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. Transmission and distribution lines located in public ways are maintained under franchises or permits.

Tampa Electric has a long-term lease for the office building in downtown Tampa, which serves as headquarters for TECO Energy, Tampa Electric, PGS and TSI.

PEOPLES GAS SYSTEM

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 19,800 miles of pipe, including approximately 12,600 miles of mains and 7,200 miles of service lines. Mains and service lines are maintained under ROW, franchises or permits.

PGS’s operations are located in 14 operating divisions throughout Florida. Most of the operations and administrative facilities are owned.

Item 3. LEGAL PROCEEDINGS

From time to time, TEC is involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of 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. For a discussion of legal proceedings and environmental matters, see Note 9, Commitments and Contingencies, of the 2017 Annual TEC Consolidated Financial Statements.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of TEC’s common stock is owned by TECO Energy, which in turn is owned by a subsidiary of Emera and, thus, is not listed on a stock exchange. Therefore, there is no market for such stock. Dividends are declared and paid at the discretion of TEC’s Board of Directors. In 2017, 2016 and 2015, TEC paid quarterly dividends on its common stock substantially equal to its net income (see the Consolidated Statements of Cash Flows in the 2017 Annual TEC Consolidated Financial Statements).

Item 6. SELECTED FINANCIAL DATA OF TAMPA ELECTRIC COMPANY

Information required by Item 6 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. Such statements are based on our current expectations as of the date we filed this report, and we do not undertake to update or revise such forward-looking statements, except as may be required by law. These forward-looking statements include references to anticipated capital expenditures, liquidity and financing requirements, projected operating results, future environmental matters, and regulatory and other plans. Important factors that could cause actual results to differ materially from those projected in these forward-looking statements are discussed under “Risk Factors”, and elsewhere in this MD&A.

In this Management’s Discussion & Analysis, “we,” “our,” “ours” and “us” refer to TEC, unless the context otherwise requires.

OVERVIEW

TEC has regulated electric and gas utility operations in Florida. Tampa Electric served approximately 750,000 customers in a 2,000-square-mile service area in West Central Florida and had electric generating plants with a winter peak generating capacity of 5,218 MW at December 31, 2017. PGS, Florida’s largest gas distribution utility, served approximately 375,000 residential, commercial, industrial and electric power generating customers at December 31, 2017 in all major metropolitan areas of the state, with a total natural gas throughput of approximately 1.8 billion therms in 2017.

MERGER WITH EMERA

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, and TECO Energy became a wholly owned subsidiary of Emera. Therefore, TEC 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. See Notes 8 and 10 to the 2017 Annual TEC Consolidated Financial Statements for further information regarding the Merger and related party transactions between TEC and its affiliates, respectively.

2017 PERFORMANCE

All amounts included in this MD&A are after tax, unless otherwise noted.

In 2017, our net income was $316 million, compared with $286 million in 2016. The most significant factors impacting the year-over-year-comparison of net income were higher base rates at Tampa Electric that went into effect with the completion of the Polk Power Station expansion in January 2017, customer growth and lower depreciation expense at PGS, partially offset by higher depreciation expense and lower AFUDC at Tampa Electric. See below for further detail.

OUTLOOK

TEC’s earnings are most directly impacted by the earned rate of return on equity and the capital structure approved by the FPSC, the prudent management of operating costs, the approved recovery of regulatory deferrals, and the timing and amount of capital expenditures.

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Tampa Electric and PGS anticipate earning within their allowed ROE ranges in 2018 and expect rate base and earnings to be higher than in prior years. Tampa Electric expects customer growth rates in 2018 to be in line with 2017, reflective of the economic growth in Florida. PGS expects customer growth rates in 2018 to be higher than 2017, reflective of the economic growth in Florida and anticipated optimizing of existing gas main opportunities. Assuming normal weather, Tampa Electric and PGS sales volumes are expected to increase primarily due to customer growth.

On December 22, 2017, President Trump signed tax reform changes into legislation. Tax reform did not significantly impact 2017 earnings as the revaluation of deferred tax liabilities at the new tax rates were allowed to be deferred as a regulatory liability and returned to customers over time (see U.S. Tax Reform below).  We also do not expect tax reform to significantly impact future net income, but we do expect it to negatively impact cash flows in the near term. On January 30, 2018, Tampa Electric filed an implementation settlement agreement with the FPSC that addresses both the recovery of storm costs and the return of tax reform benefits to customers while keeping customer rates stable in 2018. In addition, beginning in January 2019, Tampa Electric will reflect the full impact of tax reform on its base rates. See Notes 3 and 4 of the 2017 Annual TEC Consolidated Financial Statements for further information.

In September 2017, Tampa Electric announced its intention to invest approximately $850 million over four years in new utility-scale solar photovoltaic projects across its service territory.  On November 6, 2017, the FPSC approved a settlement agreement allowing a base rate adjustment that provides for the recovery, upon in-service, of up to 600 MW of investments in utility-scale solar projects that will be phased in from late 2018 through early 2021. See Note 3 of the 2017 Annual TEC Consolidated Financial Statements for further information on the potential revenue adjustments for the SoBRAs.

In 2018, we expect to invest approximately $1.2 billion in capital projects compared to $640 million in 2017. This increase is primarily the result of higher spending on solar projects. Capital expenditures also include investments to expand the PGS system, normal system reliability, programs for Tampa Electric transmission and distribution system storm hardening and transmission system reliability requirements. Depreciation expense is expected to increase in 2018 due to the projected increase in capital expenditures.

These forecasts are based on our current assumptions described in the operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).

U.S. TAX REFORM

On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. Although some of the specific details of tax reform legislation have yet to be clarified, the Act impacts TEC’s consolidated financial results as discussed below. See Note 4 of the 2017 Annual TEC Consolidated Financial Statements for further detail.

Key provisions impacting TEC:

• U.S. Federal corporate income tax rate reduction from 35% to 21% effective January 1, 2018.

• Immediate expensing of 100% of the cost of new investments made in qualified depreciable assets after September 27, 2017. However, regulated utilities have an exemption from this immediate expensing.

• Preservation of the existing normalization rules, which allows regulated companies to flow back tax benefits related to depreciation over the regulatory life of the asset.

• Repeal of section 199 domestic production deduction.

Impact on December 31, 2017 results:

• A non-cash provisional revaluation of $755 million was recorded on TEC’s net deferred income tax liabilities at the lower income tax rate. TEC has recorded an equivalent increase as a regulatory liability as the impact of lower U.S. taxes is expected to be returned to customers over time as required by the Act or by order of FPSC. As a result, the deferred tax adjustment for TEC has an impact on the 2017 balance sheet but no impact on 2017 earnings. 

• TEC is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.  Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act. The Act provides that the measurement period must be completed by December 22, 2018.

Future impacts:

• It is expected there will be no material changes in TEC’s net earnings as lower income tax expense and amortization of the revaluation regulatory liability is expected to be offset by lower customer rates over time.

An estimated decrease in cash from operations of $100 million to $150 million annually primarily due to the reduction in customer rates from tax reform benefits and the reduced levels of deferred taxes. 

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OPERATING RESULTS

This MD&A utilizes TEC’s consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, income and deferred taxes, postretirement benefits and others (see the Critical Accounting Policies and Estimates section).

The following table shows the revenues and net income of the business segments on a U.S. GAAP basis (see Note 11 to the 2017 Annual TEC Consolidated Financial Statements).  

(millions)		2017			2016			2015
Revenues
	Tampa Electric	$	2,054		$	1,965		$	2,018
	PGS		438			439			407
	Eliminations		(22	)		(8	)		(6	)
	TEC	$	2,470		$	2,396		$	2,419
Net income
	Tampa Electric	$	273		$	251		$	241
	PGS		43			35			35
	TEC	$	316		$	286		$	276

TAMPA ELECTRIC

Electric Operations Results

Net income in 2017 was $273 million, compared with $251 million in 2016, driven by higher base revenues from 1.9% higher average number of customers and higher base rates as a result of the completion of the Polk Power Station expansion in January 2017, and lower operations and maintenance expense, partially offset by higher depreciation expense, higher property taxes and lower federal R&D tax credits. Full-year net income in 2017 included $2 million of AFUDC-equity, which decreased, compared with $24 million of AFUDC-equity in 2016, due to the completion of the Polk Power Station expansion in January 2017. See the Operating Revenues and Operating Expenses section for additional information.

Net income in 2016 was $251 million, compared with $241 million in 2015, driven by higher base revenues from 1.6% higher average number of customers partially offset by higher operations and maintenance and depreciation expense. Full-year net income in 2016 included $24 million of AFUDC-equity, $7 million of federal R&D tax credits and other tax deductions including Section 199 deduction, compared with $17 million of AFUDC-equity and no federal R&D tax credits in the 2015 period. See the Operating Revenues and Operating Expenses section for additional information.

The table below provides a summary of Tampa Electric’s revenue and expenses and energy sales by customer type.

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Summary of Operating Results

(millions, except customers and total degree days)	2017		% Change			2016		% Change			2015
Revenues	$	2,054		5		$	1,965		(3	)	$	2,018
O&M expense		399		(6	)		424		1			421
Depreciation and amortization expense		300		12			268		4			257
Taxes, other than income		162		3			157		1			156
Non-fuel operating expenses		861		1			849		2			834
Fuel expense		608		7			568		(12	)		644
Purchased power expense		46		(56	)		104		32			79
Total fuel & purchased power expense		654		(3	)		672		(7	)		723
Total operating expenses		1,515		(0	)		1,521		(2	)		1,557
Operating income	$	539		21		$	444		(4	)	$	461
AFUDC-equity	$	2		(92	)	$	24		41		$	17
Provision for income taxes	$	171		32		$	130		(10	)	$	144
Net income	$	273		9		$	251		4		$	241
Megawatt-Hour Sales (thousands)
Residential		9,029		(2	)		9,188		2			9,045
Commercial		6,362		1			6,310		0			6,301
Industrial		2,024		5			1,928		3			1,870
Other		1,771		(2	)		1,808		1			1,791
Total retail		19,186		(0	)		19,234		1			19,007
Sales for resale		239		16			206		79			115
Total energy sold		19,425		(0	)		19,440		2			19,122
Retail customers—(thousands)
At December 31		748		2			736		2			724
Retail net energy for load		20,297		1			20,165		0			20,103
Total degree days		4,520		1			4,462		(6	)		4,729

Operating Revenues

In 2017, pre-tax base revenues were $118 million higher than in 2016, driven by approximately $113 million pre-tax higher base rates as a result of the 2013 rate case settlement related to the expansion of the Polk Power Station in January 2017. Pre-tax base revenues exclude revenues that recover costs from customers through clauses and riders. In 2017, total degree days in Tampa Electric's service area were 7% above normal and 1% above the 2016 period as a result of warmer than normal spring weather offset by mild winter weather in the first quarter. Although degree days were higher this year compared to the same period last year, the mix of heating and cooling degree days had an adverse effect on the residential sector's energy sales. The lack of heating degree days and heating appliance use resulted in residential sales lower than in 2016. In the non-residential sectors, which are not as sensitive to heating degree days, energy sales were higher than in 2016. In 2017, total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, was in-line with 2016.

Pre-tax base revenue in 2016 was $12 million higher than in 2015, including approximately $5 million of higher pre-tax base revenue due to the base rate increase effective November 1, 2015, as a result of the 2013 rate case settlement. In 2016, retail MWH sales, measured on a billing cycle basis as shown in the table above grew 1.2% from 2015 levels. Sales in 2016 reflected warmer than normal third quarter weather, strong customer growth and a stronger local economy. Total net energy for load increased 0.3% in 2016 compared to 2015. In 2016, total degree days in Tampa Electric's service area were 7% above normal and 6% below 2015 levels. In 2016, retail energy sales to residential and commercial customers increased primarily due to customer growth. Sales to industrial customers increased due to the strength of the Tampa area economy, increased mining operations and the decrease of self-generation.  

Customer and Energy Sales Growth Outlook

The Florida labor market continues to outperform the U.S. labor market, despite the temporary effects of Hurricane Irma. The local Tampa area unemployment rate decreased to 3.9% in 2017 compared with 4.5% in 2016 and 5.0% in 2015, which is below the 2017 Florida rate of 4.2% and the U.S. rate of 4.4%. From 2017 to 2020, Florida’s and Tampa Electric’s service area economy, as measured by Real Gross State Product, are forecasted to expand at an average annual rate of 5.0%, outpacing the forecasted U.S. rate of 2.0%.

Population growth is forecasted to continue to be a major driver of customer growth for many years. In 2017, new single-family home building permits in Tampa Electric’s service area increased by 18% over 2016. Tampa Electric expects that new community

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projects will continue to propel customer growth over the next three to five years and that, longer-term, assuming continued economic growth and business expansion, annual customer growth will average 1.6%.

For the past several years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, improvements in lighting and appliance efficiency, smaller single-family houses and increased multi-family housing.

In 2018, retail energy sales are expected to grow at a rate of approximately 1.7% over 2017 sales. Beyond 2018, average retail energy sales are expected to grow at a rate of approximately 1.0% in the near term, and about 1.2% over the longer-term. Energy sales growth projections reflect the offsetting impacts to customer growth from average energy consumption trends and assume continued local area economic growth, normal weather, and a continuation of the current energy market structure.

Tampa Electric anticipates earnings within the allowed ROE range in 2018 and expects earnings and rate base growth as a result of continued customer growth, increased investment in solar projects, and a focus on cost control.

Operating Expenses

Total pre-tax operating expense was 0.5% lower in 2017 compared to 2016, driven primarily by lower purchased power and O&M expenses partially offset by higher fuel expense. O&M expenses, excluding all FPSC-approved cost-recovery clauses and riders, decreased $20 million in 2017, reflecting fewer planned outages and generation maintenance as compared to 2016.  

Total pre-tax operating expense was 2.3% lower in 2016 compared to 2015, driven primarily by lower fuel expense partially offset by higher O&M expense. O&M expenses, excluding all FPSC-approved cost-recovery clauses and riders, increased $9 million in 2016, reflecting higher costs to safely and reliably serve customers.

In 2017 and 2016, depreciation and amortization expense increased $19 million and $7 million, respectively, reflecting additions to facilities to serve customers, including expansion of the Polk Power Station in January 2017. In 2018, depreciation expense is expected to increase as the solar projects are placed in service and due to normal plant additions.

Excluding all FPSC-approved cost-recovery clause-related expense, O&M expense in 2018 is expected to be higher than in 2017 reflecting higher costs to safely and reliably serve customers and higher employee costs in 2018.  

As a result of a tragic industrial accident at Big Bend Power Station on June 29, 2017, five workers (including one Tampa Electric employee and four contract workers) were killed and one other worker sustained serious injuries. Tampa Electric believes that any costs associated with the damages, injuries, fatalities and other losses related to the incident are substantially covered by insurance.

Fuel Prices and Fuel Cost Recovery

In October 2017, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2018. The rates include the expected cost for natural gas and coal in 2018, and the net over-recovery of fuel, purchased power and capacity clause expense.

Total fuel cost increased in 2017 due to increased natural gas-fired generation with the commercial operation of the combined cycle unit Polk 2 in January 2017. Purchased power expense decreased in 2017 due to lower volumes of energy purchased from others. Delivered natural gas prices increased 5.8% in 2017 as abundant supplies of natural gas from on-shore domestic natural gas produced from shale formations was offset by increased demand from LNG production and gas-fired electric generation. Delivered coal costs decreased 8.6% in 2017. The average coal and natural gas costs were $3.30/MMBTU and $4.01/MMBTU, respectively, in 2017, compared with $3.61/MMBTU and $3.79/MMBTU, respectively, in 2016.

Full-year Henry Hub natural gas futures as traded on the NYMEX and various forecasts for natural gas prices indicate that natural gas prices are expected to average about $2.82/MMBTU with a monthly range between $2.65 and $3.10 in 2018 and 2019, which is lower than the 2017 NYMEX natural gas average price of $3.11/MMBTU. Current natural gas prices reflect increased natural gas drilling, offset partially by continuing growth in LNG production and gas-fired electric generation. Compared to 2017, delivered coal prices are expected to be relatively flat in 2018. Tampa Electric continues to burn primarily Illinois Basin coal with small amounts of Northern Appalachian coal, petroleum coke and South American coal. 

Solar Initiatives

In 2017, Tampa Electric completed a 19.4-MW utility-scale solar photovoltaic project at Tampa Electric’s Big Bend Station. This is the largest solar project in the Tampa Bay area, consisting of more than 200,000 solar panels on 100 acres of land owned by Tampa Electric. It has the capacity to power more than 3,500 homes. In 2016, Tampa Electric completed the construction of a 1.5-MW solar photovoltaic energy installation at LEGOLAND Florida. In 2015, Tampa Electric completed the construction of a 1.6-MW solar photovoltaic energy installation at Tampa International Airport, which was Tampa Electric’s first large-scale solar facility.

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Tampa Electric owns the solar photovoltaic arrays, and the electricity they produce goes to the grid to benefit all Tampa Electric customers. In addition, Tampa Electric has installed 2,135 KW of solar panels to generate electricity at eight community sites. Tampa Electric anticipates developing additional similarly sized small-scale solar photovoltaic installations and additional utility-scale installations.

On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric that provides for SoBRAs for up to 600 MW of investment in utility-scale solar projects. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction. See Note 3 to the 2017 Annual TEC Consolidated Financial Statements for additional information.

On January 22, 2018, President Trump signed an executive order that adds significant import tariff, or tax, on certain solar panels that are brought into the U.S. TEC’s 600 MW solar project investment is not affected as its supplier uses a type of technology that is exempt from the tariff.  

PGS

Operating Results

In 2017, PGS reported net income of $43 million, compared with $35 million in 2016. Results reflect higher net revenue driven by 2.6% higher average number of customers. Excluding all FPSC-approved cost-recovery clauses, O&M expense was flat to 2016. Depreciation and amortization expense decreased $6 million due to the 2016 depreciation settlement agreement approved by the FPSC.  

In 2016, PGS reported net income of $35 million compared to the same net income in 2015. Results reflected higher residential sales volumes driven by 2.5% higher average number of customers and higher commercial sales volumes driven by a strong economy.  Excluding all FPSC-approved cost-recovery clauses, O&M expense was $4 million higher in 2016 than in 2015, driven by higher operating and employee benefit costs. Depreciation and amortization expense increased $2 million, which includes a $16 million pre-tax decrease in depreciation offset by a $16 million pre-tax increase in amortization of the regulatory asset associated with environmental remediation costs per the settlement agreement approved by the FPSC.

In 2017 and 2016, total throughput for PGS was approximately 1.8 billion therms and 1.9 billion therms, respectively. In 2017, industrial and power generation customers represented approximately 59% of annual therm volume, commercial customers used approximately 26%, approximately 11% was sold off-system, and the remainder was consumed by residential customers. In 2016 and 2015, the allocation was generally the same with industrial and power generation customers consuming approximately 57% and 60%, respectively, of PGS’s annual therm volume, commercial customers consumed 26% and 27%, respectively, off-system sales customers consumed 13% and 9%, respectively, and residential customers consumed 4% in both 2016 and 2015.

Residential customers comprised approximately 32% of total revenues in 2017, decreasing from 33% of total revenues in 2016 due to the mix of higher commercial and industrial revenue in 2017, and a warm winter. New residential construction, which includes natural gas and conversions of existing residences to natural gas, increased in 2017 and 2016 as the economy and the housing market in select markets in Florida continue to grow.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. In 2017, PGS completed a system expansion to reach a large LNG facility at the Jacksonville Port. PGS has also experienced interest in the usage of CNG as an alternative fuel for vehicles, especially refuse trucks and buses. Therms sold to CNG stations have increased steadily to 31 million therms sold in 2017 compared to 26 million therms in 2016 and 20 million therms in 2015. Currently, there are 49 CNG fueling stations connected to the PGS system, with two more in progress. PGS owns three CNG filling stations, and the cost of these stations is recovered over time through a special rate approved by the FPSC. CNG conversions add therm sales to the gas system without requiring significant capital investment by PGS.

The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a PGA. Because this charge may be adjusted monthly based on a cap approved by the FPSC annually, PGS normally has a lower percentage of under- or over-recovered gas cost than Tampa Electric.

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The table below provides a summary of PGS’s revenue and expenses and therm sales by customer type.

Summary of Operating Results

(millions, except customers)	2017		% Change			2016		% Change			2015
Revenues	$	438		(0	)	$	439		8		$	407
Cost of gas sold		153		(4	)		159		17			136
Operating expenses		201		(5	)		211		5			201
Operating income	$	84		22		$	69		(1	)	$	70
Net income	$	43		23		$	35		0		$	35
Therms sold – by customer segment
Residential		77		(1	)		78		4			75
Commercial		489		0			488		4			471
Industrial		330		3			321		11			289
Off-system sales		201		(18	)		245		48			166
Power generation		750		(1	)		760		0			758
Total		1,847		(2	)		1,892		8			1,759
Therms sold – by sales type
System supply		303		(13	)		347		29			269
Transportation		1,544		(0	)		1,545		4			1,490
Total		1,847		(2	)		1,892		8			1,759
Customer (thousands) – at December 31(1)		378		3			368		3			359

(1) The number of 2016 and 2015 customers reflects an updated customer count methodology due to the implementation of a new Customer Relationship Management and Billing System in the first quarter of 2017.

See Business-Peoples Gas System-Competition for information regarding PGS’s transportation-only customers.

PGS Outlook

In 2018, PGS expects customer growth at rates higher than those experienced in 2017, reflecting its expectations that the housing markets in many areas of the state will continue to grow, allowing for new and existing gas main opportunities. Assuming normal weather, therm sales to customers, especially residential and commercial customers, are expected to increase in 2018. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense in 2018 is expected to be higher than in 2017, driven by an increase in technology related costs and additional expense necessary to safely and reliably operate and maintain a growing distribution system. Depreciation and amortization expense is expected to be relatively flat due to an increase in depreciation from asset growth, partially offset by lower environmental amortization (see Note 3 to the 2017 Annual TEC Consolidated Financial Statements).

In 2018, PGS expects capital spending to increase to support residential and commercial customer growth, system expansion to serve large commercial and industrial customers, continued interest in LNG facilities and conversion of vehicle fleets to CNG and replacement of cast iron, bare steel pipe and other problematic pipe deemed obsolete by the Pipeline Safety and Hazardous Materials Administration.

Complementing the strong residential construction market is the PGS business model that focuses on extending the system to serve large commercial or industrial customers that are currently using petroleum or propane as fuel. The current relatively low natural gas prices and the lower emissions levels from using natural gas compared to other fuels, make it attractive for these customers to convert from other fuels.

PGS anticipates earnings within the allowed ROE range in 2018 and expects earnings and rate base growth as a result of continued customer growth and expansion of the PGS system.

OTHER ITEMS IMPACTING NET INCOME

Other Income, Net

Other income, net was $10 million, $31 million and $20 million in 2017, 2016 and 2015, respectively, and included AFUDC-equity and other items and services. AFUDC-equity at Tampa Electric was $2 million, $24 million and $17 million in 2017, 2016 and 2015, respectively. The 2017 decrease and 2016 increase in AFUDC-equity is due to Tampa Electric’s Polk Power Station expansion

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being placed in service in January 2017. In addition, other income, net increased in 2016 compared to 2015 due to a loss on disposition that occurred in 2015.

Interest Expense

In 2017, interest expense, excluding AFUDC-debt, was $120 million compared to $117 million in 2016 and $118 million in 2015. In 2017, interest expense increased, reflecting higher short-term interest rates and balances. In 2016, interest expense was similar to 2015 due to no new debt issuances at TEC and similar short-term borrowing levels.

Interest expense is expected to increase in 2018, reflecting higher interest rates and balances.

Income Taxes

The provision for income taxes increased in 2017, primarily due to higher pre-tax income and lower tax benefits related to AFUDC-equity, the production deduction and R&D tax credits.  Income tax expense as a percentage of income before taxes was 38.4% in 2017, 34.8% in 2016 and 37.5% in 2015. We expect our 2018 annual effective tax rate to be approximately 25.0%. The expected decrease is mainly due to the federal corporate tax rate deduction from 35% to 21% provided in the U.S. Tax Cuts and Jobs Act of 2017, which was enacted on December 22, 2017.

Prior to July 1, 2016, TEC was included in a consolidated U.S federal income tax return with TECO Energy and subsidiaries. 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. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with TECO Energy’s and EUSHI’s respective tax sharing agreements. The cash payments (refunds) for federal income taxes and state income taxes made under those tax sharing agreements totaled $13 million, $(3) million and $64 million in 2017, 2016 and 2015, respectively. The cash payments (refunds) mainly differ year over year due to pre-tax income and timing of bonus depreciation deductions.

For more information on our income taxes, including a reconciliation between the statutory federal income tax rate, the effective tax rate and impacts of tax reform, see U.S. Tax Reform above and Note 4 to the 2017 Annual TEC Consolidated Financial Statements.

LIQUIDITY, CAPITAL RESOURCES

Balances as of December 31, 2017

(millions)
Credit facilities	$	775
Drawn amounts/LCs		306
Available credit facilities		469
Cash and short-term investments		13
Total liquidity	$	482

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Cash from Operating Activities

Cash flows from operating activities in 2017 were $612 million, a decrease of $219 million compared to 2016.  The decrease is primarily due to refunds to retail customers in 2017 for fuel clause over-recoveries collected in 2016, lower fuel clause over-recoveries collected in 2017, Hurricane Irma related costs in 2017, and payments in 2017 related to significant December 2016 accruals for products and services. Cash from operations in 2017 and 2016 also reflect pension contributions of $36 million and $31 million, respectively.

Cash from Investing Activities

Our investing activities in 2017 resulted in a net use of cash of $640 million, which primarily reflects capital expenditures. We expect capital spending in 2018 to be approximately $1.2 billion. The forecasted increase in capital expenditures compared to 2017 is primarily related to expected land and equipment purchases for solar projects. See the Capital Investments section for additional information.

Cash from Financing Activities

Our financing activities in 2017 resulted in net cash inflows of $31 million. TEC received $190 million of equity contributions from TECO Energy and $135 million of net proceeds from borrowings under credit agreements, which were partially offset by dividend payments to TECO Energy of $292 million.

Cash and Liquidity Outlook

Our tariff-based gross margins are our principal source of cash from operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash generated from operating activities, we use available cash and credit facility borrowings to support normal operations and short-term capital requirements. We may reduce our short-term borrowings with cash from operations, long-term borrowings, or capital contributions from TECO Energy. We expect to make significant capital expenditures in 2018 as we invest in new solar projects, our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to fund those capital expenditures and debt maturities with available cash on hand, cash generated from operating activities, and cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with the existing regulatory arrangements.

Cash from operating activities and short-term borrowings may be used to fund capital expenditures and other long-term investments, which may result in periodic working capital deficits. The working capital deficit as of December 31, 2017 was primarily caused by increases in short-term liabilities as a result of long-term debt due within a year and by periodic fluctuations in assets or liabilities related to FPSC clauses and riders. Any assets or liabilities related to FPSC clauses and riders are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. At December 31, 2017, our liquidity was $482 million.  

TEC has credit facilities that provide $775 million of credit, including $450 million maturing in 2018 and $325 million available to 2022. See Note 6 to the 2017 Annual TEC Consolidated Financial Statements for additional information regarding the credit facilities. TEC believes that its liquidity is adequate for both the near and long term given its expected operating cash flows, capital expenditures and related financing plans.

We expect cash from operations in 2018 to be higher than in 2017, due in large part to lower refunds to customers for prior year fuel clause over-recoveries and storm costs paid in 2017. The implementation settlement agreement authorizes Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 annual tax reform benefits, which mitigates the impacts on cash from operations in 2018 (see Note 3 to the 2017 Annual TEC Consolidated Financial Statements and the Outlook and U.S. Tax Reform sections above). We plan to use cash in 2018 to fund capital spending and to pay dividends to our shareholder, TECO Energy. Dividends are declared and paid at the discretion of TEC’s Board of Directors.

Our credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). We estimate that we could fully utilize the total available capacity under our facilities in 2018 and remain within the covenant restrictions.

TEC currently holds investment grade credit ratings from Moody’s and S&P (see Credit Ratings section). In the event TEC’s ratings were downgraded to below investment grade, counterparties to our derivative instruments could request immediate payment or full collateralization of net liability positions. If the credit risk-related contingent features underlying these derivative instruments had been triggered as of December 31, 2017, we would not have been required to post additional collateral or settle existing positions with counterparties. In addition, credit provisions in long-term gas transportation agreements would give the transportation providers the right to demand collateral, which we estimate to be approximately $70 million. None of our credit facilities or financing agreements have ratings downgrade covenants that would require immediate repayment or collateralization.

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Short-Term Borrowings

At December 31, 2017 and 2016, the following credit facilities and related borrowings existed.

	December 31, 2017						December 31, 2016
					Letters of						Letters of
	Credit		Borrowings		Credit		Credit		Borrowings		Credit
(millions)	Facilities		Outstanding(1)		Outstanding		Facilities		Outstanding(1)		Outstanding
5-year facility (2)	$	325	$	5	$	1	$	325	$	40	$	1
3-year accounts receivable facility (3)		150		0		0		150		130		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	775	$	305	$	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 on March 23, 2018.

(4) This 1-year facility matures on November 1, 2018.

These credit facilities require 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 December 31, 2017 and 2016 was 2.07% and 1.49%, respectively. For a complete description of the credit facilities see Note 6 to the 2017 Annual TEC Consolidated Financial Statements.

	Maximum		Minimum		Average		Average
	drawn		drawn		drawn		interest
(millions)	amount		amount		amount		rate
2017 credit facility utilization	$	454	$	165	$	260		1.89	%

Significant Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2017, TEC was in compliance with all applicable financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at December 31, 2017. Reference is made to the specific agreements and instruments for more details.  

			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	at December 31, 2017
Credit facility - $325 million (2)	Debt/capital	Cannot exceed 65%	45.3%
Credit facility - $300 million (2)	Debt/capital	Cannot exceed 65%	45.3%
Accounts receivable credit facility (2)	Debt/capital	Cannot exceed 65%	45.3%

(1) As defined in each applicable instrument.

(2) See Note 6 to the 2017 Annual TEC Consolidated Financial Statements for a description of the credit facilities.

Credit Ratings

	Standard & Poor’s (S&P)	Moody’s
Credit ratings of senior unsecured debt	BBB+	A3

S&P and Moody’s describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB- and for Moody’s is Baa3; thus, both credit rating agencies assign TEC’s senior unsecured debt investment-grade credit ratings.

Certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 13 to the 2017 Annual TEC Consolidated Financial Statements).

Summary of Contractual Obligations

The following table lists the obligations of TEC for cash payments to repay debt, interest payments, lease payments and unconditional commitments related to capital expenditures.

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Contractual Cash Obligations at December 31, 2017

	Payments Due by Period
(millions)	Total		2018		2019		2020		2021		2022		After 2022
Long-term debt (1)	$	2,183	$	304	$	0	$	0	$	279	$	250	$	1,350
Interest payment obligations		1,634		99		89		89		82		74		1,201
Operating leases/purchased power		56		12		2		2		2		2		36
Long-term service agreements/capital projects (2)		416		303		74		7		7		7		18
Clause recoverable commitments (3)		2,168		444		230		177		147		141		1,029
Pension plan(4)		0		0		0		0		0		0		0
Total contractual obligations	$	6,457	$	1,162	$	395	$	275	$	517	$	474	$	3,634

(1) Includes debt at Tampa Electric and PGS (see the Consolidated Statements of Capitalization and Note 7 to the 2017 Annual TEC Consolidated Financial Statements for a list of long-term debt and the respective due dates).

(2) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At December 31, 2017, these commitments include Tampa Electric’s outstanding commitments for major projects, including solar projects, and long-term capitalized maintenance agreements for its CTs.

(3) These payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases are recovered from customers under regulatory clauses approved by the FPSC (see the Business section).

(4) Under calculation requirements of the Pension Protection Act, as of the January 1, 2018 measurement date, the pension plan was fully funded. Under MAP 21, we are not required to make additional cash contributions over the next five years; however, we may make additional cash contributions from time to time.Future contributions are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by investment portfolio performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the 2017 Annual TEC Consolidated Financial Statements).

Off-Balance Sheet Arrangements and Contingent Obligations

TEC does not have any material off-balance sheet arrangements or contingent obligations not otherwise included in our Consolidated Financial Statements as of December 31, 2017.See Note 9 to the 2017 Annual TEC Consolidated Financial Statements.

Capital Investments

(millions)	Actual 2017		Forecasted 2018
Tampa Electric (1)
Transmission	$	37	$	50
Distribution		176		180
Generation		115		190
Renewable generation		109		490
Facilities, equipment, vehicles and other		64		90
Tampa Electric total		501		1,000
PGS		121		200
Net cash effect of accruals, retentions and AFUDC		18		0
Total	$	640	$	1,200

(1) Individual line items exclude AFUDC-debt and equity.

Tampa Electric’s 2017 capital expenditures included solar generation projects (see Note 3 to the TEC Consolidated Condensed Financial Statements for information related to the 600 MW solar project recoverable under the SOBRAs), the Customer Relationship Management and Billing System (CRMB), hurricane storm hardening for the transmission and distribution systems, and the maintenance and refurbishment of existing generating facilities. In 2018, Tampa Electric expects capital expenditures related to solar generation projects, new technology for distribution system modernization and automated metering equipment.

Capital expenditures in 2017 for PGS included maintenance of the existing system, expansion of the system and replacement of cast iron, bare steel and obsolete plastic pipe. PGS expects to invest in 2018 for projects associated with customer growth, system expansion and construction of CNG, renewable natural gas and combined heat and power facilities.  The remainder of PGS’s capital expenditure forecast for 2018 includes amounts related to ongoing renewal, replacement and system safety, including the replacement

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of cast iron, bare steel and obsolete plastic pipe, which is recovered through a rider clause (see the Business–PGS-Regulation section).

The forecasted capital expenditures shown above are based on our current estimates and assumptions. Actual capital expenditures could vary materially from these estimates due to changes in and timing of projects and changes in costs for materials or labor (see the Risk Factors section).

Capital Structure

At December 31, 2017, TEC’s year-end capital structure was 45% debt and 55% common equity. At December 31, 2016, TEC’s year-end capital structure was 46% debt and 54% common equity.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the 2017 Annual TEC Consolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.

Deferred Income Taxes

We use the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes measured at enacted rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or the entire deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized. At December 31, 2017, we had a net deferred income tax liability of $825 million, attributable primarily to property-related items. This amount reflects the impact of the U.S. Tax Cuts and Jobs Act of 2017.

The FASB has guidance that prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. See further discussion of uncertainty in income taxes, impacts of tax reform and other tax items in Note 4 to the 2017 Annual TEC Consolidated Financial Statements.

Employee Postretirement Benefits

TEC is a participant in the retirement plans of TECO Energy. TECO Energy sponsors a defined benefit pension plan (pension plan) and a fully-funded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management. TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. The accounting related to employee postretirement benefits is a critical accounting estimate for TEC for the following reasons: 1) a change in the estimated benefit obligation could have a material impact on reported assets, liabilities and results of operations; and 2) changes in assumptions could change the annual pension funding requirements, which could have a significant impact on TEC’s annual cash requirements.

Several statistical and other factors which attempt to anticipate future events are used in calculating the expenses and liabilities related to these plans. Key factors include assumptions about the expected rates of return on plan assets, discount rates and mortality rates. TECO Energy management (Management) determines these factors within certain guidelines and with the help of external consultants. Management considers market conditions, including changes in investment returns and interest rates, in making these assumptions.

Pension plan assets (plan assets) are invested in a mix of equity and fixed-income securities. The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with the company’s portfolio, with provision for active management and expenses paid from the trust that holds the plan assets. The expected return on assets was 7.00% during 2017, 2016 and 2015. Given recent strong capital market returns and market

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expectations for continued low long-term interest rates, management expects to decrease the expected return on assets to 6.85% for 2018. Actual earned returns in 2017 were 19%.

The discount rate assumption used to measure the 2017 benefit expense and the benefit expense from July 1, 2016 through December 31, 2016 was an above-mean yield curve. As a result of the Merger, effective July 1, 2016, TECO Energy remeasured its employee postretirement benefit plans. As part of the remeasurement and to align discount rate methodologies with Emera, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year.

TECO Energy previously used a bond model matching technique to determine its discount rate. The discount rate assumption used to determine the 2016 benefit expense through June 30, 2016, the 2015 benefit expense and December 31, 2015 benefit obligation was based on a cash-flow matching technique developed by our outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by Moody’s) corporate bonds available from the Bloomberg Finance LP database at the measurement dates to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 remeasurement, TECO Energy used a discount rate of 3.72% for pension benefits under its qualified pension plan and 3.85% for its other postretirement benefits plans. For the December 31, 2017 measurement, TECO Energy used a discount rate of 4.16% for pension benefits under its qualified plan and 4.28% for its other postretirement benefits.

Holding all other assumptions constant, a 1% decrease in the assumed rate of return on pension plan assets or the discount rate assumption would have had in 2017 and is anticipated to have in 2018 the following impact on TEC’s after-tax pension cost:

Year	1% Decrease in Assumed Expected Return on Assets	1% Decrease in Assumed Discount Rate
2017	$3 million increase	$1 million increase
2018(1)	$4 million increase	$2 million increase

(1)     Tax impact reflects the tax rates in effect for 2018 and beyond.

On October 27, 2014, the Society of Actuaries (SOA) released its final report on the RP-2014 mortality tables. The MP-2014 improvement scale assumes an ultimate improvement rate of 1.00% and an ultimate long-term rate of improvement over a 20-year period. Based upon an evaluation of the information provided by the SOA related to the RP-2014 tables and data provided by the Social Security Administration, TECO Energy has determined that the SOA mortality tables are not the most appropriate mortality tables to be used in valuing its postretirement benefit plans. Beginning with the 2014 year-end measurement, TECO Energy utilized a table that is based on the SOA RP-2014 mortality but adjusts it to remove the post-2007 projections for its base scale. For the 2014 and 2015 year-end measurements, TECO Energy used a mortality projection scale that utilizes the same data and methodology used in the SOA-developed scale but modifies it to use a 0.75% ultimate annual improvement rate and a 10-year grade-down period. In 2015, 2016 and 2017, the SOA updated the projection scale. For mortality improvements reflected in the 2016 and 2017 year-end measurements, TECO Energy used an updated projection scale based on the SOA’s 2016 scale but, again, with a shorter grade-down period and lower ultimate rates of mortality improvement. TECO Energy believes these tables are more appropriate and reflective of its population.

Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 12 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions.

TECO Energy’s policy is to fund the plan based on the required contribution determined by its actuaries within the guidelines set by the ERISA, as amended. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability.

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TECO Energy currently provides certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. TECO Energy implemented an EGWP for its post-65 retiree prescription drug plan effective January 1, 2013. The EGWP was a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduced net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act (combined the Health Care Reform Acts), which were greater than subsidy payments previously received under Medicare Part D for the post-65 retiree prescription drug plan. Effective January 1, 2015, TECO Energy changed its post-65 retiree coverage for medical benefits to a Medicare Advantage plan insured by Aetna in order to take advantage of the government subsidies available for the plan.

The Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits, including a provision that imposes an excise tax on certain high-cost plans beginning in 2020, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially impact its postretirement benefit obligation. TECO Energy will continue to monitor and assess the potential impact of the Health Care Reform Acts on our future results of operations, cash flows or financial position.

The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. TECO Energy determines the discount rate for the OPEB’s projected benefit cash flows. In estimating the health care cost trend rate, TECO Energy considers its actual health care cost experience, future benefit structures, industry trends, and advice from our outside actuaries. TECO Energy assumes that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industrywide cost-containment initiatives.

TECO Energy’s Florida-based plan’s assumed health care cost trend rate for medical costs was 6.83% during 2017 and graded down to 6.58% for the December 31, 2017 measurement.  This rate, over time, is projected to decrease to 4.50% in 2038 and thereafter. A 1% increase in the health care trend rates would result in an after-tax increase in the aggregate service and interest cost of less than $1 million for 2017 and 2018.  

The actuarial assumptions used in determining TECO Energy’s pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.

See the discussion of employee postretirement benefits in Note 5 to the 2017 Annual TEC Consolidated Financial Statements.

Regulatory Accounting

Tampa Electric’s and PGS’s retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. As a result, the regulated utilities qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between U.S. GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.

We regularly assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered.

TEC’s most significant regulatory liability relates to non-ARO costs of removal and regulatory tax liability. The non-ARO costs of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment upon retirement. TEC accrues for removal costs over the life of the related assets based on depreciation studies approved by the FPSC. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. The regulatory tax liability is the offset to the adjustment to the deferred tax liability remeasured as a result of tax reform. See Note 4 to the 2017 Annual TEC Consolidated Financial Statements for further information.

The application of regulatory accounting guidance is a critical accounting policy since a difference in these assumptions and actual results may result in a material impact on reported assets and the results of operations (see the Regulation section in Item 1. Business and Note 3 to the 2017 Annual TEC Consolidated Financial Statements).

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RECENTLY ISSUED ACCOUNTINGSTANDARDS

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2017, are described as follows:

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued Accounting Standard Update (ASU) 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach.  TEC has early adopted the standard, with no impact on the consolidated financial statements as a result of implementation of this standard.

Future Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB, but have not yet been adopted by TECO Energy.  Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, codified as ASC Topic 606.  The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients.  The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption.  TEC will adopt this guidance effective January 1, 2018, using the modified retrospective approach.

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 completed an analysis of material unregulated revenue streams and concluded that there will be no material changes on adoption of this standard.  TEC also 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.  The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC will adopt this guidance effective January 1, 2018 and does not expect an impact on the consolidated financial statements as a result of implementation of this standard.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases.  The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months.  Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet.  The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018.  Early adoption is permitted and is required to be applied using a modified retrospective approach.  

In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in the first quarter of 2018.  

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TEC is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures.  In the third quarter of 2017, TEC implemented a project plan.  In the fourth quarter of 2017, TEC began execution of the project plan, including training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements.  This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements.  TEC continues to monitor FASB amendments to ASC Topic 842.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures.  The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts.  The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators.  

This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019.  Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach.  TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business.  The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted and is required to be applied prospectively.  The adoption of this standard will not have an impact on TEC’s consolidated financial statements.

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.  The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs.  The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations.  Only the service cost component will be eligible for capitalization as property, plant and equipment under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC is a participant in the comprehensive retirement plans of TECO Energy and applies multiemployer accounting. This new guidance will not impact accounting for multiemployer plans, therefore, it will not impact TEC’s financial statements.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815.  This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting.  The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach.  TEC is currently evaluating the impact of the adoption of this standard on the consolidated financial statements and does not expect the impact to be significant.

 ENVIRONMENTAL COMPLIANCE

Environmental Matters

TEC has significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters. TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites.

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Emission Reductions

Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.

The emission-reduction requirements of several agreements negotiated in 1999 resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Station to help reduce SO₂ emissions, and installation of SCR systems for NOx reduction on Big Bend Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC (see the Business-Tampa Electric-Regulation section). Cost recovery for the repowering of the Bayside Power Station was accomplished in Tampa Electric’s 2008 rate case.

Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% from 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system-wide reduction of mercury emissions of more than 90% from 1998 levels.

CAIR/CSAPR

As a result of all its completed emission reduction actions, Tampa Electric achieved the emission-reduction levels called for in Phase I and Phase II of CAIR. On July 7, 2011, EPA released its final CAIR-replacement rule, called Cross-State Air Pollution Rule (CSAPR). An update to CSAPR was finalized on October 26, 2016 and was implemented in 2017. Based on updated EPA modeling, Florida is no longer subject to CSAPR requirements.  However, Florida (including TEC power plants) could be subject to a future version of CSAPR as a result of an expected update triggered by compliance with the more stringent 2015 ozone standard (which is described below) or ongoing litigation relating to current rule applicability.  On August 23, 2017, the Florida Department of Environmental Protection submitted to EPA a proposed Infrastructure State Implementation Plan to confirm that Florida is meeting its cross-state air transport obligations under the Clean Air Act.

Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) Mercury Air Toxics Standards (MATS)

The EPA published proposed rules under National Emission Standards for HAPS on May 3, 2011, pursuant to a court order. The final Utility MACT rules, called Mercury Air Toxics Standards (MATS), were published in December 2011 and compliance was required by April 16, 2015.

On June 29, 2015, the U.S. Supreme Court remanded the EPA’s MATS to the U.S. District of Columbia Circuit Court (the D.C. Circuit Court) for failing to properly consider the cost of compliance. The litigation is currently in abeyance while EPA reconsiders its action. MATS remains in effect until the D.C. Circuit Court acts.

All of Tampa Electric’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric has minimized the impact of this rule and has demonstrated compliance on all applicable units with the most stringent “Low Emitting Electric Generating Unit” classification for MATS with nominal additional capital investment.

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO₂ by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO₂ to remain near 1990 levels even after the addition of the newest base load unit, which was placed in service in January 2017 (see the Tampa Electric and Capital Investments sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO₂ emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 34% and 18%, respectively.

In June 2013, President Obama announced his Climate Action Plan, a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17% below 2005 levels by 2020. On June 2, 2014, the EPA released a comprehensive proposed rule to limit GHG emissions from existing power plants. The EPA’s final rule, the Clean Power Plan (CPP), was signed by

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the Administrator of the EPA on August 3, 2015 and set emission performance goals that would cut GHG emissions from existing power plants by an average across all states of 32% from their 2012 levels by 2030, with an interim goal for the period from 2022 through 2029.

In January 2016, the U.S. Court of Appeals for the District of Columbia Circuit denied requests by 27 states and numerous trade groups that would have barred the EPA from implementing the carbon regulations for the electricity sector.  However, in February 2016, the U.S. Supreme Court issued a stay against enforcement of the CPP for the electricity sector pending resolution of the legal challenges before the U.S. Court of Appeals for the District of Columbia Circuit. The timing of the resolution of the legal challenges and the removal of the stay by the U.S. Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018 or later. In addition, on March 28, 2017 President Trump issued an Executive Order calling for the review of the CPP and the New Source Performance Standards and suspend, revise or rescind the rule if appropriate.  

In response to the Trump Executive Order, on October 10, 2017, EPA Administrator Pruitt issued a notice of proposed rulemaking to repeal the CPP in its entirety. EPA has proposed that the regulation exceeds EPA’s statutory authority and is taking comments due by February 28, 2018. EPA proposed to repeal the CPP in its entirety because, even though some parts of the CPP do not exceed the EPA's authority, those portions are not severable and separately implementable, and "it is not appropriate for a rule that exceeds statutory authority...to remain in existence pending a potential, successive rulemaking process."  EPA also proposed to repeal the legal memorandum that accompanied the CPP, since the memorandum helped form the legal basis for the rule.

Florida has not begun any CPP rulemaking process and is currently awaiting final resolution of the legal challenges and EPA efforts before proceeding with state rulemaking.  Tampa Electric is evaluating a number of potential compliance scenarios, but there is no Florida initiative to develop a final compliance plan. The outcome of this litigation and the rule-making process and its impact on TEC’s businesses is therefore uncertain at this time; however, it could result in increased operating costs, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on how the state plan could be developed and implemented, the Clean Power Plan could cause an increase in costs or rates charged to customers, which could curtail sales. See Item 1A - Risk Factors.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding.

Ozone

On September 30, 2015 in response to a court order, the EPA published a final rule revising the ground level ozone standard to 70 parts per billion from the previous level of 75 parts per billion.  On September 30, 2016, the Florida Department of Environmental Protection submitted its recommendation that the entire State of Florida be designated as “attainment” for the 2015 standard. On June 6, 2017, EPA Administrator Pruitt sent letters to state governors announcing that the EPA is extending, by one year, the October 2017 deadline for promulgating initial area designations for the 2015 national ambient air quality standard for ozone. Litigation regarding the stringency of the rule is currently in abeyance. The impact of this new standard on the operations of Tampa Electric will depend on the outcome of litigation or other developments.

Water Supply and Quality

The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to both Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on Waters of the U.S. Tampa Electric has two ongoing projects (one for Bayside and one for Big Bend) to negotiate scheduling with FDEP and to complete the biological, technical, and financial study elements necessary to comply with the rule. These study elements will ultimately be used by FDEP to determine the necessity of cooling water system retrofits for Big Bend and Bayside Power Stations. The full impact of the new regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.

The final EPA rule for existing steam electric effluent limit guidelines became effective January 4, 2016 and establishes limits for wastewater discharges from flue gas desulfurization (FGD) processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing coal combustion residuals, gasification processes, and flue gas mercury controls. The new guidelines are expected to be incorporated into National Pollutant Discharge Elimination System permit renewals for Big Bend Station (FGD wastewater and bottom ash transport water) and Polk Power Station (gasification wastewater) to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023. EPA decided to extend the near-term deadlines for FGD waste water and bottom ash transport water to as soon as possible after November 1, 2020, while those limits are under consideration. Gasification limits are not under consideration, and Polk Power Station will be expected to achieve compliance in accordance with the original dates.

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EPA Waters of the US

In June 2015, the U.S. Army Corps of Engineers (Corps) and the EPA issued a rule defining “Waters of the United States” (WOTUS) for purposes of federal Clean Water Act (CWA) jurisdiction. The final rule took effect on August 28, 2015. The rule has the effect of defining the scope of agency jurisdiction under the CWA very broadly. In August 2015, a federal judge in North Dakota issued an injunction against the implementation of the rule in certain states. In October 2015, the Sixth Circuit Court of Appeals issued a nationwide stay of WOTUS, effectively ending the implementation of the rule in the 37 states that were not subject to the prior injunction.  This stay is temporary, pending the outcome of litigation.  On February 28, 2017, President Trump issued an Executive Order directing the EPA and the Corps to review the rule. EPA proposed new rulemaking, published in the Federal Registeron November 22, 2017, to revise the definition of WOTUS and to add an applicability date to the 2015 Clean Water Rule.  

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 manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 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 “Other” 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 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. See Note 3 to the 2017 Annual TEC Consolidated Financial Statements for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this liability.

Coal Combustion Residuals Recycling and Disposal

Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk Power stations. An annual average of 95% of all CCRs produced at these facilities is marketed to customers for beneficial use in commercial and industrial products.

EPA’s final CCR rule became effective on October 19, 2015 and regulates CCRs as non-hazardous solid waste. On February 2, 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for recovery of certain capital and O&M expenses through the Environmental Cost Recovery Clause (ECRC). On December 12, 2017, the FPSC approved an additional petition for recovery of expenses associated with the closure of the Big Bend economizer ash and pyrite ponds, which is scheduled to begin in 2018. Additional petitions may be submitted for recovery of future capital project expenses based on engineering studies currently being performed. On December 10, 2016, Congress passed the Water Infrastructure Improvements for the Nation (WIIN) Act, which contains language modifying the implementation plan for the federal CCR Rule.  Under the WIIN Act, state programs would be approved and overseen by EPA, thus placing compliance and enforcement authority in the hands of the EPA and the states. See Note 16 to the 2017 Annual TEC Consolidated Financial Statements for information regarding the estimated impact on Tampa Electric’s AROs.

Conservation

Energy conservation is becoming more important in the GHG emissions reduction debate. Tampa Electric supports the FPSC and its efforts to encourage energy efficiency. In 2016, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled it to meet its required Demand Side Management (DSM) goals, reduce weather-sensitive peak demand and conserve energy. This strategy continues to allow Tampa Electric to delay construction of future generation facilities. Since their inception, TEC’s conservation programs have contributed to reducing the summer peak demand by 685 MW and the winter peak demand by 1,184 MW.

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In November 2014, the FPSC established new DSM goals for the 10-year period from 2015 to 2024 for all Florida investor-owned electric utilities. In 2016, Tampa Electric continued with the new 2015-2024 DSM plan that was fully implemented in November 2015. This DSM plan supports the approved FPSC goals which are reasonable, beneficial and cost-effective to all customers as required by the Florida Energy Efficiency & Conservation Act.  For Tampa Electric, the summer and winter demand goals are 56.3 and 78.3 MWs, respectively, and the energy goal is 144.3 gigawatt-hours over the 10-year period. Establishing these DSM goals for the 10-year period is required every five years. Tampa Electric met all the annual and incremental DSM goals for 2016 and in May, completed the phased final closure of the “Prime Time” program which was its direct load control Residential Load Management Program. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. In addition, PGS offers conservation programs that enable customers to reduce their energy consumption, with those costs recovered through a clause on the customer’s gas bill. 

REGULATION

See the Business section (Tampa Electric – Electric Operations and Peoples Gas System – Gas Operations sections)and Note 3 to the 2017 Annual TEC Consolidated Financial Statements for a description of the utilities’ base rates, cost-recovery clauses and competition.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Infrastructure

TEC is subject to various types of market risk in the course of daily operations, as discussed below. TEC has adopted an enterprise wide approach to the management and control of market and credit risk. Middle Office risk management functions, including credit risk management and risk control, are independent of each transacting entity (Front Office).

TEC’s Risk Management Policy (Policy) governs all energy transacting activity. The Policy is approved by TECO Energy’s board of directors and administered by a Risk Authorizing Committee (RAC) that is comprised of senior management. Within the bounds of the Policy, the RAC approves specific hedging strategies, new transaction types or products, limits, and transacting authorities. Transaction activity is reported daily and measured against limits. For all commodity risk management activities, derivative transaction volumes are limited to the anticipated volume for customer sales or supplier procurement activities.

The RAC also administers the Policy with respect to interest rate risk exposures. Under the Policy, the RAC operates and oversees transaction activity. Interest rate derivative transaction activity is directly correlated to borrowing activities.

Risk Management Objectives

The Front Office is responsible for reducing and mitigating the market risk exposures that arise from the ownership of physical assets and contractual obligations, such as debt instruments and firm customer sales contracts. The primary objectives of the risk management organization, the Middle Office, are to quantify, measure, and monitor the market risk exposures arising from the activities of the Front Office and the ownership of physical assets. In addition, the Middle Office is responsible for enforcing the limits and procedures established under the approved risk management policies. Based on the policies approved by the company’s board of directors and the procedures established by the RAC, from time to time, our companies enter into futures, forwards, swaps and option contracts to limit the exposure to items such as:

• Price fluctuations for physical purchases and sales of natural gas in the course of normal operations; and

• Interest rate fluctuations on debt.

Our companies use derivatives only to reduce normal operating and market risks, not for speculative purposes. Our primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers.

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 includes a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022. The FPSC approved the agreement on November 6, 2017 (see Note 3 to the 2017 Annual TEC Consolidated Financial Statements).

Fair Value Measurements

The accounting standards for fair value measurement define fair value, establish a framework for measuring fair value under U.S. GAAP, and expand disclosures about financial assets and liabilities carried at fair value. The majority of TEC’s financial assets and liabilities are in the form of natural gas or interest rate derivatives classified as cash flow hedges.

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Natural gas derivatives were entered into by TEC to manage the impact of natural gas prices on customers. As a result of applying the provisions of accounting standards for regulated activities, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel recovery clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

The valuation methods we used to determine fair value are described in Note 14 to the 2017 Annual TEC Consolidated Financial Statements.

Credit Risk

TEC has a rigorous process for the establishment of new trading counterparties. This process includes an evaluation of each counterparty’s financial statements, with particular attention paid to liquidity and capital resources; establishment of counterparty specific credit limits; optimization of credit terms; and execution of standardized enabling agreements. TEC’s Credit Risk Guidelines, which are approved by the RAC, require transactions with counterparties below investment grade to be collateralized.

Contracts with different legal entities affiliated with the same counterparty are consolidated for credit purposes and managed as appropriate, considering the legal structure and any netting agreements in place. Credit exposures are calculated, compared to limits and are made available to management on a daily basis. The Credit Risk Guidelines are administered and monitored within the Middle Office, independent of the Front Office.

TEC has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions.

Certain of TEC’s derivative instruments contain provisions that require our debt to maintain an investment-grade credit rating from any or all of the major credit rating agencies. If TEC’s debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features were in a liability position of $1 million on December 31, 2017.

Interest Rate Risk

TEC is exposed to changes in interest rates primarily as a result of our borrowing activities. TEC may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of December 31, 2017 and 2016, a hypothetical 10% increase in TEC’s weighted-average interest rate on its variable rate debt during the subsequent year would not result in a material impact on pre-tax earnings. This is driven by the low amounts of variable rate debt at TEC. A hypothetical 10% decrease in interest rates would increase the fair market value of our long-term debt by 4.0% at December 31, 2017 and 4.4% at December 31, 2016. See the Financing Activity section and Notes 6 and 7 to the 2017 Annual TEC Consolidated Financial Statements. These amounts were determined based on the variable rate obligations existing on the indicated dates at TEC. The above sensitivities assume no changes to our financial structure and could be affected by changes in our credit ratings, changes in general economic conditions or other external factors (see the Risk Factors section).

Commodity Risk

TEC faces varying degrees of exposure to commodity risks including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risks.

Regulated Utilities

Tampa Electric’s fuel costs used for generation are affected primarily by the price of natural gas and, to a lesser degree, the cost of coal, oil and petcoke. Tampa Electric’s use of natural gas, with its more volatile pricing, for generation of electricity increased to 69% in 2017 from 56% in 2016 (see the Business section). PGS has exposure related to the price of purchased gas and pipeline capacity.

Currently, TEC’s commodity price risks are largely mitigated by the fact that increases in the price of prudently incurred fuel and purchased power are recovered through FPSC approved cost-recovery clauses, with no anticipated effect on earnings. However, increasing fuel cost-recovery has the potential to affect total energy usage and the relative attractiveness of electricity and natural gas to consumers. TEC manages commodity price risk by entering into long-term fuel supply agreements, prudently operating plant

39

facilities to optimize cost, and prior to the moratorium mentioned above, entering into derivative transactions designated as cash flow hedges of anticipated purchases of wholesale natural gas. At December 31, 2017 and 2016, a change in commodity prices would not have had a material impact on earnings for Tampa Electric or PGS, but could have had an impact on the timing of the cash recovery of the cost of fuel (see the Tampa Electric and Regulation sections above).

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to settlements of natural gas swaps and a decrease in the average market price component of TEC’s outstanding natural gas swaps of approximately 6% from December 31, 2016 to December 31, 2017. TEC decreased by 79% the natural gas volume hedged as of December 31, 2017 as compared to December 31, 2016.

The following tables summarize the changes in and the fair value balances of TEC’s derivative assets (liabilities) for the year ended December 31, 2017:

Changes in Fair Value of Derivatives (millions)

Net fair value of derivatives as of December 31, 2016	$	17
Additions and net changes in unrealized fair value of derivatives		(16	)
Changes in valuation techniques and assumptions		0
Realized net settlement of derivatives		(2	)
Net fair value of derivatives as of December 31, 2017	$	(1	)

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

Total derivative net assets/(liabilities) as of December 31, 2016	$	17
Change in fair value of net derivatives:
Recorded as regulatory assets and liabilities or other comprehensive income		(16	)
Recorded in earnings		0
Realized net settlement of derivatives		(2	)
Total derivative net assets/(liabilities) as of December 31, 2017	$	(1	)

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

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TAMPA ELECTRIC COMPANY

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholder of Tampa Electric Company:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and statements of capitalization of Tampa Electric Company and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of income and comprehensive income, of cash flows and of retained earnings for each of the three years in the period ended December 31, 2017, including the related notes and schedule of valuation and qualifying accounts and reserves for each of the three years in the period ended December 31, 2017 appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America.  

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits.  We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.  Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.  Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.  We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Certified Public Accountants

Tampa, Florida

February 9, 2018

We have served as the Company's auditor since at least 1934.  We have not determined the specific year we began serving as auditor of the Company.

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TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets	December 31,			December 31,
(millions)	2017			2016
Property, plant and equipment
Utility plant in service
Electric	$	8,555		$	7,624
Gas		1,609			1,503
Construction work in progress		263			892
Utility plant in service, at original costs		10,427			10,019
Accumulated depreciation		(2,994	)		(2,826	)
Utility plant in service, net		7,433			7,193
Other property		11			10
Total property, plant and equipment, net		7,444			7,203
Current assets
Cash and cash equivalents		13			10
Receivables, less allowance for uncollectibles of $1 at December 31, 2017 and 2016		257			206
Due from affiliates		5			7
Inventories, at average cost
Fuel		60			77
Materials and supplies		90			86
Current derivative assets		0			15
Regulatory assets		77			28
Prepayments and other current assets		13			21
Total current assets		515			450
Deferred debits
Regulatory assets		356			393
Other		49			37
Total deferred debits		405			430
Total assets	$	8,364		$	8,083

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

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TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets—continued

Liabilities and Capital	December 31,			December 31,
(millions)	2017			2016
Capitalization
Common stock	$	2,645		$	2,456
Accumulated other comprehensive loss		(2	)		(3	)
Retained earnings		335			311
Total capital		2,978			2,764
Long-term debt, less amount due within one year		1,860			2,163
Total capital		4,838			4,927
Current liabilities
Long-term debt due within one year		304			0
Notes payable		305			170
Accounts payable		233			262
Due to affiliates		21			25
Customer deposits		131			146
Regulatory liabilities		58			154
Accrued interest		14			16
Accrued taxes		12			12
Other		44			11
Total current liabilities		1,122			796
Long-term liabilities
Deferred income taxes		825			1,407
Regulatory liabilities		1,227			591
Deferred credits and other liabilities		352			362
Total deferred credits		2,404			2,360
Commitments and Contingencies (see Note 9)
Total liabilities and capital	$	8,364		$	8,083

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Income and Comprehensive Income

(millions)
For the years ended December 31,	2017			2016			2015
Revenues
Electric	$	2,052		$	1,964		$	2,018
Gas		418			432			401
Total revenues		2,470			2,396			2,419
Expenses
Fuel		588			561			639
Purchased power		46			104			79
Cost of natural gas sold		153			159			135
Operations & maintenance		513			538			529
Depreciation and amortization		350			328			313
Taxes, other than income		198			193			192
Total expenses		1,848			1,883			1,887
Income from operations		622			513			532
Other income
Allowance for other funds used during construction		2			24			17
Other income, net		8			7			3
Total other income		10			31			20
Interest charges
Interest expense		120			117			118
Allowance for borrowed funds used during construction		(1	)		(11	)		(8	)
Total interest charges		119			106			110
Income before provision for income taxes		513			438			442
Provision for income taxes		197			152			166
Net income		316			286			276
Other comprehensive income, net of tax
Gain on cash flow hedges		1			1			4
Total other comprehensive income, net of tax		1			1			4
Comprehensive income	$	317		$	287		$	280

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

44

TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

(millions)
For the years ended December 31,	2017			2016			2015
Cash flows from operating activities
Net income	$	316		$	286		$	276
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		350			328			313
Deferred income taxes and investment tax credits		192			87			120
Allowance for equity funds used during construction		(2	)		(24	)		(17	)
Deferred recovery clauses		(83	)		54			26
Receivables, less allowance for uncollectibles		(43	)		18			(3	)
Inventories		13			16			(21	)
Taxes accrued		(9	)		68			(17	)
Accounts payable		(16	)		63			(27	)
Regulatory assets and liabilities		(100	)		(11	)		(9	)
Other(2)		(6	)		(54	)		(33	)
Cash flows from operating activities		612			831			608
Cash flows from investing activities
Capital expenditures(1)		(640	)		(727	)		(687	)
Net proceeds from sale of assets		0			9			0
Cash flows used in investing activities		(640	)		(718	)		(687	)
Cash flows from financing activities
Equity contributions from TECO Energy		190			150			175
Proceeds from long-term debt issuance		0			0			251
Repayment of long-term debt		0			(83	)		(83	)
Net change in short-term debt (maturities of 90 days or less)		(165	)		109			3
Proceeds from other short-term debt (maturities over 90 days)		300			0			0
Dividends to TECO Energy		(292	)		(289	)		(268	)
Other financing activities		(2	)		1			0
Cash flows from/(used in) financing activities		31			(112	)		78
Net increase (decrease) in cash and cash equivalents		3			1			(1	)
Cash and cash equivalents at beginning of the year		10			9			10
Cash and cash equivalents at end of the year	$	13		$	10		$	9
Supplemental disclosure of cash paid (received):
Interest	$	115		$	103		$	106
Income taxes	$	13		$	(3	)	$	64
Supplemental disclosure of non-cash activities
(1) Change in accrued capital expenditures	$	(16	)	$	(9	)	$	7

     (2) The 2017 amount includes the net impact of the change in deferred taxes as a result of tax reform with an offset to a regulatory liability of $755 million.

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Retained Earnings

(millions)
For the years ended December 31,	2017		2016		2015
Balance, beginning of year	$	311	$	314	$	306
Add: Net income		316		286		276
		627		600		582
Deduct: Cash dividends on capital stock—common		292		289		268
Balance, end of year	$	335	$	311	$	314

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

46

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization

		Capital Stock Outstanding			Cash Dividends
	Current	December 31,			Paid (1)
	Redemption				Per
(millions, except share amounts)	Price	Shares	Amount		Share			Amount
Common stock - without par value
25 million shares authorized
2017 (3)	N/A	10	$	2,645		(2	)	$	292
2016 (3)	N/A	10	$	2,456		(2	)	$	289

Preferred stock – $100 par value

1.5 million shares authorized, none outstanding.

Preferred stock – no par

2.5 million shares authorized, none outstanding.

Preference stock – no par

2.5 million shares authorized, none outstanding.

(1) Quarterly dividends paid on February 15, May 15, August 15 and November 29 during 2017.

Quarterly dividends paid on February 29, May 27, June 29 and November 10 during 2016.

(2) Not meaningful.

(3) TECO Energy made equity contributions to TEC of $190 million in 2017 and $150 million in 2016.

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

At December 31, 2017 and 2016, TEC had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2017			2016
Tampa Electric	Installment contracts payable (1) :
	5.65% Refunding bonds	2018	$	54		$	54
	Notes (2)(3) : 6.10%	2018		200			200
	5.40%	2021		232			232
	2.60%	2022		225			225
	6.55%	2036		250			250
	6.15%	2037		190			190
	4.10%	2042		250			250
	4.35%	2044		290			290
	4.20%	2045		230			230
	Total long-term debt of Tampa Electric			1,921			1,921
PGS	Notes (2)(3) : 6.10%	2018		50			50
	5.40%	2021		47			47
	2.60%	2022		25			25
	6.15%	2037		60			60
	4.10%	2042		50			50
	4.35%	2044		10			10
	4.20%	2045		20			20
	Total long-term debt of PGS			262			262
Total long-term debt of TEC				2,183			2,183
Unamortized debt discount, net				(3	)		(3	)
Debt issuance costs				(16	)		(17	)
Total carrying amount of long-term debt				2,164			2,163
Less amount due within one year				304			0
Total long-term debt			$	1,860		$	2,163

(1)   Tax-exempt securities.

(2)   These senior unsecured debt securities are subject to redemption in whole or in part, at any time, at the option of the issuer.

(3)   These long-term debt agreements contain various restrictive covenants.

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization—continued

At December 31, 2017, long-term debt had a carrying amount of $2,164 million and an estimated fair market value of $2,412 million. At December 31, 2016, 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 $55 million and $58 million at December 31, 2017 and 2016, respectively. The fair value of the remaining debt securities is determined using Level 2 measurements(see Note 14 for information regarding the fair value hierarchy).  

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt for the years 2018 through 2022 and thereafter are as follows:

Long-Term Debt Maturities

													Total
As of December 31, 2017													Long-Term
(millions)	2018		2019		2020		2021		2022		Thereafter		Debt
Tampa Electric	$	254	$	0	$	0	$	232	$	225	$	1,210	$	1,921
PGS		50		0		0		47		25		140		262
Total long-term debt maturities	$	304	$	0	$	0	$	279	$	250	$	1,350	$	2,183

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.Significant Accounting Policies

Description of Business

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

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.

TEC is a wholly-owned subsidiary of TECO Energy, Inc. and contains electric and natural gas divisions. Intercompany balances and transactions within the divisions have been eliminated in consolidation.

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC 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. See Note 8 for further information.

Cash Equivalents

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

Property, Plant and Equipment

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

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

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2017			December 31, 2016
Electric generation	21-56 years	$	4,766		$	4,102
Electric transmission	28-77 years		859			837
Electric distribution	14-56 years		2,437			2,331
Gas transmission and distribution	15-77 years		1,534			1,429
General plant and other	8-43 years		579			438
Total cost			10,175			9,137
Less accumulated depreciation			(2,994	)		(2,826	)
Construction work in progress			263			892
Total property, plant and equipment, net		$	7,444		$	7,203

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7%, 3.5% and 3.7% for 2017, 2016 and 2015, respectively. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $332 million,

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$304 million and $306 million, respectively. See Note 3 for information regarding an agreement approved by the FPSC that, among other things, reduced PGS’s annual depreciation expense by $16 million beginning in 2016.

Tampa Electric and PGS compute depreciation and amortization using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2017, 2016 and 2015, the rate was 6.46%. Total AFUDC for the years ended December 31, 2017, 2016 and 2015 was $2 million, $36 million and $26 million, respectively. The decrease in 2017 and increase in 2016 is a result of the Polk Power Station conversion project, which was completed in January 2017.

Inventory

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

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3). TEC’s retail and wholesale businesses are regulated by the FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details, including the impacts of tax reform.

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property. As of December 31, 2017 and 2016, ITCs were $22 million and $11 million, respectively.

Revenue Recognition

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

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

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2017 and 2016, unbilled revenues of $66 million and $54 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

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Revenues and Cost Recovery

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

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-affiliates at a cost of $46 million, $104 million and $79 million, for the years ended December 31, 2017, 2016 and 2015, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Receivables and Allowance for Uncollectible Accounts

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

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $113 million, $117 million and $117 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), asset retirement obligations (see Note 16), and medical and general liability claims incurred but not reported.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2017 and 2016 ranged from 2.74% to 4.00% and 2.69% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

Reclassifications

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

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2017, are described as follows:

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

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In August 2016, the FASB issued Accounting Standard Update (ASU) 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach.  TEC has early adopted the standard, with no impact on the consolidated financial statements as a result of implementation of this standard.

Future Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB, but have not yet been adopted by TEC.  Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, codified as ASC Topic 606.  The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients.  The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption.  TEC will adopt this guidance effective January 1, 2018, using the modified retrospective approach.

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 completed an analysis of material unregulated revenue streams and concluded that there will be no material changes on adoption of this standard.  TEC also 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.  The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC will adopt this guidance effective January 1, 2018 and does not expect an impact on the consolidated financial statements as a result of implementation of this standard.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases.  The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months.  Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet.  The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018.  Early adoption is permitted and is required to be applied using a modified retrospective approach.  

In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in the first quarter of 2018.  

TEC is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures.  In the third quarter of 2017, TEC implemented a project plan.  In the fourth quarter of 2017, TEC began execution of the project plan, including training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements.  This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated

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with individual contractual arrangements and assessing the disclosure requirements.  TEC continues to monitor FASB amendments to ASC Topic 842.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures.  The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts.  The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators.  

This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019.  Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach.  TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business.  The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted and is required to be applied prospectively.  The adoption of this standard will not have an impact on TEC’s consolidated financial statements.

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.  The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs.  The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations.  Only the service cost component will be eligible for capitalization as property, plant and equipment under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC is a participant in the comprehensive retirement plans of TECO Energy and applies multiemployer accounting. This new guidance will not impact accounting for multiemployer plans, therefore, it will not impact TEC’s financial statements.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815.  This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting.  The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach.  TEC is currently evaluating the impact of the adoption of this standard on the consolidated financial statements and does not expect the impact to be significant.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. The FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Tampa Electric Base Rates-2013 Agreement

Tampa Electric’s results for the past three years reflect the stipulation and settlement agreement entered into on September 6, 2013, which resolved all matters in Tampa Electric’s 2013 base rate proceeding.

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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 provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. The agreement provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, 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 replaced the existing 2013 base rate settlement agreement described above and extended it another four years through 2021. The FPSC approved the agreement on November 6, 2017.    

The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue adjustments for the 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 SoBRAs 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 receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction.   

On December 12, 2017, TEC filed its petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the spring of 2018.

The agreement further maintains Tampa Electric’s allowed regulatory ROE and allowed equity in the capital structure and extends the rate freeze date from January 1, 2018 to December 31, 2021, subject to the same ROE thresholds. The agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. 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 agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make 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, Tropical Storm Erika, 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 cost of restoration to be approximately $105 million, of which $93 million was charged to the storm reserve, $4 million was charged to O&M expense, and $8 million was charged to capital expenditures. This reflects an update from the estimated cost of restoration of $70 million at September 30, 2017, primarily due to higher than expected mutual assistance and contractor costs. At December 31, 2017, the amount of $93 million charged to the storm reserve exceeded the $46 million balance by $47 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 petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below.

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Tampa Electric Implementation Settlement

On January 30, 2018, Tampa Electric filed a settlement agreement with the FPSC that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates stable in 2018.  If approved by the FPSC, the agreement authorizes Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. Tampa Electric’s final storm costs and final impact of tax reform on Tampa Electric’s base rates pursuant to the 2017 agreement will be determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. In addition, beginning in January 2019, Tampa Electric will reflect the full impact of tax reform on its base rates, provided that the FPSC’s determinations have been finalized. A decision is expected in March 2018.

PGS Base Rates

PGS’s base rates were established in May 2009 and reflect an allowed ROE range of 9.75% to 11.75% with base rates set at the middle of the range of 10.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital.

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 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 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 agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million of that amount would be amortized over a two-year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense. This additional amortization expense in 2017 and 2016 was offset by the decrease in depreciation expense as discussed above.  

The PGS settlement does not contain a provision for tax reform. On January 9, 2018, the Florida Office of Public Counsel filed a generic docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS.

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.

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Details of the regulatory assets and liabilities as of December 31, 2017 and 2016 are presented in the following table:

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2017		2016
Regulatory assets:
Regulatory tax asset (1)	$	45	$	86
Cost-recovery clauses - deferred balances (2)		12		8
Cost-recovery clauses - offsets to derivative liabilities (2)		1		0
Environmental remediation (3)		33		37
Postretirement benefits (4)		272		272
Storm reserve (5)		47		0
Other		23		18
Total regulatory assets		433		421
Less: Current portion		77		28
Long-term regulatory assets	$	356	$	393
Regulatory liabilities:
Regulatory tax liability (6)	$	730	$	6
Cost-recovery clauses (2)		32		112
Cost-recovery clauses - offsets to derivative assets (2)		0		17
Storm reserve (5)		0		56
Accumulated reserve—cost of removal (7)		518		547
Other		5		7
Total regulatory liabilities		1,285		745
Less: Current portion		58		154
Long-term regulatory liabilities	$	1,227	$	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 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. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. 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 the Tampa Electric Storm Restoration Cost Recovery section 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 within a 12-month period.

(6) The increase in the regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 for further information.

(7) 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.

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4. Income Taxes

On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform proposals affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. accounting standards, TEC is required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate. Additionally, under FPSC rules TEC is required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3.

TEC has provisionally revalued all deferred tax assets and liabilities, $199 million and $1,024 million, respectively, based on the rates at which they are expected to reverse in the future, which is 21% for federal tax purposes. TEC is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Provisional amounts primarily relate to the uncertainty of the application of 100% asset expensing rules after September 27, 2017. Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act.

Income Tax Expense

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.

In 2017, 2016 and 2015, TEC recorded net tax provisions of $197 million, $152 million and $166 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2017			2016		2015
Current income taxes
Federal	$	(1	)	$	53	$	38
State		6			12		8
Deferred income taxes
Federal		170			76		105
State		23			11		15
Investment tax credits, net of amortization		(1	)		0		0
Total income tax expense	$	197		$	152	$	166

For the three years presented, the overall effective tax rate differs from the 35% U.S. federal statutory rate as presented below:

Effective Income Tax Rate

(millions)
For the year ended December 31,	2017			2016			2015
Income before provision for income taxes	$	513		$	438		$	442
Federal statutory income tax rates		35	%		35	%		35	%
Income taxes, at statutory income tax rate		180			153			155
Increase (decrease) due to
State income tax, net of federal income tax		19			15			15
AFUDC-equity		(1	)		(8	)		(6	)
Tax credits		(3	)		(7	)		0
Other		2			(1	)		2
Total income tax expense on consolidated statements of income	$	197		$	152		$	166
Income tax expense as a percent of income from continuing operations,    before income taxes		38.4	%		34.8	%		37.5	%

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Deferred Income Taxes

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

(millions)
As of December 31,	2017			2016
Deferred tax liabilities (1)
Property related	$	924		$	1,549
Pension and postretirement benefits		57			105
Pension		43			69
Total deferred tax liabilities		1,024			1,723
Deferred tax assets (1)
Loss and credit carryforwards (2)		91			91
Medical benefits		24			47
Insurance reserves		(5	)		27
Pension and postretirement benefits		57			105
Capitalized energy conservation assistance costs		13			23
Other		19			23
Total deferred tax assets		199			316
Total deferred tax liability, net	$	825		$	1,407

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $8 million.

As a result of tax reform, Tampa Electric recorded a change in net deferred taxes with an offset to a regulatory tax liability in the amount of $755 million, subject to refund to customers over time as required by order of the FPSC. At December 31, 2017, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $345 million and $273 million, respectively, expiring between 2033 and 2037. TEC has unused general business credits of $23 million, expiring between 2028 and 2037. As a result of the Merger with Emera, TECO Energy’s NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI.

Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2017		2016		2015
Balance at January 1,	$	7	$	0	$	0
Increases due to tax positions related to current year		1		7		0
Balance at December 31	$	8	$	7	$	0

As of December 31, 2017 and 2016, TEC’s uncertain tax positions for federal R&D tax credits were $8 million and $7 million, respectively, 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 $8 million of unrecognized tax benefits at December 31, 2017, that, if recognized, would reduce TEC’s effective tax rate.

TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2017, 2016 and 2015, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2017, 2016 and 2015. No amounts have been recorded for penalties.

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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). Prior to July 1, 2016, TEC was included in a consolidated U.S. federal income tax return with TECO Energy and subsidiaries. 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. 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.

5. Employee Postretirement Benefits

Pension Benefits

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

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

Other Postretirement Benefits

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

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

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2020, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy and its affiliates do not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase the PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective January 1, 2013, TECO Energy implemented an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by TECO Energy under Medicare Part D for its post-65 retiree prescription drug plan. Effective January 1, 2015, TECO Energy changed its post-65 retiree coverage for medical benefits to a Medicare Advantage plan insured by Aetna. This will result in a lower claims cost by taking advantage of the government subsidies available for that plan.

Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in

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the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted.

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

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2017			2016			2017			2016
Change in benefit obligation
Net benefit obligation at beginning of year	$	770		$	733		$	175		$	172
Service cost		20			19			2			2
Interest cost		31			31			7			7
Plan participants’ contributions		0			0			3			3
Plan amendments		0			1			0			0
Plan curtailment		(1	)		1			0			0
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Actuarial loss (gain)		69			56			22			5
Net benefit obligation at end of year	$	812		$	770		$	193		$	175

Change in plan assets
Fair value of plan assets at beginning of year	$	649		$	625		$	0		$	0
Actual return on plan assets		122			55			0			0
Employer contributions		46			38			(3	)		(3	)
Employer direct benefit payments		27			3			16			14
Plan participants’ contributions		0			0			3			3
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Direct benefit payments		(1	)		(1	)		0			0
Fair value of plan assets at end of year (1)	$	766		$	649		$	0		$	0

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

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

TECO Energy	Pension Benefits						Other Benefits (1)
Funded Status
(millions)	2017			2016			2017			2016
Benefit obligation (PBO/APBO)	$	812		$	770		$	193		$	175
Less: Fair value of plan assets		766			649			0			0
Funded status at end of year	$	(46	)	$	(121	)	$	(193	)	$	(175	)

(1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

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The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $762 million at December 31, 2017 and $724 million at December 31, 2016.

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

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2017			2016			2017			2016
Accrued benefit costs and other current liabilities	$	(7	)	$	(1	)	$	(10	)	$	(9	)
Deferred credits and other liabilities		(30	)		(80	)		(154	)		(139	)
	$	(37	)	$	(81	)	$	(164	)	$	(148	)

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

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2017		2016		2017			2016
Net actuarial loss (gain)	$	215	$	236	$	70		$	50
Prior service cost (credit)		1		1		(13	)		(15	)
Amount recognized	$	216	$	237	$	57		$	35

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2017			2016			2017			2016
Discount rate		3.62	%		4.11	%		3.70	%		4.28	%
Rate of compensation increase-weighted average		3.32	%		2.57	%		3.31	%		2.48	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.58	%		6.83	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

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

(millions)	1% Increase		1 % Decrease
Effect on PBO	$	7	$	(6	)

The discount rate assumption used to determine the December 31, 2017 and 2016 benefit obligation was based on a cash flow matching technique that matches yields from high-quality (AA-rated, non-callable) corporate bonds to TECO Energy’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption. The discount rate assumption used to determine the December 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructed hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculated all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selected the portfolio with the highest yield and used that yield as the recommended discount rate. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate.

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

TECO Energy	Pension Benefits									Other Benefits (1)
	2017			2016			2015			2017			2016			2015
(millions)
Service cost	$	20		$	19		$	21		$	2		$	2		$	2
Interest cost		31			31			30			7			7			7
Expected return on plan assets		(48	)		(46	)		(43	)		0			0			0
Amortization of:
Actuarial loss		17			16			15			0			0			0
Prior service (benefit) cost		0			0			0			(2	)		(2	)		(3	)
Curtailment loss (gain)		0			1			0			0			0			0
Settlement loss (2)		7			1			0			0			0			0
Net periodic benefit cost	$	27		$	22		$	23		$	7		$	7		$	6

New prior service cost		0			1		$	0		$	0	$	0	$	0
Net loss (gain) arising during the year		(5	)		47			75			22		5		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2		2		3
Amortization or settlement of actuarial gain (loss)		(24	)		(17	)		(15	)		0		0		0
Total recognized in OCI and regulatory assets	$	(29	)	$	31		$	60		$	24	$	7	$	3
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	53		$	83		$	31	$	14	$	9

(1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2) 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 costs for pension benefits was $14 million, $13 million and $14 million for 2017, 2016 and 2015, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $6 million, $6 million and $6 million for 2017, 2016 and 2015, respectively.

The estimated net loss for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year is $14 million. There are no prior service credits to be amortized from regulatory assets into net periodic benefit cost in 2018 for the other postretirement benefit plan.

TEC’s postretirement benefit plans were not explicitly impacted by the Merger. However, as a result of the Merger, TECO Energy remeasured its postretirement benefits plans on the Merger effective date, July 1, 2016. As a result of the remeasurements, TEC’s net periodic benefit cost increased by $1 million for pension benefits and $0 million for other postretirement plan benefits for the six months ended December 31, 2016. Additionally, a curtailment loss for the SERP of $1 million was recognized by TECO Energy in 2016 as a result of retirements due to the Merger. In addition, TECO Energy recognized a settlement charge related to the SERP of $7 million in 2017 due to retirements that have occurred as a result of the Merger. TEC was not impacted by the curtailment loss or settlement charge.

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

	Pension Benefits									Other Benefits
	2017			2016			2015			2017			2016			2015
Discount rate		4.110	%		4.688	%		4.258	%		4.280	%	4.667%/3.85%				4.206	%
Expected long-term return on plan assets		7.00	%		7.00	%		7.00	%	N/A			N/A			N/A
Rate of compensation increase		2.57	%		2.59	%		3.87	%		2.48	%		2.50	%		3.86	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.83	%		7.05	%		7.00	%
Ultimate rate	n/a			n/a			n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			n/a			2038			2038			2025

The discount rate assumption used to determine the benefit cost for 2017 and from the Merger date to December 31, 2016 was based on the same technique that was used to determine the December 31, 2017 and 2016 benefit obligation as discussed above. The discount rate assumption used to determine the January 1, 2016 through June 30, 2016 and the 2015 benefit cost was based on the same technique that was used to determine the December 31, 2015 benefit obligation as discussed above. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2017, TECO Energy’s pension plan’s assets increased approximately 19%.

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

A one-percentage-point change in assumed health care cost trend rates would have a less than $1 million effect on net periodic benefit cost.

Pension Plan Assets

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

TECO Energy	2017 Target Allocation			ActualAllocation, End of Year
Asset Category				2017			2016
Equity securities	47%-53%				51	%		56	%
Fixed income securities	47%-53%				49	%		44	%
Total		100	%		100	%		100	%

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

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

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is

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most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of December 31, 2017 and 2016.

Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2017
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	3		$	0		$	0	$	0	$	3
Accounts receivable		14			0			0		0		14
Accounts payable		(43	)		0			0		0		(43	)
Short-term investment funds (STIFs)		14			0			0		0		14
Common stocks		44			0			0		0		44
Real estate investment trusts (REITs)		4			0			0		0		4
Mutual funds		196			0			0		0		196
Municipal bonds		0			2			0		0		2
Government bonds		0			55			0		0		55
Corporate bonds		0			45			0		0		45
Mortgage-backed securities (MBS)		0			(1	)		0		0		(1	)
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Swaps		0			4			0		0		4
Purchase options (swaptions)		0			1			0		0		1
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		232			105			0		0		337
Common and collective trusts (1)		0			0			0		326		326
Mutual fund (1)		0			0			0		103		103
Total investments	$	232		$	105		$	0	$	429	$	766

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

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TECO Energy	At Fair Value as of December 31, 2016
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	2		$	0		$	0	$	0	$	2
Accounts receivable		27			0			0		0		27
Accounts payable		(59	)		0			0		0		(59	)
Cash collateral		1			0			0		0		1
STIFs		12			0			0		0		12
Common stocks		44			0			0		0		44
REITs		3			0			0		0		3
Mutual funds		181			0			0		0		181
Municipal bonds		0			3			0		0		3
Government bonds		0			32			0		0		32
Corporate bonds		0			39			0		0		39
MBS		0			9			0		0		9
CMOs		0			1			0		0		1
Swaps		0			1			0		0		1
Purchase options (swaptions)		0			2			0		0		2
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		211			85			0		0		296
Common and collective trusts (1)		0			0			0		270		270
Mutual fund (1)		0			0			0		83		83
Total investments	$	211		$	85		$	0	$	353	$	649

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

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

• Cash collateral is valued at cash posted due to its short-term nature.

• The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

• The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

• The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

• The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

• The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-ended mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is a closed-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. There were no unfunded commitments as of December 31, 2017.

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• The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain  funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 5 business days. There were no unfunded commitments as of December 31, 2017.

• Discounted notes are valued at amortized cost.

• Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Additionally, the non-qualified SERP had $17 million and $41 million of assets as of December 31, 2017 and 2016, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in TEC’s Consolidated Balance Sheets rather than being netted with the related liability. The non-qualified trust holds investments in a money market fund. The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make it a level 1 asset. The SERP was fully funded as of December 31, 2017 and 2016.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan.

Contributions

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

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

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

The qualified pension plan’s actuarial value of assets, including credit balance, was 118.1% of the Pension Protection Act funded target as of January 1, 2017 and is estimated at 117.9% of the Pension Protection Act funded target as of January 1, 2018.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability. TECO Energy made contributions to this plan in 2017, 2016 and 2015, which met the minimum funding requirements for 2017, 2016 and 2015. TEC’s portion of the contribution in 2017 was $36 million and in 2016 was $31 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2018 contribution to be $37 million. TEC estimates its portion of annual contributions from 2019 to 2022 will range from $6 million to $17 million per year based on current assumptions. The amounts TECO Energy expects to make are in excess of the minimum funding required under ERISA guidelines.

   TEC’s portion of the contributions to the SERP in 2017, 2016 and 2015 were zero, zero and $15 million, respectively. TEC’s contribution in 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year. The fully-funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2018.  

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between January 1, 1990 and June 30, 2001 is limited to a defined

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dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2018, TEC expects to make a contribution of about $10 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

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

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2018	$	58	$	12
2019		56		12
2020		56		12
2021		59		12
2022		61		12
2023-2027		323		61

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period of January 2015 to December 2016, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals.  For the years ended December 31, 2017, 2016 and 2015, TEC’s portion of expense totaled $11 million, $8 million and $8 million, respectively, related to the matching contributions made to this plan.

6. Short-Term Debt

Credit Facilities

	December 31, 2017						December 31, 2016
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	5	$	1	$	325	$	40	$	1
3-year accounts receivable facility (3)		150		0		0		150		130		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	775	$	305	$	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.

(4) This 1-year facility matures on November 1, 2018.

At December 31, 2017, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2017 and 2016 was 2.07% and 1.49%, respectively.

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Tampa Electric Company Credit Agreement

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 the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin.

Tampa Electric Company Accounts Receivable Facility

On March 24, 2015, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to appoint a new program agent; add new lenders; and extend the scheduled termination date to March 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement and (b) a Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2017. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either the BTMU’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin.  In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of December 31, 2017, TEC was in compliance with the requirements of the Loan Agreement.  

Amendment of Tampa Electric Company Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment 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); provides for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; includes a $50 million letter of credit facility; and made other technical changes.  

7. Long-Term Debt  

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.

Issuance of Tampa Electric Company 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes). Until November 15, 2044, TEC may redeem all or any part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after November 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Purchase in Lieu of Redemption of Revenue Refunding Bonds

  At December 31, 2017 and 2016, $233 million of tax-exempt bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric to provide an opportunity to evaluate refinancing alternatives including $20 million variable-rate bonds due 2020, $52 million term-rate refunding bonds due 2025, $75 million term-rate bonds due 2030, and $86 million term-rate refunding bonds due 2034.

8. Merger with Emera

As disclosed in Note 1, 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.

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Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was cancelled and converted automatically into the right to receive $27.55 in cash, without interest. This represents an aggregate purchase price of approximately $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion).

The Merger Agreement requires Emera, among other things, (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 and TEC’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.

9. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of 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.

Tampa Electric Legal Proceeding

As a result of a tragic industrial accident at Big Bend Power Station on June 29, 2017, five workers (including one Tampa Electric employee and four contract workers) were killed and one other worker sustained serious injuries. Tampa Electric believes that any costs associated with the damages, injuries, fatalities and other losses related to the incident are substantially covered by insurance.  Tampa Electric recorded any accruals for all material insured and non-insured costs and related insurance recoveries resulting from the incident.

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 MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 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 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. See Note 3 for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this liability.

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Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015, totaled $2 million, $2 million and $4 million, respectively. TEC also has other purchase obligations for 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 December 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2018	$	10	$	2	$	303	$	444	$	759
2019		0		2		74		230		306
2020		0		2		7		177		186
2021		0		2		7		147		156
2022		0		2		7		141		150
Thereafter		0		36		18		1,029		1,083
Total future minimum payments	$	10	$	46	$	416	$	2,168	$	2,640

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2017, TEC was in compliance with all required financial covenants.

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2017			2016		2015
Natural gas sales to/(from) affiliates	$	(4	)	$	0	$	1
Services received from affiliates		67			66		69
Dividends to TECO Energy		292			289		268
Equity contributions from TECO Energy		190			150		175

Services received from affiliates primarily include shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning on January 1, 2015. Through TSI, TECO Energy provided TEC with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to TEC based on cost-causative allocation methods or the Modified Massachusetts Formula.

Amounts due from or to affiliates at December 31,

(millions)	2017		2016
Accounts receivable (1)	$	2	$	7
Accounts payable (1)		19		18
Taxes receivable (2)		3		0
Taxes payable (2)		2		7

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2) Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

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11. Segment Information

Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC, but are included in determining reportable segments.

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 750,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 375,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2017
Revenues - external	$	2,052	$	418	$	0			$	2,470
Sales to affiliates		2		20		(22	)			0
Total revenues		2,054		438		(22	)			2,470
Depreciation and amortization		300		50		0				350
Total interest charges		104		15		0				119
Provision for income taxes		171		26		0				197
Net income		273		43		0				316
Total assets		7,635		1,284		(555	)	(1)		8,364
Capital expenditures		518		122		0				640
2016
Revenues - external	$	1,964	$	432	$	0			$	2,396
Sales to affiliates		1		7		(8	)			0
Total revenues		1,965		439		(8	)			2,396
Depreciation and amortization		268		60		0				328
Total interest charges		91		15		0				106
Provision for income taxes		130		22		0				152
Net income		251		35		0				286
Total assets		7,357		1,191		(465	)	(1)		8,083
Capital expenditures		594		133		0				727
2015
Revenues - external	$	2,018	$	401	$	0			$	2,419
Sales to affiliates		0		6		(6	)			0
Total revenues		2,018		407		(6	)			2,419
Depreciation and amortization		256		57		0				313
Total interest charges		95		15		0				110
Provision for income taxes		144		22		0				166
Net income		241		35		0				276
Total assets		7,004		1,136		(431	)	(1)		7,709
Capital expenditures		593		94		0				687

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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12. Other Comprehensive Income

TEC reported the following OCI related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income

(millions)	Gross		Tax			Net
2017
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2016
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2015
Unrealized gain on cash flow hedges	$	4	$	(1	)	$	3
Reclassification from AOCI to net income		2		(1	)		1
Gain on cash flow hedges		6		(2	)		4
Total other comprehensive income	$	6	$	(2	)	$	4

Accumulated Other Comprehensive Loss

(millions) As of December 31,	2017			2016
Net unrealized losses from cash flow hedges (1)	$	(2	)	$	(3	)
Total accumulated other comprehensive loss	$	(2	)	$	(3	)

(1) Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

13. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

• To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

• To limit the exposure to interest rate fluctuations on debt securities.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on 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 ending on December 31, 2022. 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 14). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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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 December 31, 2016, 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 December 31, 2017 and 2016 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were zero and $17 million derivative assets as of December 31, 2017 and 2016, respectively. There were $1 million and zero derivative liabilities as of December 31, 2017 and 2016, respectively. 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 December 31, 2017 and 2016.

All of the derivative asset and liabilities at December 31, 2017 and 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 December 31, 2017, net pre-tax reductions of $1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The December 31, 2017 and 2016 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 years ended December 31, 2017, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended December 31, 2017, 2016 and 2015 is presented in Note 12. 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. The following table presents TEC’s derivative volumes that, as of December 31, 2017, are expected to settle during the 2018 fiscal year:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2018		0		7

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 December 31, 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 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.

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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.  

14. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As 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 table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016.

Recurring Derivative Fair Value Measures

	As of December 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0	$	1	$	0	$	1
	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 13).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At December 31, 2017 and 2016, 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 December 31, 2017 and 2016, the fair value of TEC’s short-term debt was not materially different from the carrying 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 Notes 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.

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15. 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 121 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 $16 million, $62 million and $34 million, under these PPAs for the three years ended December 31, 2017, 2016 and 2015, 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. Excluding the payments for energy under these contracts, TEC’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

16. Asset Retirement Obligations

TEC accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices.

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

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

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

	December 31,
(millions)	2017			2016
Beginning balance	$	45		$	6
Additional liabilities (1)		1			36
Liabilities settled		(1	)		0
Revisions to estimated cash flows		0			3
Other (2)		2			0
Ending balance	$	47		$	45

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The increase in the ARO in 2016 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed.    

(2) Includes accretion recorded as a deferred regulatory asset.  

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17. Stock-Based Compensation

Performance Share Unit Plan

Emera has a performance share unit (PSU) plan, and TEC employees started participating in the plan in 2017.  The PSU liability is marked-to-market at the end of each period based on the common share price in CAD at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA.

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan.  PSUs are granted annually for three-year overlapping performance cycles.  PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as the Dividend Reinvestment Plan (DRIP).  The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the Emera Management Resources and Compensation Committee early in the following year.  The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

A summary of the activity related to TEC employee PSUs for the year ended December 31, 2017 is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2016		0		$	0	$	0
Granted including DRIP		144			45.40		6
Exercised		(5	)		30.57		0
Forfeited		(17	)		45.41		(1	)
Transferred		11			38.51		1
Outstanding as of December 31, 2017		133		$	45.11	$	6

Compensation cost recognized for the PSU plan for the year ended December 31, 2017 was $2 million. Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2017were $1 million. As of December 31, 2017, there was $4 million of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Conclusions Regarding Effectiveness of Disclosure Controls and Procedures.

TEC’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TEC’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this annual report, December 31, 2017 (Evaluation Date). Based on such evaluation, TEC’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TEC’s disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

TEC’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TEC’s internal control over financial reporting as of December 31, 2017 based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TEC’s internal control over financial reporting was effective as of December 31, 2017.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

There was no change in TEC’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TEC’s internal controls that occurred during TEC’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Item 9B. OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required by Item 10 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by Item 12 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees Paid by TEC to the Independent Auditor

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of TEC’s annual financial statements for the years ended December 31, 2017 and 2016, and fees billed for other services rendered by PricewaterhouseCoopers LLP during these periods.

	2017		2016
Audit fees	$	915,897	$	997,380
Audit-related fees		7,395		156,890
Tax fees
Tax compliance fees		0		0
Tax planning fees		0		23,750
All other fees		0		0
Total	$	923,292	$	1,178,020

Audit fees consist of fees for professional services performed for (i) the audit of TEC’s annual financial statements (ii) the related reviews of the financial statements included in TEC’s 10-Q filings and (iii) services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-related fees consist of fees for professional services that are reasonably related to the performance of the audit or review of our financial statements, such as required activities related to debt offerings.

Tax fees consist of tax compliance fees for tax return review and income tax provision review, and tax planning fees, including tax audit advice.

All other fees, if any, consist of fees for other work performed by PricewaterhouseCoopers LLP, including fees for assessments and recommendations related to specific transactions, regulatory accounting advice and other miscellaneous services.

Audit Committee Pre-Approval Policy

All services performed by the independent auditor are approved by the Board in accordance with Emera’s pre-approval policy for services provided by the independent auditor.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Certain Documents Filed as Part of this Form 10-K

1. Financial Statements

Tampa Electric Company Financial Statements

Report of Independent Registered Public Accounting Firm dated February 9, 2018 of PricewaterhouseCoopers LLP

Consolidated Balance Sheets at December 31, 2017 and 2016

Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Retained Earnings for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Capitalization for the Years Ended December 31, 2017, 2016 and 2015

Notes to Consolidated Financial Statements

2. Financial Statement Schedules

Tampa Electric Company Schedule II - Valuation and Qualifying Accounts and Reserves  

3. Exhibits

(b) The exhibits filed as part of this Form 10-K are listed on the List of Exhibits below.

(c) The financial statement schedules filed as part of this Form 10-K are listed in paragraph (a)(2) above, and follow immediately.

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SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended December 31, 2017, 2016 and 2015

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions  (1)		Period
Allowance for Uncollectible Accounts:
2017	$	1	$	5	$	0	$	5	$	1
2016	$	1	$	3	$	0	$	3	$	1
2015	$	1	$	3	$	0	$	3	$	1

(1) Write-off of individual bad debt accounts

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LIST OF EXHIBITS

Exhibit No.	Description
3.1	Restated Articles of Incorporation of Tampa Electric Company, as amended on November 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company). (P)	*
3.2	Bylaws of Tampa Electric Company, as amended effective February 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of Tampa Electric Company).	*
4.1	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company of Florida, N.A., as trustee, dated as of Jun. 1, 2002 (including the form of bond) (Exhibit 4.5, Amendment No. 1 to Form 10-K for 2004 of Tampa Electric Company).	*
4.2	Loan and Trust Agreement dated as of Jul. 2, 2007 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (including the form of Bond) (Exhibit 4.1, Form 8-K dated Jul. 25, 2007 of Tampa Electric Company).	*
4.3	First Supplemental Loan and Trust Agreement dated as of March 26, 2008 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated March 26, 2008 of Tampa Electric Company).	*
4.4	Loan and Trust Agreement dated as of November 15, 2010 among Tampa Electric Company, Polk County Industrial Development Authority and The Bank of New York Mellon Trust Company, N.A., as trustee (including the form of bond) (Exhibit 4.1, Form 8-K dated November 23, 2010 of Tampa Electric Company).	*
4.5	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee, dated as of January 5, 2006 (including the form of bond) (Exhibit 4.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).	*
4.6	Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jul. 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873 of Tampa Electric Company).	*
4.7	Third Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jun. 15, 2001 (Exhibit 4.2, Form 8-K dated Jun. 25, 2001 of Tampa Electric Company).	*
4.8	Fifth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of May 1, 2006 (Exhibit 4.16, Form 8-K dated May 12, 2006 of Tampa Electric Company).	*
4.9	Note Purchase Agreement among Tampa Electric Company and the Purchasers party thereto, dated as of April 11, 2003 (Exhibit 10.1, Form 8-K dated April 14, 2003 of Tampa Electric Company).	*
4.10	Sixth Supplemental Indenture dated as of May 1, 2007 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.18, Form 8-K dated May 25, 2007 of Tampa Electric Company).	*
4.11	Seventh Supplemental Indenture dated as of May 1, 2008 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.20, Form 8-K dated May 16, 2008 of Tampa Electric Company).	*
4.12	Eighth Supplemental Indenture dated as of November 15, 2010 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee (including the form of 5.40% Notes due 2021) (Exhibit 4.1, Form 8-K dated December 9, 2010 of Tampa Electric Company).	*
4.13	Ninth Supplemental Indenture dated as of May 31, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.10% Notes due 2042) (Exhibit 4.23, Form 8-K dated June 5, 2012 for Tampa Electric Company).	*

82

Exhibit No.	Description
4.14	Tenth Supplemental Indenture dated as of September 19, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing and amending the Indenture dated as of July 1, 1998, as amended (including the form of 2.60% Notes due 2022) (Exhibit 4.25, Form 8-K dated September 28, 2012 for Tampa Electric Company).	*
4.15	Eleventh Supplemental Indenture dated as of May 12, 2014 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.35% Notes due 2044) (Exhibit 4.27, Form 8-K dated May 15, 2014).	*
4.16	Twentieth Supplemental Indenture dated as of December 1, 2013 between Tampa Electric Company and US Bank, N.A., as successor trustee, amending and restating the Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of August 1, 1946 (Exhibit 4.30, Form 10-K for 2013 of Tampa Electric Company).	*
4.17	Twelfth Supplemental Indenture dated as of May 20, 2015, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.20% Notes due 2045) (Exhibit 4.24, Form 8-K dated May 20, 2015 of Tampa Electric Company).	*
10.1	TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of November 1, 2007 (Exhibit 10.1, Form 10-K for 2007 of Tampa Electric Company).	*
10.2	TECO Energy Group Supplemental Disability Income Plan, dated as of March 20, 1989 (Exhibit 10.22, Form 10-K for 1988 of TECO Energy, Inc.). (P)	*
10.3	TECO Energy Group Supplemental Retirement Benefits Trust Agreement, effective as of November 17, 2008 (Exhibit 10.3, Form 10-K for 2008 of Tampa Electric Company).	*
10.4	TECO Energy Group Benefit Restoration Plan dated as of November 13, 2015 (Exhibit 10.4, Form 10-K for 2015 of Tampa Electric Company).	*
10.5	Form of Change-in-Control Severance Agreement between TECO Energy, Inc. and certain Executive Officers (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2008 of Tampa Electric Company).	*
10.6	Form of Change-in-Control Severance Agreement between TECO Energy, Inc. and certain Executive Officers (Exhibit 10.1, Form 8-K dated February 5, 2010 of TECO Energy, Inc.).	*
10.7	Insurance Agreement dated as of January 5, 2006 between Tampa Electric Company and Ambac Assurance Corporation (Exhibit 10.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).	*
10.8	Amended and Restated Purchase and Contribution Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Originator, and TEC Receivables Corp., as the Purchaser (Exhibit 10.1, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).	*
10.9	Loan and Servicing Agreement dated as of March 24, 2015, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.2, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).	*
10.10	Amendment No. 1 to Loan and Servicing Agreement dated as of August 10, 2016, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2016 of Tampa Electric Company).	*
10.11	Fourth Amended and Restated Credit Agreement dated as of December 17, 2013, among Tampa Electric Company, as Borrower, Citibank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.2, Form 8-K dated December 17, 2013 of Tampa Electric Company).	*

83

Exhibit No.	Description
10.12	Amendment No. 1, dated as of August 1, 2014, to the Fourth Amended and Restated Credit Agreement dated as of December 17, 2013, among Tampa Electric Company, as Borrower, Citibank, N.A., as Administrative Agent, and the Lenders party thereto (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2014 of Tampa Electric Company).		*
10.13	Amendment No. 2, dated as of September 30, 2014, to the Fourth Amended and Restated Credit Agreement dated as of December 17, 2013, as amended, among Tampa Electric Company, as Borrower, Citibank, N.A., as Administrative Agent, and the Lenders party thereto (Exhibit 10.7, Form 10-Q for the quarter ended September 30, 2014 of Tampa Electric Company).		*
10.14	Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.1, Form 8-K dated March 22, 2017 of Tampa Electric Company).		*
10.15	Credit Agreement dated as of November 2, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated November 2, 2017 of Tampa Electric Company).	*
12	Ratio of Earnings to Fixed Charges.
23	Consent of Independent Certified Public Accountants.
31.1	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of Tampa Electric Company to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

(1) This certification accompanies the Annual Report on Form 10-K and is not filed as part of it.

* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Executive Compensation Plans and Arrangements

Exhibits 10.1 through 10.6, above are management contracts or compensatory plans or arrangements in which executive officers or directors of Tampa Electric Company participate.

84

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TAMPA ELECTRIC COMPANY
Dated: February 9, 2018	By:	/s/ Nancy Tower
		Nancy Tower
		President and Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 9, 2018:

	Title
/s/ Nancy Tower	President and Chief Executive Officer
Nancy Tower	(Principal Executive Officer)
/s/ Gregory W. Blunden	Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer)
Gregory W. Blunden	(Principal Financial and Accounting Officer)

Signature		Title
/s/ Scott Balfour		Chairman of the Board and Director		/s/ Christopher G. Huskilson	Director
Scott Balfour				Christopher G. Huskilson
/s/ Robert R. Bennett	Director		/s/ Pamela D. Iorio		Director
Robert R. Bennett			Pamela D. Iorio
/s/ Sarah R. MacDonald	Director		/s/ Patrick J. Geraghty		Director
Sarah R. MacDonald			Patrick J. Geraghty
/s/ Rhea F. Law	Director		/s/ Will Weatherford		Director
Rhea F. Law			Will Weatherford
/s/ Ana-Marie Codina Barlick	Director		/s/ Rasesh Thakkar		Director
Ana-Marie Codina Barlick			Rasesh Thakkar

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to Tampa Electric Company’s security holders because all of its equity securities are held by TECO Energy, Inc.

85

EX-12

Exhibit 12

TAMPA ELECTRIC COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth Tampa Electric Company’s ratio of earnings to fixed charges for the periods indicated.

	Year Ended December 31,
(millions)	2017		2016		2015		2014		2013
Income from continuing operations, before income taxes	$	513	$	438	$	442	$	416	$	364
Interest expense		122		120		122		116		113
Earnings before taxes and fixed charges	$	635	$	558	$	564	$	532	$	477
Interest expense	$	122	$	120	$	122	$	116	$	113
Total fixed charges	$	122	$	120	$	122	$	116	$	113
Ratio of earnings to fixed charges		5.20x		4.66x		4.62x		4.59x		4.23x

For the purposes of calculating these ratios, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges consist of interest expense on indebtedness, amortization of debt premium and an estimate of the interest component of rentals.  Interest expense includes total interest expense, excluding AFUDC, and an estimate of the interest component of rentals.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202565) of Tampa Electric Company of our report dated February 9, 2018 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Certified Public Accountants

Tampa, Florida

February 9, 2018

PricewaterhouseCoopers LLP, 4040 West Boy Scout Boulevard, Suite 1000, Tampa, FL 33607-5745

T: (813) 229 0221, F: (812) 229 3646, www.pwc.com/us

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Nancy Tower, certify that:

1. I have reviewed this annual report on Form 10-K of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 9, 2018	/s/ NANCY TOWER
	NANCY TOWER
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

1. I have reviewed this annual report on Form 10-K of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 9, 2018	/s/ GREGORY W. BLUNDEN
	GREGORY W. BLUNDEN
	Senior Vice President-Finance and Accounting and Chief Financial Officer
	(Chief Accounting Officer)
	(Principal Financial and Accounting Officer)

EX-32

Exhibit 32

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, the Annual Report on Form 10-K of the Company for the year ended December 31, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 9, 2018	/s/	NANCY TOWER
		NANCY TOWER
		President and Chief Executive Officer
		(Principal Executive Officer)

Dated: February 9, 2018	/s/	GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting and
		Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signatures that appear in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-K and shall not be considered filed as part of the Form 10-K.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 08, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Trading Symbol	ck0000096271
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Entity Public Float			$ 0

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, plant and equipment
Utility plant in service, at original costs	$ 10,427	$ 10,019
Construction work in progress	263	892
Accumulated depreciation	(2,994)	(2,826)
Utility plant in service, net	7,433	7,193
Other property	11	10
Total property, plant and equipment, net	7,444	7,203
Current assets
Cash and cash equivalents	13	10
Receivables, less allowance for uncollectibles of $1 at December 31, 2017 and 2016	257	206
Due from affiliates	5	7
Inventories, at average cost
Current derivative assets	0	15
Regulatory assets	77	28
Prepayments and other current assets	13	21
Total current assets	515	450
Deferred debits
Regulatory assets	356	393
Other	49	37
Total deferred debits	405	430
Total assets	8,364	8,083
Capitalization
Common stock	2,645	2,456
Accumulated other comprehensive loss	(2)	(3)
Retained earnings	335	311
Total capital	2,978	2,764
Long-term debt, less amount due within one year	1,860	2,163
Total capital	4,838	4,927
Current liabilities
Long-term debt due within one year	304	0
Notes payable	305	170
Accounts payable	233	262
Due to affiliates	21	25
Customer deposits	131	146
Regulatory liabilities	58	154
Accrued interest	14	16
Accrued taxes	12	12
Other	44	11
Total current liabilities	1,122	796
Long-term liabilities
Deferred income taxes	825	1,407
Regulatory liabilities	1,227	591
Deferred credits and other liabilities	352	362
Total deferred credits	2,404	2,360
Commitments and Contingencies (see Note 9)
Total liabilities and capital	8,364	8,083
Fuel [Member]
Inventories, at average cost
Utility inventories	60	77
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	90	86
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	8,555	7,624
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,609	$ 1,503

XML

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

XML

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Electric	$ 2,052	$ 1,964	$ 2,018
Gas	418	432	401
Total revenues	2,470	2,396	2,419
Expenses
Fuel	588	561	639
Purchased power	46	104	79
Cost of natural gas sold	153	159	135
Operations & maintenance	513	538	529
Depreciation and amortization	350	328	313
Taxes, other than income	198	193	192
Total expenses	1,848	1,883	1,887
Income from operations	622	513	532
Other income
Allowance for other funds used during construction	2	24	17
Other income, net	8	7	3
Total other income	10	31	20
Interest charges
Interest expense	120	117	118
Allowance for borrowed funds used during construction	(1)	(11)	(8)
Total interest charges	119	106	110
Income before provision for income taxes	513	438	442
Provision for income taxes	197	152	166
Net income	316	286	276
Other comprehensive income, net of tax
Gain on cash flow hedges	1	1	4
Total other comprehensive income, net of tax	1	1	4
Comprehensive income	$ 317	$ 287	$ 280

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Net income	$ 316	$ 286	$ 276
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	350	328	313
Deferred income taxes and investment tax credits	192	87	120
Allowance for equity funds used during construction	(2)	(24)	(17)
Deferred recovery clauses	(83)	54	26
Receivables, less allowance for uncollectibles	(43)	18	(3)
Inventories	13	16	(21)
Taxes accrued	(9)	68	(17)
Accounts payable	(16)	63	(27)
Regulatory assets and liabilities	(100)	(11)	(9)
Other	(6)	(54)	(33)
Cash flows from operating activities	612	831	608
Cash flows from investing activities
Capital expenditures	(640)	(727)	(687)
Net proceeds from sale of assets	0	9	0
Cash flows used in investing activities	(640)	(718)	(687)
Cash flows from financing activities
Equity contributions from TECO Energy	190	150
Proceeds from long-term debt issuance	0	0	251
Repayment of long-term debt	0	(83)	(83)
Net change in short-term debt (maturities of 90 days or less)	(165)	109	3
Proceeds from other short-term debt (maturities over 90 days)	300	0	0
Dividends to TECO Energy	(292)	(289)
Other financing activities	(2)	1	0
Cash flows from/(used in) financing activities	31	(112)	78
Net increase (decrease) in cash and cash equivalents	3	1	(1)
Cash and cash equivalents at beginning of the year	10	9	10
Cash and cash equivalents at end of the year	13	10	9
Supplemental disclosure of cash paid (received):
Interest	115	103	106
Income taxes	13	(3)	64
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	(16)	(9)	7
TECO Energy [Member]
Cash flows from financing activities
Equity contributions from TECO Energy	190	150	175
Dividends to TECO Energy	$ (292)	$ (289)	$ (268)

XML

Consolidated Statements of Cash Flows (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Statement Of Cash Flows [Abstract]
Change in deferred taxes as result of tax reform offset to regulatory liability	$ 755

XML

Consolidated Statements of Retained Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Partners Capital [Abstract]
Beginning Balance	$ 311	$ 314	$ 306
Add: Net income	316	286	276
Retained Earning, Gross	627	600	582
Deduct: Cash dividends on capital stock—common	292	289	268
Ending Balance	$ 335	$ 311	$ 314

XML

Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulated Operations [Abstract]
Common equity, shares authorized	25,000,000	25,000,000
Capital Stock Outstanding December 31, Shares	10	10
Capital Stock Outstanding December 31, Amount	$ 2,645	$ 2,456
Cash Dividends Paid	$ 292	$ 289

XML

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) $ / shares shares
Preferred stock - par value | $ / shares	$ 100
Preferred stock, no par value | $ / shares
Equity contributions made by TECO Energy | $	$ 190
Preferred Stock Par Value [Member]
Preferred stock, shares authorized	1,500,000
Preferred stock, shares outstanding	0
Preferred Stock No Par Value [Member]
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0
Preference Stock No Par Value [Member]
Preferred stock, no par value | $ / shares
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

XML

Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt, total	$ 2,183	$ 2,183
Unamortized debt discount, net	(3)	(3)
Debt issuance costs	(16)	(17)
Long-term debt, carrying amount	2,164	2,163
Less amount due within one year	304	0
Total long-term debt	1,860	2,163
Long-term debt, fair value	2,412	2,345
Level 1 [Member]
Debt Instrument [Line Items]
Long-term debt, fair value	55	58
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,921	1,921
Long-term debt, carrying amount	$ 1,921
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	$ 54	54
Tampa Electric [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	$ 200	200
Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	$ 232	232
Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	$ 225	225
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	$ 250	250
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	$ 190	190
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 250	250
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 290	290
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 230	230
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	262	262
Long-term debt, carrying amount	$ 262
PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	$ 50	50
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	$ 47	47
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	$ 25	25
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	$ 60	60
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 50	50
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 10	10
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 20	$ 20

XML

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical)	Dec. 31, 2017
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.65%
Tampa Electric [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.55%
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.10%
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%

XML

Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Total long-term debt maturities	$ 2,164
Long Term Debt Maturities
Debt Instrument [Line Items]
2018	304
2019	0
2020	0
2021	279
2022	250
Thereafter	1,350
Total long-term debt maturities	2,183
Tampa Electric [Member]
Debt Instrument [Line Items]
2018	254
2019	0
2020	0
2021	232
2022	225
Thereafter	1,210
Total long-term debt maturities	1,921
PGS [Member]
Debt Instrument [Line Items]
2018	50
2019	0
2020	0
2021	47
2022	25
Thereafter	140
Total long-term debt maturities	$ 262

XML

Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Significant Accounting Policies

1.Significant Accounting Policies

Description of Business

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

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.

TEC is a wholly-owned subsidiary of TECO Energy, Inc. and contains electric and natural gas divisions. Intercompany balances and transactions within the divisions have been eliminated in consolidation.

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC 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. See Note 8 for further information.

Cash Equivalents

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

Property, Plant and Equipment

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

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

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2017			December 31, 2016
Electric generation	21-56 years	$	4,766		$	4,102
Electric transmission	28-77 years		859			837
Electric distribution	14-56 years		2,437			2,331
Gas transmission and distribution	15-77 years		1,534			1,429
General plant and other	8-43 years		579			438
Total cost			10,175			9,137
Less accumulated depreciation			(2,994	)		(2,826	)
Construction work in progress			263			892
Total property, plant and equipment, net		$	7,444		$	7,203

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7%, 3.5% and 3.7% for 2017, 2016 and 2015, respectively. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $332 million, $304 million and $306 million, respectively. See Note 3 for information regarding an agreement approved by the FPSC that, among other things, reduced PGS’s annual depreciation expense by $16 million beginning in 2016.

Tampa Electric and PGS compute depreciation and amortization using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2017, 2016 and 2015, the rate was 6.46%. Total AFUDC for the years ended December 31, 2017, 2016 and 2015 was $2 million, $36 million and $26 million, respectively. The decrease in 2017 and increase in 2016 is a result of the Polk Power Station conversion project, which was completed in January 2017.

Inventory

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

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3). TEC’s retail and wholesale businesses are regulated by the FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details, including the impacts of tax reform.

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property. As of December 31, 2017 and 2016, ITCs were $22 million and $11 million, respectively.

Revenue Recognition

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

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

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2017 and 2016, unbilled revenues of $66 million and $54 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Revenues and Cost Recovery

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

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-affiliates at a cost of $46 million, $104 million and $79 million, for the years ended December 31, 2017, 2016 and 2015, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Receivables and Allowance for Uncollectible Accounts

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

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $113 million, $117 million and $117 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), asset retirement obligations (see Note 16), and medical and general liability claims incurred but not reported.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2017 and 2016 ranged from 2.74% to 4.00% and 2.69% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

Reclassifications

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

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

Accounting Changes And Error Corrections [Abstract]

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2017, are described as follows:

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued Accounting Standard Update (ASU) 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows.  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach.  TEC has early adopted the standard, with no impact on the consolidated financial statements as a result of implementation of this standard.

Future Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB, but have not yet been adopted by TEC.  Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, codified as ASC Topic 606.  The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients.  The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption.  TEC will adopt this guidance effective January 1, 2018, using the modified retrospective approach.

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 completed an analysis of material unregulated revenue streams and concluded that there will be no material changes on adoption of this standard.  TEC also 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.  The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC will adopt this guidance effective January 1, 2018 and does not expect an impact on the consolidated financial statements as a result of implementation of this standard.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases.  The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months.  Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet.  The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged.  The guidance will require additional disclosures regarding key information about leasing arrangements.  This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018.  Early adoption is permitted and is required to be applied using a modified retrospective approach.  

In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in the first quarter of 2018.  

TEC is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures.  In the third quarter of 2017, TEC implemented a project plan.  In the fourth quarter of 2017, TEC began execution of the project plan, including training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements.  This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements.  TEC continues to monitor FASB amendments to ASC Topic 842.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments.  The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures.  The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts.  The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators.  

This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019.  Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach.  TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business.  The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted and is required to be applied prospectively.  The adoption of this standard will not have an impact on TEC’s consolidated financial statements.

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.  The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs.  The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations.  Only the service cost component will be eligible for capitalization as property, plant and equipment under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. TEC is a participant in the comprehensive retirement plans of TECO Energy and applies multiemployer accounting. This new guidance will not impact accounting for multiemployer plans, therefore, it will not impact TEC’s financial statements.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815.  This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting.  The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach.  TEC is currently evaluating the impact of the adoption of this standard on the consolidated financial statements and does not expect the impact to be significant.

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Regulatory

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. The FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Tampa Electric Base Rates-2013 Agreement

Tampa Electric’s results for the past three years reflect the stipulation and settlement agreement entered into on September 6, 2013, which resolved all matters in Tampa Electric’s 2013 base rate proceeding.

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 provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. The agreement provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, 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 replaced the existing 2013 base rate settlement agreement described above and extended it another four years through 2021. The FPSC approved the agreement on November 6, 2017.    

The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue adjustments for the 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 SoBRAs 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 receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction.   

On December 12, 2017, TEC filed its petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the spring of 2018.

The agreement further maintains Tampa Electric’s allowed regulatory ROE and allowed equity in the capital structure and extends the rate freeze date from January 1, 2018 to December 31, 2021, subject to the same ROE thresholds. The agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. 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 agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make 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, Tropical Storm Erika, 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 cost of restoration to be approximately $105 million, of which $93 million was charged to the storm reserve, $4 million was charged to O&M expense, and $8 million was charged to capital expenditures. This reflects an update from the estimated cost of restoration of $70 million at September 30, 2017, primarily due to higher than expected mutual assistance and contractor costs. At December 31, 2017, the amount of $93 million charged to the storm reserve exceeded the $46 million balance by $47 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 petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below.

Tampa Electric Implementation Settlement

On January 30, 2018, Tampa Electric filed a settlement agreement with the FPSC that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates stable in 2018.  If approved by the FPSC, the agreement authorizes Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. Tampa Electric’s final storm costs and final impact of tax reform on Tampa Electric’s base rates pursuant to the 2017 agreement will be determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. In addition, beginning in January 2019, Tampa Electric will reflect the full impact of tax reform on its base rates, provided that the FPSC’s determinations have been finalized. A decision is expected in March 2018.

PGS Base Rates

PGS’s base rates were established in May 2009 and reflect an allowed ROE range of 9.75% to 11.75% with base rates set at the middle of the range of 10.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital.

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 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 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 agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million of that amount would be amortized over a two-year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense. This additional amortization expense in 2017 and 2016 was offset by the decrease in depreciation expense as discussed above.  

The PGS settlement does not contain a provision for tax reform. On January 9, 2018, the Florida Office of Public Counsel filed a generic docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS.

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 as of December 31, 2017 and 2016 are presented in the following table:

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2017		2016
Regulatory assets:
Regulatory tax asset (1)	$	45	$	86
Cost-recovery clauses - deferred balances (2)		12		8
Cost-recovery clauses - offsets to derivative liabilities (2)		1		0
Environmental remediation (3)		33		37
Postretirement benefits (4)		272		272
Storm reserve (5)		47		0
Other		23		18
Total regulatory assets		433		421
Less: Current portion		77		28
Long-term regulatory assets	$	356	$	393
Regulatory liabilities:
Regulatory tax liability (6)	$	730	$	6
Cost-recovery clauses (2)		32		112
Cost-recovery clauses - offsets to derivative assets (2)		0		17
Storm reserve (5)		0		56
Accumulated reserve—cost of removal (7)		518		547
Other		5		7
Total regulatory liabilities		1,285		745
Less: Current portion		58		154
Long-term regulatory liabilities	$	1,227	$	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 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. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. 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 the Tampa Electric Storm Restoration Cost Recovery section 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 within a 12-month period.

(6) The increase in the regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 for further information.

(7) 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.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

4. Income Taxes

On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform proposals affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. accounting standards, TEC is required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate. Additionally, under FPSC rules TEC is required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3.

TEC has provisionally revalued all deferred tax assets and liabilities, $199 million and $1,024 million, respectively, based on the rates at which they are expected to reverse in the future, which is 21% for federal tax purposes. TEC is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Provisional amounts primarily relate to the uncertainty of the application of 100% asset expensing rules after September 27, 2017. Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act.

Income Tax Expense

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.

In 2017, 2016 and 2015, TEC recorded net tax provisions of $197 million, $152 million and $166 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2017			2016		2015
Current income taxes
Federal	$	(1	)	$	53	$	38
State		6			12		8
Deferred income taxes
Federal		170			76		105
State		23			11		15
Investment tax credits, net of amortization		(1	)		0		0
Total income tax expense	$	197		$	152	$	166

For the three years presented, the overall effective tax rate differs from the 35% U.S. federal statutory rate as presented below:

Effective Income Tax Rate

(millions)
For the year ended December 31,	2017			2016			2015
Income before provision for income taxes	$	513		$	438		$	442
Federal statutory income tax rates		35	%		35	%		35	%
Income taxes, at statutory income tax rate		180			153			155
Increase (decrease) due to
State income tax, net of federal income tax		19			15			15
AFUDC-equity		(1	)		(8	)		(6	)
Tax credits		(3	)		(7	)		0
Other		2			(1	)		2
Total income tax expense on consolidated statements of income	$	197		$	152		$	166
Income tax expense as a percent of income from continuing operations,    before income taxes		38.4	%		34.8	%		37.5	%

Deferred Income Taxes

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

(millions)
As of December 31,	2017			2016
Deferred tax liabilities (1)
Property related	$	924		$	1,549
Pension and postretirement benefits		57			105
Pension		43			69
Total deferred tax liabilities		1,024			1,723
Deferred tax assets (1)
Loss and credit carryforwards (2)		91			91
Medical benefits		24			47
Insurance reserves		(5	)		27
Pension and postretirement benefits		57			105
Capitalized energy conservation assistance costs		13			23
Other		19			23
Total deferred tax assets		199			316
Total deferred tax liability, net	$	825		$	1,407

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $8 million.

As a result of tax reform, Tampa Electric recorded a change in net deferred taxes with an offset to a regulatory tax liability in the amount of $755 million, subject to refund to customers over time as required by order of the FPSC. At December 31, 2017, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $345 million and $273 million, respectively, expiring between 2033 and 2037. TEC has unused general business credits of $23 million, expiring between 2028 and 2037. As a result of the Merger with Emera, TECO Energy’s NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI.

Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2017		2016		2015
Balance at January 1,	$	7	$	0	$	0
Increases due to tax positions related to current year		1		7		0
Balance at December 31	$	8	$	7	$	0

As of December 31, 2017 and 2016, TEC’s uncertain tax positions for federal R&D tax credits were $8 million and $7 million, respectively, 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 $8 million of unrecognized tax benefits at December 31, 2017, that, if recognized, would reduce TEC’s effective tax rate.

TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2017, 2016 and 2015, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2017, 2016 and 2015. No amounts have been recorded for penalties.

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). Prior to July 1, 2016, TEC was included in a consolidated U.S. federal income tax return with TECO Energy and subsidiaries. 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. 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.

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Employee Postretirement Benefits

12 Months Ended

Dec. 31, 2017

Compensation And Retirement Disclosure [Abstract]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Pension Benefits

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

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

Other Postretirement Benefits

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

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

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2020, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy and its affiliates do not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase the PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective January 1, 2013, TECO Energy implemented an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by TECO Energy under Medicare Part D for its post-65 retiree prescription drug plan. Effective January 1, 2015, TECO Energy changed its post-65 retiree coverage for medical benefits to a Medicare Advantage plan insured by Aetna. This will result in a lower claims cost by taking advantage of the government subsidies available for that plan.

Obligations and Funded Status

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

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

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2017			2016			2017			2016
Change in benefit obligation
Net benefit obligation at beginning of year	$	770		$	733		$	175		$	172
Service cost		20			19			2			2
Interest cost		31			31			7			7
Plan participants’ contributions		0			0			3			3
Plan amendments		0			1			0			0
Plan curtailment		(1	)		1			0			0
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Actuarial loss (gain)		69			56			22			5
Net benefit obligation at end of year	$	812		$	770		$	193		$	175

Change in plan assets
Fair value of plan assets at beginning of year	$	649		$	625		$	0		$	0
Actual return on plan assets		122			55			0			0
Employer contributions		46			38			(3	)		(3	)
Employer direct benefit payments		27			3			16			14
Plan participants’ contributions		0			0			3			3
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Direct benefit payments		(1	)		(1	)		0			0
Fair value of plan assets at end of year (1)	$	766		$	649		$	0		$	0

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

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

TECO Energy	Pension Benefits						Other Benefits (1)
Funded Status
(millions)	2017			2016			2017			2016
Benefit obligation (PBO/APBO)	$	812		$	770		$	193		$	175
Less: Fair value of plan assets		766			649			0			0
Funded status at end of year	$	(46	)	$	(121	)	$	(193	)	$	(175	)

(1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $762 million at December 31, 2017 and $724 million at December 31, 2016.

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

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2017			2016			2017			2016
Accrued benefit costs and other current liabilities	$	(7	)	$	(1	)	$	(10	)	$	(9	)
Deferred credits and other liabilities		(30	)		(80	)		(154	)		(139	)
	$	(37	)	$	(81	)	$	(164	)	$	(148	)

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

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2017		2016		2017			2016
Net actuarial loss (gain)	$	215	$	236	$	70		$	50
Prior service cost (credit)		1		1		(13	)		(15	)
Amount recognized	$	216	$	237	$	57		$	35

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2017			2016			2017			2016
Discount rate		3.62	%		4.11	%		3.70	%		4.28	%
Rate of compensation increase-weighted average		3.32	%		2.57	%		3.31	%		2.48	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.58	%		6.83	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

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

(millions)	1% Increase		1 % Decrease
Effect on PBO	$	7	$	(6	)

The discount rate assumption used to determine the December 31, 2017 and 2016 benefit obligation was based on a cash flow matching technique that matches yields from high-quality (AA-rated, non-callable) corporate bonds to TECO Energy’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption. The discount rate assumption used to determine the December 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructed hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculated all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selected the portfolio with the highest yield and used that yield as the recommended discount rate. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate.

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

TECO Energy	Pension Benefits									Other Benefits (1)
	2017			2016			2015			2017			2016			2015
(millions)
Service cost	$	20		$	19		$	21		$	2		$	2		$	2
Interest cost		31			31			30			7			7			7
Expected return on plan assets		(48	)		(46	)		(43	)		0			0			0
Amortization of:
Actuarial loss		17			16			15			0			0			0
Prior service (benefit) cost		0			0			0			(2	)		(2	)		(3	)
Curtailment loss (gain)		0			1			0			0			0			0
Settlement loss (2)		7			1			0			0			0			0
Net periodic benefit cost	$	27		$	22		$	23		$	7		$	7		$	6

New prior service cost		0			1		$	0		$	0	$	0	$	0
Net loss (gain) arising during the year		(5	)		47			75			22		5		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2		2		3
Amortization or settlement of actuarial gain (loss)		(24	)		(17	)		(15	)		0		0		0
Total recognized in OCI and regulatory assets	$	(29	)	$	31		$	60		$	24	$	7	$	3
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	53		$	83		$	31	$	14	$	9

(1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2) 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 costs for pension benefits was $14 million, $13 million and $14 million for 2017, 2016 and 2015, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $6 million, $6 million and $6 million for 2017, 2016 and 2015, respectively.

The estimated net loss for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year is $14 million. There are no prior service credits to be amortized from regulatory assets into net periodic benefit cost in 2018 for the other postretirement benefit plan.

TEC’s postretirement benefit plans were not explicitly impacted by the Merger. However, as a result of the Merger, TECO Energy remeasured its postretirement benefits plans on the Merger effective date, July 1, 2016. As a result of the remeasurements, TEC’s net periodic benefit cost increased by $1 million for pension benefits and $0 million for other postretirement plan benefits for the six months ended December 31, 2016. Additionally, a curtailment loss for the SERP of $1 million was recognized by TECO Energy in 2016 as a result of retirements due to the Merger. In addition, TECO Energy recognized a settlement charge related to the SERP of $7 million in 2017 due to retirements that have occurred as a result of the Merger. TEC was not impacted by the curtailment loss or settlement charge.

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

	Pension Benefits									Other Benefits
	2017			2016			2015			2017			2016			2015
Discount rate		4.110	%		4.688	%		4.258	%		4.280	%	4.667%/3.85%				4.206	%
Expected long-term return on plan assets		7.00	%		7.00	%		7.00	%	N/A			N/A			N/A
Rate of compensation increase		2.57	%		2.59	%		3.87	%		2.48	%		2.50	%		3.86	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.83	%		7.05	%		7.00	%
Ultimate rate	n/a			n/a			n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			n/a			2038			2038			2025

The discount rate assumption used to determine the benefit cost for 2017 and from the Merger date to December 31, 2016 was based on the same technique that was used to determine the December 31, 2017 and 2016 benefit obligation as discussed above. The discount rate assumption used to determine the January 1, 2016 through June 30, 2016 and the 2015 benefit cost was based on the same technique that was used to determine the December 31, 2015 benefit obligation as discussed above. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2017, TECO Energy’s pension plan’s assets increased approximately 19%.

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

A one-percentage-point change in assumed health care cost trend rates would have a less than $1 million effect on net periodic benefit cost.

Pension Plan Assets

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

TECO Energy	2017 Target Allocation			ActualAllocation, End of Year
Asset Category				2017			2016
Equity securities	47%-53%				51	%		56	%
Fixed income securities	47%-53%				49	%		44	%
Total		100	%		100	%		100	%

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

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

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

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of December 31, 2017 and 2016.

Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2017
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	3		$	0		$	0	$	0	$	3
Accounts receivable		14			0			0		0		14
Accounts payable		(43	)		0			0		0		(43	)
Short-term investment funds (STIFs)		14			0			0		0		14
Common stocks		44			0			0		0		44
Real estate investment trusts (REITs)		4			0			0		0		4
Mutual funds		196			0			0		0		196
Municipal bonds		0			2			0		0		2
Government bonds		0			55			0		0		55
Corporate bonds		0			45			0		0		45
Mortgage-backed securities (MBS)		0			(1	)		0		0		(1	)
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Swaps		0			4			0		0		4
Purchase options (swaptions)		0			1			0		0		1
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		232			105			0		0		337
Common and collective trusts (1)		0			0			0		326		326
Mutual fund (1)		0			0			0		103		103
Total investments	$	232		$	105		$	0	$	429	$	766

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

TECO Energy	At Fair Value as of December 31, 2016
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	2		$	0		$	0	$	0	$	2
Accounts receivable		27			0			0		0		27
Accounts payable		(59	)		0			0		0		(59	)
Cash collateral		1			0			0		0		1
STIFs		12			0			0		0		12
Common stocks		44			0			0		0		44
REITs		3			0			0		0		3
Mutual funds		181			0			0		0		181
Municipal bonds		0			3			0		0		3
Government bonds		0			32			0		0		32
Corporate bonds		0			39			0		0		39
MBS		0			9			0		0		9
CMOs		0			1			0		0		1
Swaps		0			1			0		0		1
Purchase options (swaptions)		0			2			0		0		2
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		211			85			0		0		296
Common and collective trusts (1)		0			0			0		270		270
Mutual fund (1)		0			0			0		83		83
Total investments	$	211		$	85		$	0	$	353	$	649

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

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

• Cash collateral is valued at cash posted due to its short-term nature.

• The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

• The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

• The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

• The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

• The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-ended mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is a closed-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. There were no unfunded commitments as of December 31, 2017.

• The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain  funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 5 business days. There were no unfunded commitments as of December 31, 2017.

• Discounted notes are valued at amortized cost.

• Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Additionally, the non-qualified SERP had $17 million and $41 million of assets as of December 31, 2017 and 2016, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in TEC’s Consolidated Balance Sheets rather than being netted with the related liability. The non-qualified trust holds investments in a money market fund. The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make it a level 1 asset. The SERP was fully funded as of December 31, 2017 and 2016.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan.

Contributions

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

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

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

The qualified pension plan’s actuarial value of assets, including credit balance, was 118.1% of the Pension Protection Act funded target as of January 1, 2017 and is estimated at 117.9% of the Pension Protection Act funded target as of January 1, 2018.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability. TECO Energy made contributions to this plan in 2017, 2016 and 2015, which met the minimum funding requirements for 2017, 2016 and 2015. TEC’s portion of the contribution in 2017 was $36 million and in 2016 was $31 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2018 contribution to be $37 million. TEC estimates its portion of annual contributions from 2019 to 2022 will range from $6 million to $17 million per year based on current assumptions. The amounts TECO Energy expects to make are in excess of the minimum funding required under ERISA guidelines.

   TEC’s portion of the contributions to the SERP in 2017, 2016 and 2015 were zero, zero and $15 million, respectively. TEC’s contribution in 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year. The fully-funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2018.  

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between January 1, 1990 and June 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2018, TEC expects to make a contribution of about $10 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

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

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2018	$	58	$	12
2019		56		12
2020		56		12
2021		59		12
2022		61		12
2023-2027		323		61

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period of January 2015 to December 2016, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2017, 2016 and 2015, TEC’s portion of expense totaled $11 million, $8 million and $8 million, respectively, related to the matching contributions made to this plan.

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Short-Term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Credit Facilities

	December 31, 2017						December 31, 2016
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	5	$	1	$	325	$	40	$	1
3-year accounts receivable facility (3)		150		0		0		150		130		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	775	$	305	$	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.

(4) This 1-year facility matures on November 1, 2018.

At December 31, 2017, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2017 and 2016 was 2.07% and 1.49%, respectively.

Tampa Electric Company Credit Agreement

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 the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin.

Tampa Electric Company Accounts Receivable Facility

On March 24, 2015, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to appoint a new program agent; add new lenders; and extend the scheduled termination date to March 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement and (b) a Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2017. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either the BTMU’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin.  In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of December 31, 2017, TEC was in compliance with the requirements of the Loan Agreement.  

Amendment of Tampa Electric Company Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment 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); provides for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; includes a $50 million letter of credit facility; and made other technical changes.  

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Long-Term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

7. Long-Term Debt  

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.

Issuance of Tampa Electric Company 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes). Until November 15, 2044, TEC may redeem all or any part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after November 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Purchase in Lieu of Redemption of Revenue Refunding Bonds

  At December 31, 2017 and 2016, $233 million of tax-exempt bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric to provide an opportunity to evaluate refinancing alternatives including $20 million variable-rate bonds due 2020, $52 million term-rate refunding bonds due 2025, $75 million term-rate bonds due 2030, and $86 million term-rate refunding bonds due 2034.

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Merger with Emera

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Merger with Emera

8. Merger with Emera

As disclosed in Note 1, 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.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was cancelled and converted automatically into the right to receive $27.55 in cash, without interest. This represents an aggregate purchase price of approximately $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion).

The Merger Agreement requires Emera, among other things, (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 and TEC’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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of 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.

Tampa Electric Legal Proceeding

As a result of a tragic industrial accident at Big Bend Power Station on June 29, 2017, five workers (including one Tampa Electric employee and four contract workers) were killed and one other worker sustained serious injuries. Tampa Electric believes that any costs associated with the damages, injuries, fatalities and other losses related to the incident are substantially covered by insurance.  Tampa Electric recorded any accruals for all material insured and non-insured costs and related insurance recoveries resulting from the incident.

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 MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 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 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. See Note 3 for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this liability.

Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015, totaled $2 million, $2 million and $4 million, respectively. TEC also has other purchase obligations for 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 December 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2018	$	10	$	2	$	303	$	444	$	759
2019		0		2		74		230		306
2020		0		2		7		177		186
2021		0		2		7		147		156
2022		0		2		7		141		150
Thereafter		0		36		18		1,029		1,083
Total future minimum payments	$	10	$	46	$	416	$	2,168	$	2,640

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2017, TEC was in compliance with all required financial covenants.

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2017			2016		2015
Natural gas sales to/(from) affiliates	$	(4	)	$	0	$	1
Services received from affiliates		67			66		69
Dividends to TECO Energy		292			289		268
Equity contributions from TECO Energy		190			150		175

Services received from affiliates primarily include shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning on January 1, 2015. Through TSI, TECO Energy provided TEC with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to TEC based on cost-causative allocation methods or the Modified Massachusetts Formula.

Amounts due from or to affiliates at December 31,

(millions)	2017		2016
Accounts receivable (1)	$	2	$	7
Accounts payable (1)		19		18
Taxes receivable (2)		3		0
Taxes payable (2)		2		7

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2) Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

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Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

11. Segment Information

Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC, but are included in determining reportable segments.

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 750,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 375,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2017
Revenues - external	$	2,052	$	418	$	0			$	2,470
Sales to affiliates		2		20		(22	)			0
Total revenues		2,054		438		(22	)			2,470
Depreciation and amortization		300		50		0				350
Total interest charges		104		15		0				119
Provision for income taxes		171		26		0				197
Net income		273		43		0				316
Total assets		7,635		1,284		(555	)	(1)		8,364
Capital expenditures		518		122		0				640
2016
Revenues - external	$	1,964	$	432	$	0			$	2,396
Sales to affiliates		1		7		(8	)			0
Total revenues		1,965		439		(8	)			2,396
Depreciation and amortization		268		60		0				328
Total interest charges		91		15		0				106
Provision for income taxes		130		22		0				152
Net income		251		35		0				286
Total assets		7,357		1,191		(465	)	(1)		8,083
Capital expenditures		594		133		0				727
2015
Revenues - external	$	2,018	$	401	$	0			$	2,419
Sales to affiliates		0		6		(6	)			0
Total revenues		2,018		407		(6	)			2,419
Depreciation and amortization		256		57		0				313
Total interest charges		95		15		0				110
Provision for income taxes		144		22		0				166
Net income		241		35		0				276
Total assets		7,004		1,136		(431	)	(1)		7,709
Capital expenditures		593		94		0				687

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2017

Other Comprehensive Income [Abstract]

Other Comprehensive Income

12. Other Comprehensive Income

TEC reported the following OCI related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income

(millions)	Gross		Tax			Net
2017
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2016
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2015
Unrealized gain on cash flow hedges	$	4	$	(1	)	$	3
Reclassification from AOCI to net income		2		(1	)		1
Gain on cash flow hedges		6		(2	)		4
Total other comprehensive income	$	6	$	(2	)	$	4

Accumulated Other Comprehensive Loss

(millions) As of December 31,	2017			2016
Net unrealized losses from cash flow hedges (1)	$	(2	)	$	(3	)
Total accumulated other comprehensive loss	$	(2	)	$	(3	)

(1) Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

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Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

13. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

• To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

• To limit the exposure to interest rate fluctuations on debt securities.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on 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 ending on December 31, 2022. 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 14). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2016, 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 December 31, 2017 and 2016 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were zero and $17 million derivative assets as of December 31, 2017 and 2016, respectively. There were $1 million and zero derivative liabilities as of December 31, 2017 and 2016, respectively. 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 December 31, 2017 and 2016.

All of the derivative asset and liabilities at December 31, 2017 and 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 December 31, 2017, net pre-tax reductions of $1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The December 31, 2017 and 2016 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 years ended December 31, 2017, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended December 31, 2017, 2016 and 2015 is presented in Note 12. 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. The following table presents TEC’s derivative volumes that, as of December 31, 2017, are expected to settle during the 2018 fiscal year:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2018		0		7

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 December 31, 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 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.  

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

14. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As 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 table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016.

Recurring Derivative Fair Value Measures

	As of December 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0	$	1	$	0	$	1
	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 13).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At December 31, 2017 and 2016, 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 December 31, 2017 and 2016, the fair value of TEC’s short-term debt was not materially different from the carrying 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 Notes 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2017

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Variable Interest Entities

15. 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 121 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 $16 million, $62 million and $34 million, under these PPAs for the three years ended December 31, 2017, 2016 and 2015, 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. Excluding the payments for energy under these contracts, TEC’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

16. Asset Retirement Obligations

TEC accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices.

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

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

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

	December 31,
(millions)	2017			2016
Beginning balance	$	45		$	6
Additional liabilities (1)		1			36
Liabilities settled		(1	)		0
Revisions to estimated cash flows		0			3
Other (2)		2			0
Ending balance	$	47		$	45

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The increase in the ARO in 2016 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed.    

(2) Includes accretion recorded as a deferred regulatory asset.  

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation

17. Stock-Based Compensation

Performance Share Unit Plan

Emera has a performance share unit (PSU) plan, and TEC employees started participating in the plan in 2017.  The PSU liability is marked-to-market at the end of each period based on the common share price in CAD at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA.

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan.  PSUs are granted annually for three-year overlapping performance cycles.  PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as the Dividend Reinvestment Plan (DRIP).  The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the Emera Management Resources and Compensation Committee early in the following year.  The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

A summary of the activity related to TEC employee PSUs for the year ended December 31, 2017 is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2016		0		$	0	$	0
Granted including DRIP		144			45.40		6
Exercised		(5	)		30.57		0
Forfeited		(17	)		45.41		(1	)
Transferred		11			38.51		1
Outstanding as of December 31, 2017		133		$	45.11	$	6

Compensation cost recognized for the PSU plan for the year ended December 31, 2017 was $2 million. Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2017were $1 million. As of December 31, 2017, there was $4 million of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.

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Schedule II - Valuation and Qualifying Accounts and Reserves

12 Months Ended

Dec. 31, 2017

Valuation And Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts and Reserves

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended December 31, 2017, 2016 and 2015

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions  (1)		Period
Allowance for Uncollectible Accounts:
2017	$	1	$	5	$	0	$	5	$	1
2016	$	1	$	3	$	0	$	3	$	1
2015	$	1	$	3	$	0	$	3	$	1

(1) Write-off of individual bad debt accounts

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.

TEC is a wholly-owned subsidiary of TECO Energy, Inc. and contains electric and natural gas divisions. Intercompany balances and transactions within the divisions have been eliminated in consolidation.

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC 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. See Note 8 for further information.

Cash Equivalents

Cash Equivalents

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

Property, Plant and Equipment

Property, Plant and Equipment

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

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

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2017			December 31, 2016
Electric generation	21-56 years	$	4,766		$	4,102
Electric transmission	28-77 years		859			837
Electric distribution	14-56 years		2,437			2,331
Gas transmission and distribution	15-77 years		1,534			1,429
General plant and other	8-43 years		579			438
Total cost			10,175			9,137
Less accumulated depreciation			(2,994	)		(2,826	)
Construction work in progress			263			892
Total property, plant and equipment, net		$	7,444		$	7,203

Depreciation

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7%, 3.5% and 3.7% for 2017, 2016 and 2015, respectively. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $332 million, $304 million and $306 million, respectively. See Note 3 for information regarding an agreement approved by the FPSC that, among other things, reduced PGS’s annual depreciation expense by $16 million beginning in 2016.

Tampa Electric and PGS compute depreciation and amortization using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2017, 2016 and 2015, the rate was 6.46%. Total AFUDC for the years ended December 31, 2017, 2016 and 2015 was $2 million, $36 million and $26 million, respectively. The decrease in 2017 and increase in 2016 is a result of the Polk Power Station conversion project, which was completed in January 2017.

Inventory

Inventory

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

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3). TEC’s retail and wholesale businesses are regulated by the FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Deferred Income Taxes

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details, including the impacts of tax reform.

Investment Tax Credits

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property. As of December 31, 2017 and 2016, ITCs were $22 million and $11 million, respectively.

Revenue Recognition

Revenue Recognition

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

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

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2017 and 2016, unbilled revenues of $66 million and $54 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Revenues and Cost Recovery

Revenues and Cost Recovery

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

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-affiliates at a cost of $46 million, $104 million and $79 million, for the years ended December 31, 2017, 2016 and 2015, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Receivables and Allowance for Uncollectible Accounts

Receivables and Allowance for Uncollectible Accounts

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

Accounting for Franchise Fees and Gross Receipts Taxes

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $113 million, $117 million and $117 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Deferred Credits and Other Liabilities

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), asset retirement obligations (see Note 16), and medical and general liability claims incurred but not reported.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2017 and 2016 ranged from 2.74% to 4.00% and 2.69% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

Cash Flows Related to Derivatives and Hedging Activities

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

Reclassifications

Reclassifications

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

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Schedule of Property, Plant and Equipment

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2017			December 31, 2016
Electric generation	21-56 years	$	4,766		$	4,102
Electric transmission	28-77 years		859			837
Electric distribution	14-56 years		2,437			2,331
Gas transmission and distribution	15-77 years		1,534			1,429
General plant and other	8-43 years		579			438
Total cost			10,175			9,137
Less accumulated depreciation			(2,994	)		(2,826	)
Construction work in progress			263			892
Total property, plant and equipment, net		$	7,444		$	7,203

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Regulatory (Tables)

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of December 31, 2017 and 2016 are presented in the following table:

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2017		2016
Regulatory assets:
Regulatory tax asset (1)	$	45	$	86
Cost-recovery clauses - deferred balances (2)		12		8
Cost-recovery clauses - offsets to derivative liabilities (2)		1		0
Environmental remediation (3)		33		37
Postretirement benefits (4)		272		272
Storm reserve (5)		47		0
Other		23		18
Total regulatory assets		433		421
Less: Current portion		77		28
Long-term regulatory assets	$	356	$	393
Regulatory liabilities:
Regulatory tax liability (6)	$	730	$	6
Cost-recovery clauses (2)		32		112
Cost-recovery clauses - offsets to derivative assets (2)		0		17
Storm reserve (5)		0		56
Accumulated reserve—cost of removal (7)		518		547
Other		5		7
Total regulatory liabilities		1,285		745
Less: Current portion		58		154
Long-term regulatory liabilities	$	1,227	$	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 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. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. 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 the Tampa Electric Storm Restoration Cost Recovery section 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 within a 12-month period.

(6) The increase in the regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 for further information.

(7) 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.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

Income tax expense consists of the following components:

(millions)
For the year ended December 31,	2017			2016		2015
Current income taxes
Federal	$	(1	)	$	53	$	38
State		6			12		8
Deferred income taxes
Federal		170			76		105
State		23			11		15
Investment tax credits, net of amortization		(1	)		0		0
Total income tax expense	$	197		$	152	$	166

Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes

For the three years presented, the overall effective tax rate differs from the 35% U.S. federal statutory rate as presented below:

(millions)
For the year ended December 31,	2017			2016			2015
Income before provision for income taxes	$	513		$	438		$	442
Federal statutory income tax rates		35	%		35	%		35	%
Income taxes, at statutory income tax rate		180			153			155
Increase (decrease) due to
State income tax, net of federal income tax		19			15			15
AFUDC-equity		(1	)		(8	)		(6	)
Tax credits		(3	)		(7	)		0
Other		2			(1	)		2
Total income tax expense on consolidated statements of income	$	197		$	152		$	166
Income tax expense as a percent of income from continuing operations,    before income taxes		38.4	%		34.8	%		37.5	%

Schedule of Deferred Tax Assets and Liabilities

The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

(millions)
As of December 31,	2017			2016
Deferred tax liabilities (1)
Property related	$	924		$	1,549
Pension and postretirement benefits		57			105
Pension		43			69
Total deferred tax liabilities		1,024			1,723
Deferred tax assets (1)
Loss and credit carryforwards (2)		91			91
Medical benefits		24			47
Insurance reserves		(5	)		27
Pension and postretirement benefits		57			105
Capitalized energy conservation assistance costs		13			23
Other		19			23
Total deferred tax assets		199			316
Total deferred tax liability, net	$	825		$	1,407

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $8 million.

Schedule of Unrecognized Tax Benefits

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2017		2016		2015
Balance at January 1,	$	7	$	0	$	0
Increases due to tax positions related to current year		1		7		0
Balance at December 31	$	8	$	7	$	0

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Employee Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Amount Recognized in Balance Sheet

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

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2017			2016			2017			2016
Accrued benefit costs and other current liabilities	$	(7	)	$	(1	)	$	(10	)	$	(9	)
Deferred credits and other liabilities		(30	)		(80	)		(154	)		(139	)
	$	(37	)	$	(81	)	$	(164	)	$	(148	)

Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets

The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2017		2016		2017			2016
Net actuarial loss (gain)	$	215	$	236	$	70		$	50
Prior service cost (credit)		1		1		(13	)		(15	)
Amount recognized	$	216	$	237	$	57		$	35

Benefit Obligations [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2017			2016			2017			2016
Discount rate		3.62	%		4.11	%		3.70	%		4.28	%
Rate of compensation increase-weighted average		3.32	%		2.57	%		3.31	%		2.48	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.58	%		6.83	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

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

(millions)	1% Increase		1 % Decrease
Effect on PBO	$	7	$	(6	)

Net Periodic Benefit Cost [Member]

Schedule of Assumptions Used to Determine Benefit

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

	Pension Benefits									Other Benefits
	2017			2016			2015			2017			2016			2015
Discount rate		4.110	%		4.688	%		4.258	%		4.280	%	4.667%/3.85%				4.206	%
Expected long-term return on plan assets		7.00	%		7.00	%		7.00	%	N/A			N/A			N/A
Rate of compensation increase		2.57	%		2.59	%		3.87	%		2.48	%		2.50	%		3.86	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.83	%		7.05	%		7.00	%
Ultimate rate	n/a			n/a			n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			n/a			2038			2038			2025

Effect on Expenses [Member]

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have a less than $1 million effect on net periodic benefit cost.

TECO Energy [Member]

Schedule of Change in Plan Assets

Change in plan assets
Fair value of plan assets at beginning of year	$	649		$	625		$	0		$	0
Actual return on plan assets		122			55			0			0
Employer contributions		46			38			(3	)		(3	)
Employer direct benefit payments		27			3			16			14
Plan participants’ contributions		0			0			3			3
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Direct benefit payments		(1	)		(1	)		0			0
Fair value of plan assets at end of year (1)	$	766		$	649		$	0		$	0

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

Schedule of Net Periodic Benefit Cost

TECO Energy	Pension Benefits									Other Benefits (1)
	2017			2016			2015			2017			2016			2015
(millions)
Service cost	$	20		$	19		$	21		$	2		$	2		$	2
Interest cost		31			31			30			7			7			7
Expected return on plan assets		(48	)		(46	)		(43	)		0			0			0
Amortization of:
Actuarial loss		17			16			15			0			0			0
Prior service (benefit) cost		0			0			0			(2	)		(2	)		(3	)
Curtailment loss (gain)		0			1			0			0			0			0
Settlement loss (2)		7			1			0			0			0			0
Net periodic benefit cost	$	27		$	22		$	23		$	7		$	7		$	6

Schedule of Amounts Recognized in OCI and Regulatory Assets

New prior service cost		0			1		$	0		$	0	$	0	$	0
Net loss (gain) arising during the year		(5	)		47			75			22		5		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2		2		3
Amortization or settlement of actuarial gain (loss)		(24	)		(17	)		(15	)		0		0		0
Total recognized in OCI and regulatory assets	$	(29	)	$	31		$	60		$	24	$	7	$	3
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	53		$	83		$	31	$	14	$	9

(1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2) 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.

Schedule of Pension Plan Assets

TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

TECO Energy	2017 Target Allocation			ActualAllocation, End of Year
Asset Category				2017			2016
Equity securities	47%-53%				51	%		56	%
Fixed income securities	47%-53%				49	%		44	%
Total		100	%		100	%		100	%

Schedule of Fair Value Hierarchy Plan's Investments

The following table sets forth by level within the fair value hierarchy the plan’s investments as of December 31, 2017 and 2016.

Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2017
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	3		$	0		$	0	$	0	$	3
Accounts receivable		14			0			0		0		14
Accounts payable		(43	)		0			0		0		(43	)
Short-term investment funds (STIFs)		14			0			0		0		14
Common stocks		44			0			0		0		44
Real estate investment trusts (REITs)		4			0			0		0		4
Mutual funds		196			0			0		0		196
Municipal bonds		0			2			0		0		2
Government bonds		0			55			0		0		55
Corporate bonds		0			45			0		0		45
Mortgage-backed securities (MBS)		0			(1	)		0		0		(1	)
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Swaps		0			4			0		0		4
Purchase options (swaptions)		0			1			0		0		1
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		232			105			0		0		337
Common and collective trusts (1)		0			0			0		326		326
Mutual fund (1)		0			0			0		103		103
Total investments	$	232		$	105		$	0	$	429	$	766

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

TECO Energy	At Fair Value as of December 31, 2016
(millions)
	Level 1			Level 2			Level 3		NAV (1)		Total
Cash	$	2		$	0		$	0	$	0	$	2
Accounts receivable		27			0			0		0		27
Accounts payable		(59	)		0			0		0		(59	)
Cash collateral		1			0			0		0		1
STIFs		12			0			0		0		12
Common stocks		44			0			0		0		44
REITs		3			0			0		0		3
Mutual funds		181			0			0		0		181
Municipal bonds		0			3			0		0		3
Government bonds		0			32			0		0		32
Corporate bonds		0			39			0		0		39
MBS		0			9			0		0		9
CMOs		0			1			0		0		1
Swaps		0			1			0		0		1
Purchase options (swaptions)		0			2			0		0		2
Written options (swaptions)		0			(2	)		0		0		(2	)
Investments not utilizing the practical expedient		211			85			0		0		296
Common and collective trusts (1)		0			0			0		270		270
Mutual fund (1)		0			0			0		83		83
Total investments	$	211		$	85		$	0	$	353	$	649

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

• Cash collateral is valued at cash posted due to its short-term nature.

• The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

• The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

• The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

• The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

• The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-ended mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is a closed-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. There were no unfunded commitments as of December 31, 2017.

• The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain  funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 5 business days. There were no unfunded commitments as of December 31, 2017.

• Discounted notes are valued at amortized cost.

• Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Schedule of Benefit Payments

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2018	$	58	$	12
2019		56		12
2020		56		12
2021		59		12
2022		61		12
2023-2027		323		61

TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]

Schedule of Change in Benefit Obligation

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2017			2016			2017			2016
Change in benefit obligation
Net benefit obligation at beginning of year	$	770		$	733		$	175		$	172
Service cost		20			19			2			2
Interest cost		31			31			7			7
Plan participants’ contributions		0			0			3			3
Plan amendments		0			1			0			0
Plan curtailment		(1	)		1			0			0
Plan settlement		(26	)		(2	)		0			0
Benefits paid		(51	)		(69	)		(16	)		(14	)
Actuarial loss (gain)		69			56			22			5
Net benefit obligation at end of year	$	812		$	770		$	193		$	175

1. Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan

Schedule of Funded status

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

TECO Energy	Pension Benefits						Other Benefits (1)
Funded Status
(millions)	2017			2016			2017			2016
Benefit obligation (PBO/APBO)	$	812		$	770		$	193		$	175
Less: Fair value of plan assets		766			649			0			0
Funded status at end of year	$	(46	)	$	(121	)	$	(193	)	$	(175	)

(1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

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Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Short-Term Debt Credit Facilities

Credit Facilities

	December 31, 2017						December 31, 2016
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	5	$	1	$	325	$	40	$	1
3-year accounts receivable facility (3)		150		0		0		150		130		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	775	$	305	$	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.

(4) This 1-year facility matures on November 1, 2018.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 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 December 31, 2017:

					Long-term Service
	Purchased		Operating		Agreements/Capital		Clause Recoverable
(millions)	Power		Leases		Projects		Commitments		Total
Year ended December 31:
2018	$	10	$	2	$	303	$	444	$	759
2019		0		2		74		230		306
2020		0		2		7		177		186
2021		0		2		7		147		156
2022		0		2		7		141		150
Thereafter		0		36		18		1,029		1,083
Total future minimum payments	$	10	$	46	$	416	$	2,168	$	2,640

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2017			2016		2015
Natural gas sales to/(from) affiliates	$	(4	)	$	0	$	1
Services received from affiliates		67			66		69
Dividends to TECO Energy		292			289		268
Equity contributions from TECO Energy		190			150		175

Amounts due from or to affiliates at December 31,

(millions)	2017		2016
Accounts receivable (1)	$	2	$	7
Accounts payable (1)		19		18
Taxes receivable (2)		3		0
Taxes payable (2)		2		7

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2) Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Information

Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC, but are included in determining reportable segments.

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 750,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 375,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2017
Revenues - external	$	2,052	$	418	$	0			$	2,470
Sales to affiliates		2		20		(22	)			0
Total revenues		2,054		438		(22	)			2,470
Depreciation and amortization		300		50		0				350
Total interest charges		104		15		0				119
Provision for income taxes		171		26		0				197
Net income		273		43		0				316
Total assets		7,635		1,284		(555	)	(1)		8,364
Capital expenditures		518		122		0				640
2016
Revenues - external	$	1,964	$	432	$	0			$	2,396
Sales to affiliates		1		7		(8	)			0
Total revenues		1,965		439		(8	)			2,396
Depreciation and amortization		268		60		0				328
Total interest charges		91		15		0				106
Provision for income taxes		130		22		0				152
Net income		251		35		0				286
Total assets		7,357		1,191		(465	)	(1)		8,083
Capital expenditures		594		133		0				727
2015
Revenues - external	$	2,018	$	401	$	0			$	2,419
Sales to affiliates		0		6		(6	)			0
Total revenues		2,018		407		(6	)			2,419
Depreciation and amortization		256		57		0				313
Total interest charges		95		15		0				110
Provision for income taxes		144		22		0				166
Net income		241		35		0				276
Total assets		7,004		1,136		(431	)	(1)		7,709
Capital expenditures		593		94		0				687

(1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2017

Other Comprehensive Income [Abstract]

Other Comprehensive Income

TEC reported the following OCI related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income

(millions)	Gross		Tax			Net
2017
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2016
Unrealized gain on cash flow hedges	$	0	$	0		$	0
Reclassification from AOCI to net income		1		0			1
Gain on cash flow hedges		1		0			1
Total other comprehensive income	$	1	$	0		$	1
2015
Unrealized gain on cash flow hedges	$	4	$	(1	)	$	3
Reclassification from AOCI to net income		2		(1	)		1
Gain on cash flow hedges		6		(2	)		4
Total other comprehensive income	$	6	$	(2	)	$	4

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

(millions) As of December 31,	2017			2016
Net unrealized losses from cash flow hedges (1)	$	(2	)	$	(3	)
Total accumulated other comprehensive loss	$	(2	)	$	(3	)

(1) Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Volumes Expected to Settle

The following table presents TEC’s derivative volumes that, as of December 31, 2017, are expected to settle during the 2018 fiscal year:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2018		0		7

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 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 table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016.

Recurring Derivative Fair Value Measures

	As of December 31, 2017
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0	$	1	$	0	$	1
	As of December 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0	$	17	$	0	$	17

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

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

	December 31,
(millions)	2017			2016
Beginning balance	$	45		$	6
Additional liabilities (1)		1			36
Liabilities settled		(1	)		0
Revisions to estimated cash flows		0			3
Other (2)		2			0
Ending balance	$	47		$	45

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The increase in the ARO in 2016 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed.    

(2) Includes accretion recorded as a deferred regulatory asset.  

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Activity Related to TEC Employee PSUs

A summary of the activity related to TEC employee PSUs for the year ended December 31, 2017 is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2016		0		$	0	$	0
Granted including DRIP		144			45.40		6
Exercised		(5	)		30.57		0
Forfeited		(17	)		45.41		(1	)
Transferred		11			38.51		1
Outstanding as of December 31, 2017		133		$	45.11	$	6

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Significant Accounting Policies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) Segment	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | Segment	2
Percentage of original cost of depreciable property	3.70%	3.50%	3.70%
Depreciation expense	$ 332	$ 304	$ 306
Allowance for funds used during construction rate	6.46%	6.46%	6.46%
Allowance for funds used during construction	$ 2	$ 36	$ 26
Investment tax credits	22	11
Unbilled revenues	66	54
Purchased power	46	104	79
Franchise fees and gross receipts taxes	$ 113	$ 117	$ 117
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.74%	2.69%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	4.00%	4.00%
PGS [Member]
Summary Of Significant Accounting Policies [Line Items]
Reduction in annual depreciation expense		$ 16

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Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Total cost	$ 10,175	$ 9,137
Less accumulated depreciation	(2,994)	(2,826)
Construction work in progress	263	892
Total property, plant and equipment, net	7,444	7,203
Electric Generation [Member]
Property Plant And Equipment [Line Items]
Total cost	4,766	4,102
Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	1,534	1,429
General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 579	438
Minimum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	21 years
Minimum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	15 years
Minimum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	8 years
Maximum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years
Maximum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	77 years
Maximum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	43 years
Electric Transmission [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 859	837
Electric Transmission [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	28 years
Electric Transmission [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	77 years
Electric Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 2,437	$ 2,331
Electric Distribution [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	14 years
Electric Distribution [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years

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Regulatory - Additional Information (Detail)						1 Months Ended	3 Months Ended		12 Months Ended
	Dec. 12, 2017 USD ($) MW	Sep. 30, 2017 USD ($)	Sep. 27, 2017 USD ($) $ / kWac MW	Dec. 15, 2016 USD ($)	Jun. 28, 2016	May 31, 2009	Sep. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2013	Oct. 31, 2013 USD ($)	Sep. 05, 2013 USD ($)
Public Utilities General Disclosures [Line Items]
Percentage of ROE									10.25%
Return on equity range									Range of plus or minus 1%
Amortization period of Regulatory Asset									12 years
Allowed equity in the capital structure											54.00%
Storm costs incurred										$ 10,000,000
Storm costs applied to storm reserve								$ 10,000,000
Storm damage reserve								$ 46,000,000				$ 56,000,000
Regulatory assets									$ 433,000,000	$ 421,000,000
PGS [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE					10.75%	10.75%
Allowed equity in the capital structure						54.70%
PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement, approval date										Feb. 07, 2017
Regulatory assets										$ 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									$ 5,000,000	$ 16,000,000
Regulatory asset amortization beginning period										2016
Regulatory asset amortization ending period										2020
Hurricane Irma [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs		$ 70,000,000					$ 105,000,000
Hurricane Irma [Member] | Storm Reserve [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs							93,000,000
Hurricane Irma [Member] | O&M Expenses [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs							4,000,000
Hurricane Irma [Member] | Capital Expenditures [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs							8,000,000
Minimum [Member] | PGS [Member]
Public Utilities General Disclosures [Line Items]
Return on equity						9.75%
Minimum [Member] | PGS and OPC [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
Maximum [Member] | PGS [Member]
Public Utilities General Disclosures [Line Items]
Return on equity					11.75%	11.75%
Maximum [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Decrease bottom return on equity					9.75%
Solar Project Cost Recovery [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement, extended terms			four years through 2021
Settlement agreement, approval date			Nov. 06, 2017
Cost cap of project | $ / kWac			1,500
Cost savings benefit percentage for projects below cost cap			75.00%
Solar generation capacity investments			$ 850,000,000
Impact of tax reform through reduction in base revenue days			120 days
Investments in gas reserves			$ 0
Solar Project Cost Recovery [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Solar project investment term			2017
Extended agreement base rate freeze date			Jan. 01, 2018
Solar Project Cost Recovery [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Solar project investment term			2021
Extended agreement base rate freeze date			Dec. 31, 2021
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	145		150
Estimated revenue requirements	$ 26,000,000
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
Storm Reserve [Member]
Public Utilities General Disclosures [Line Items]
Regulatory assets		$ 47,000,000					$ 47,000,000		$ 47,000,000	$ 0
November 1, 2013 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge									58,000,000
November 1, 2014 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge									8,000,000
November 1, 2015 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge									5,000,000
January 16, 2017 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge									$ 110,000,000
Condition One [Member]
Public Utilities General Disclosures [Line Items]
ROE lower range limit									9.25%
Condition Two [Member]
Public Utilities General Disclosures [Line Items]
ROE lower range limit									11.25%
Computer Software [Member]
Public Utilities General Disclosures [Line Items]
Amortization period of Regulatory Asset									15 years

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Regulatory assets:
Regulatory assets	$ 433		$ 421
Less: Current portion	77		28
Long-term regulatory assets	356		393
Regulatory liabilities:
Regulatory liabilities	1,285		745
Less: Current portion	58		154
Long-term regulatory liabilities	1,227		591
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	45		86
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	12		8
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	1		0
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	33		37
Postretirement Benefit [Member]
Regulatory assets:
Regulatory assets	272		272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	47	$ 47	0
Other [Member]
Regulatory assets:
Regulatory assets	23		18
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	730		6
Cost-Recovery Clauses - Offsets to Derivative Assets [Member]
Regulatory liabilities:
Regulatory liabilities	0		17
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	32		112
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	0		56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	518		547
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 5		$ 7

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2017
Maximum [Member] | Storm Reserve [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory asset recovery period	12 months

XML

Income Taxes - Additional Information (Detail) - USD ($)			12 Months Ended
	Jan. 01, 2018	Sep. 27, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Federal statutory tax rate			35.00%	35.00%	35.00%
Deferred tax assets			$ 199,000,000	$ 316,000,000
Deferred tax liabilities			1,024,000,000	1,723,000,000
Asset expensing, uncertainty provisional percentage		100.00%
Provision for income taxes			197,000,000	152,000,000	$ 166,000,000
Change in net deferred taxes offset to regulatory tax liability			$ 755,000,000
Deferred tax assets expiration date			2033 and 2037
General business credit			$ 23,000,000
Deferred tax general business credits expiration date			2028 and 2037
Uncertain tax positions			$ 8,000,000	7,000,000	0	$ 0
Pre-tax charges (benefits)			0	0	0
Interest accrued			0	0	$ 0
Penalties			$ 0
Statutes of limitations			3 years
Income tax examination period			1 year
Federal [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward			$ 345,000,000
Federal [Member] | R&D Tax Credits [Member]
Income Taxes [Line Items]
Uncertain tax positions			8,000,000	$ 7,000,000
Florida [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward			$ 273,000,000
Subsequent Event [Member]
Income Taxes [Line Items]
Federal statutory tax rate	21.00%
Asset expensing	100.00%

XML

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current income taxes, Federal	$ (1)	$ 53	$ 38
Current income taxes, State	6	12	8
Deferred income taxes, Federal	170	76	105
Deferred income taxes, State	23	11	15
Investment tax credits, net of amortization	(1)	0	0
Total income tax expense	$ 197	$ 152	$ 166

XML

Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income before provision for income taxes	$ 513	$ 438	$ 442
Federal statutory income tax rates	35.00%	35.00%	35.00%
Income taxes, at statutory income tax rate	$ 180	$ 153	$ 155
State income tax, net of federal income tax	19	15	15
AFUDC-equity	(1)	(8)	(6)
Tax credits	(3)	(7)	0
Other	2	(1)	2
Total income tax expense	$ 197	$ 152	$ 166
Income tax expense as a percent of income from continuing operations, before income taxes	38.40%	34.80%	37.50%

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred tax liabilities
Property related	$ 924	$ 1,549
Pension and postretirement benefits	57	105
Pension	43	69
Total deferred tax liabilities	1,024	1,723
Deferred tax assets
Loss and credit carryforwards	91	91
Medical benefits	24	47
Insurance reserves	(5)	27
Pension and postretirement benefits	57	105
Capitalized energy conservation assistance costs	13	23
Other	19	23
Total deferred tax assets	199	316
Total deferred tax liability, net	$ 825	$ 1,407

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 8	$ 7	$ 0	$ 0

XML

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Beginning Balance	$ 7	$ 0	$ 0
Increases due to tax positions related to current year	1	7	0
Ending Balance	$ 8	$ 7	$ 0

XML

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)			6 Months Ended	12 Months Ended			24 Months Ended
		Jan. 02, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Percentage of tax-free subsidy under prescription drug programs				28.00%
Amortization period of Regulatory Asset				12 years
Tax of premiums paid for retiree medical benefits plan				40.00%
Redemption frequency description				The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 5 business days.
Primary provisions for pension benefits				First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%.
Percentage of qualified pension plan's actuarial value of assets			118.10%	117.90%	118.10%		118.10%
Employer contributions				$ 36,000,000	$ 31,000,000
Employer contributions in next fiscal year				$ 37,000,000
Description of defined contribution plan				Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period of January 2015 to December 2016, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals.
Defined contribution plan cost recognized				$ 11,000,000	$ 8,000,000	$ 8,000,000
Employer matching contribution percentage of eligible participant contribution		75.00%			70.00%		70.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer				25.00%			30.00%
Non-qualified SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assets			$ 41,000,000	$ 17,000,000	$ 41,000,000		$ 41,000,000
Unfunded [Member]
Defined Benefit Plan Disclosure [Line Items]
Commitments				0
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on net periodic benefit cost				1,000,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				14,000,000	13,000,000	14,000,000
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year				14,000,000
Increase in net periodic benefit cost			1,000,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				6,000,000	6,000,000	6,000,000
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year				0
Increase in net periodic benefit cost			0
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				0	0	15,000,000
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation of defined benefit pension plans			724,000,000	$ 762,000,000	724,000,000		724,000,000
Percentage of defined benefit plan's assets increased				19.00%
Defined contribution plan, maximum employer match percentage				6.00%
TECO Energy [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions				$ 17,000,000
TECO Energy [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions				6,000,000
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				27,000,000	22,000,000	23,000,000
Curtailment loss				0	1,000,000	0
Settlement charge				(7,000,000)	(1,000,000)	0
Commitments			770,000,000	812,000,000	770,000,000	733,000,000	770,000,000
Employer contributions				46,000,000	38,000,000
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				7,000,000	7,000,000	6,000,000
Curtailment loss				0	0	0
Settlement charge				0	0	0
Commitments	[1]		$ 175,000,000	193,000,000	175,000,000	$ 172,000,000	$ 175,000,000
Employer contributions	[1]			(3,000,000)	$ (3,000,000)
Employer contributions in next fiscal year				10,000,000
TECO Energy [Member] | SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Settlement charge				7,000,000
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year				$ 0

[1] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year		$ 770		$ 733
Service cost		20		19		$ 21
Interest cost		31		31		30
Plan participants’ contributions		0		0
Plan amendments		0		1
Plan curtailment		(1)		1
Plan settlement		(26)		(2)
Benefits paid		(51)		(69)
Actuarial loss (gain)		69		56
Net benefit obligation at end of year		812		770		733
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	[1]	175		172
Service cost		2	[1]	2	[1]	2
Interest cost		7	[1]	7	[1]	7
Plan participants’ contributions	[1]	3		3
Plan amendments	[1]	0		0
Plan curtailment	[1]	0		0
Plan settlement	[1]	0		0
Benefits paid	[1]	(16)		(14)
Actuarial loss (gain)	[1]	22		5
Net benefit obligation at end of year	[1]	$ 193		$ 175		$ 172

[1] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Change in plan assets
Employer contributions		$ 36		$ 31
TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year		649
Fair value of plan assets at end of year		766		649
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year		649	[1]	625
Actual return on plan assets		122		55
Employer contributions		46		38
Employer direct benefit payments		27		3
Plan participants’ contributions		0		0
Plan settlement		(26)		(2)
Benefits paid		(51)		(69)
Direct benefit payments		(1)		(1)
Fair value of plan assets at end of year	[1]	766		649
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	[2]	0	[1]	0
Actual return on plan assets	[2]	0		0
Employer contributions	[2]	(3)		(3)
Employer direct benefit payments	[2]	16		14
Plan participants’ contributions	[2]	3		3
Plan settlement	[2]	0		0
Benefits paid	[2]	(16)		(14)
Direct benefit payments	[2]	0		0
Fair value of plan assets at end of year	[1],[2]	$ 0		$ 0

[1] The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

[2] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years

XML

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 766		$ 649
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)		812		770		$ 733
Fair value of plan assets		766	[1]	649	[1]	625
Funded status at end of year		(46)		(121)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	[2]	193		175		172
Fair value of plan assets	[2]	0	[1]	0	[1]	$ 0
Other Postretirement Benefits [Member] | Florida [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)		193		175
Fair value of plan assets		0		0
Funded status at end of year		$ (193)		$ (175)

[1] The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

[2] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	$ (7)	$ (1)
Deferred credits and other liabilities	(30)	(80)
Net amount recognized at end of year	(37)	(81)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	(10)	(9)
Deferred credits and other liabilities	(154)	(139)
Net amount recognized at end of year	$ (164)	$ (148)

XML

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 215	$ 236
Prior service cost (credit)	1	1
Amount recognized	216	237
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	70	50
Prior service cost (credit)	(13)	(15)
Amount recognized	$ 57	$ 35

XML

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.62%	4.11%
Rate of compensation increase-weighted average	3.32%	2.57%
Discount rate	4.11%	4.688%	4.258%
Expected long-term return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	2.57%	2.59%	3.87%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.70%	4.28%
Rate of compensation increase-weighted average	3.31%	2.48%
Healthcare cost trend rate
Immediate rate	6.58%	6.83%
Ultimate rate	4.50%	4.50%
Year rate reaches ultimate	2038	2038
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.28%		4.206%
Rate of compensation increase	2.48%	2.50%	3.86%
Healthcare cost trend rate
Immediate rate	6.83%	7.05%	7.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	2038	2038	2025
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.667%
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%

XML

Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) - Assumed One-percentage-point Change [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on PBO - Increase	$ 7
Effect on PBO - Decrease	$ (6)

XML

Employee Postretirement Benefits - Schedule of Amounts Recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 14		$ 13		$ 14
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	6		6		6
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	20		19		21
Interest cost	31		31		30
Expected return on plan assets	(48)		(46)		(43)
Amortization of:
Actuarial loss	17		16		15
Prior service (benefit) cost	0		0		0
Curtailment loss (gain)	0		1		0
Settlement loss (2)	7		1		0
Net periodic benefit cost	27		22		23
New prior service cost	0		1		0
Net loss (gain) arising during the year	(5)		47		75
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	0		0		0
Amortization or settlement of actuarial gain (loss)	(24)		(17)		(15)
Total recognized in OCI and regulatory assets	(29)		31		60
Total recognized in net periodic benefit cost, OCI and regulatory assets	(2)		53		83
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	[1]	2	[1]	2
Interest cost	7	[1]	7	[1]	7
Expected return on plan assets	0		0		0
Amortization of:
Actuarial loss	0		0		0
Prior service (benefit) cost	(2)		(2)		(3)
Curtailment loss (gain)	0		0		0
Settlement loss (2)	0		0		0
Net periodic benefit cost	7		7		6
New prior service cost	0		0		0
Net loss (gain) arising during the year	22		5		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	2		2		3
Amortization or settlement of actuarial gain (loss)	0		0		0
Total recognized in OCI and regulatory assets	24		7		3
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ 31		$ 14		$ 9

[1] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member]	Dec. 31, 2017	Dec. 31, 2016
Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	100.00%	100.00%
Actual Asset Allocation [Member] | Equity Securities [Member]
Asset Category
Actual Allocation, End of Year	51.00%	56.00%
Actual Asset Allocation [Member] | Fixed Income Securities [Member]
Asset Category
Actual Allocation, End of Year	49.00%	44.00%
Target Allocation [Member]
Asset Category
Target Allocation	100.00%
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%

XML

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 766	$ 649
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	2
Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	12
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	44
Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	3
Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)	9
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	196	181
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	3
Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	55	32
Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45	39
Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	337	296
Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	326	270
Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103	83
Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	1
NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	429	353
NAV [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	326	270
NAV [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103	83
NAV [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
NAV [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	232	211
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	2
Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	12
Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	44
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	3
Level 1 [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	196	181
Level 1 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	232	211
Level 1 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
Level 1 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	105	85
Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)	9
Level 2 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	3
Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	55	32
Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45	39
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	105	85
Level 2 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Level 2 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 2 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	1
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	27
Accounts Receivable [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	27
Accounts Receivable [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Receivable [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(43)	(59)
Accounts Payable [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(43)	(59)
Accounts Payable [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accounts Payable [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Purchase Options (swaptions) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	2
Purchase Options (swaptions) [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Purchase Options (swaptions) [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Purchase Options (swaptions) [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	2
Purchase Options (swaptions) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Written Options (Swaptions) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(2)	(2)
Written Options (Swaptions) [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Written Options (Swaptions) [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Written Options (Swaptions) [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(2)	(2)
Written Options (Swaptions) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

XML

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions	Dec. 31, 2017 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2018	$ 58
Expected Benefit Payments - 2019	56
Expected Benefit Payments - 2020	56
Expected Benefit Payments - 2021	59
Expected Benefit Payments - 2022	61
Expected Benefit Payments - 2023 - 2027	323
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2018	12
Expected Benefit Payments - 2019	12
Expected Benefit Payments - 2020	12
Expected Benefit Payments - 2021	12
Expected Benefit Payments - 2022	12
Expected Benefit Payments - 2023 - 2027	$ 61

XML

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2017	Mar. 22, 2017	Dec. 31, 2016	Mar. 24, 2015
Line Of Credit Facility [Line Items]
Credit Facilities	$ 775,000,000	$ 50,000,000	$ 475,000,000
Borrowings Outstanding	305,000,000		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	5,000,000		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	$ 150,000,000
Borrowings Outstanding	0		130,000,000
Letters of Credit Outstanding	0		0
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000		0
Borrowings Outstanding	300,000,000		0
Letters of Credit Outstanding	$ 0		$ 0

XML

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)		12 Months Ended
	Mar. 24, 2015	Dec. 31, 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	Mar. 23, 2018
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Nov. 01, 2018	Nov. 01, 2018

XML

Short-Term Debt - Additional Information (Detail) - USD ($)				12 Months Ended
	Nov. 02, 2017	Mar. 22, 2017	Mar. 24, 2015	Dec. 31, 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		$ 775,000,000	$ 475,000,000
Increase of credit facility		175,000,000
Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity		$ 325,000,000
364-day Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity period	364 days
Line of credit facility maximum borrowing capacity	$ 300,000,000
Credit facility maturity date	Nov. 01, 2018
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity			$ 150,000,000	$ 150,000,000	$ 150,000,000
Credit facility maturity date			Mar. 23, 2018	Mar. 23, 2018	Mar. 23, 2018
Credit facility amendment date			Mar. 24, 2015
Loan agreement program and liquidity fees				0.65%
Interest rate description				TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2017. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either the BTMU’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin
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

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
	May 20, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 0	$ 83	$ 83
Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		233	233
4.20% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2045
4.20% Notes [Member] | The TEC 2015 Notes
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 250
Stated interest rate	4.20%
Debt instrument maturity date	May 15, 2045
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	0.20%
Redeemable principal amount percentage	100.00%
Debt instrument, start date of redemption	Nov. 15, 2044
Debt instrument, offering date	May 20, 2015
Variable Rate Bonds Due 2020 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 20	$ 20
Purchase in lieu of redemption, due year		2020	2020
Term Rate Refunding Bonds Due 2025 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 52	$ 52
Purchase in lieu of redemption, due year		2025	2025
Term Rate Refunding Bonds Due 2030 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 75	$ 75
Purchase in lieu of redemption, due year		2030	2030
Term Rate Refunding Bonds Due 2034 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 86	$ 86
Purchase in lieu of redemption, due year		2034	2034

XML

Merger with Emera - Additional Information (Detail) - Emera Inc. [Member] $ / shares in Units, $ in Billions	Jul. 01, 2016 USD ($) $ / shares
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding | $ / shares	$ 27.55
Aggregate purchase price	$ 10.7
Purchase price allocation for debt	4.2
Assumed debt	$ 2.3

XML

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 29, 2017 Worker
Long Term Commitments [Line Items]
Total rental expense and lease | $	$ 2	$ 2	$ 4
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites | $	$ 30
Industrial Accident [Member]
Long Term Commitments [Line Items]
Number of workers killed				5
Number of workers sustained serious injuries				1
Industrial Accident [Member] | Tampa Electric Employee [Member]
Long Term Commitments [Line Items]
Number of workers killed				1
Industrial Accident [Member] | Contract Workers [Member]
Long Term Commitments [Line Items]
Number of workers killed				4

XML

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2017 USD ($)
Commitments And Contingencies Disclosure [Abstract]
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, 2022	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	10
Future Minimum Operating Leases Payments Due, 2018	2
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, 2022	2
Future Minimum Operating Leases Payments Due, Thereafter	36
Total future minimum operating leases payments due	46
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	303
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, 2022	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	18
Total future minimum long-term service agreements/capital projects payments due	416
Future Minimum Clause Recoverable Commitments Payments Due, 2018	444
Future Minimum Clause Recoverable Commitments Payments Due, 2019	230
Future Minimum Clause Recoverable Commitments Payments Due, 2020	177
Future Minimum Clause Recoverable Commitments Payments Due, 2021	147
Future Minimum Clause Recoverable Commitments Payments Due, 2022	141
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,029
Total future minimum clause recoverable commitments payments due	2,168
Future Minimum Payments Due, 2018	759
Future Minimum Payments Due, 2019	306
Future Minimum Payments Due, 2020	186
Future Minimum Payments Due, 2021	156
Future Minimum Payments Due, 2022	150
Future Minimum Payments Due, Thereafter	1,083
Total future minimum payments	$ 2,640

XML

Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Natural gas sales to/(from) affiliates	$ (4)	$ 0	$ 1
Services received from affiliates	67	66	69
Dividends to TECO Energy	292	289
Equity contributions from TECO Energy	190	150
Accounts receivable	2	7
Accounts payable	19	18
Taxes receivable	3	0
Taxes payable	2	7
TECO Energy [Member]
Related Party Transaction [Line Items]
Dividends to TECO Energy	292	289	268
Equity contributions from TECO Energy	$ 190	$ 150	$ 175

XML

Segment Information - Additional Information (Detail)	Dec. 31, 2017 Customer
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	750,000
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	375,000

XML

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total revenues	$ 2,470	$ 2,396	$ 2,419
Depreciation and amortization	350	328	313
Total interest charges	119	106	110
Provision for income taxes	197	152	166
Net income	316	286	276
Total assets	8,364	8,083	7,709
Capital expenditures	640	727	687
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,470	2,396	2,419
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(22)	(8)	(6)
Depreciation and amortization	0	0	0
Total interest charges	0	0	0
Provision for income taxes	0	0	0
Net income	0	0	0
Total assets	(555)	(465)	(431)
Capital expenditures	0	0	0
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Eliminations [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(22)	(8)	(6)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2,054	1,965	2,018
Depreciation and amortization	300	268	256
Total interest charges	104	91	95
Provision for income taxes	171	130	144
Net income	273	251	241
Total assets	7,635	7,357	7,004
Capital expenditures	518	594	593
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,052	1,964	2,018
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	2	1	0
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	438	439	407
Depreciation and amortization	50	60	57
Total interest charges	15	15	15
Provision for income taxes	26	22	22
Net income	43	35	35
Total assets	1,284	1,191	1,136
Capital expenditures	122	133	94
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	418	432	401
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 20	$ 7	$ 6

XML

Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income, Gross		$ 1	$ 1	$ 6
Total other comprehensive income, Tax		0	0	(2)
Total other comprehensive income, net of tax		1	1	4
Net unrealized losses from cash flow hedges	[1]	(2)	(3)
Total accumulated other comprehensive loss		(2)	(3)
Accumulated Gain on Cash Flow Hedges [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0	0	4
Reclassification from AOCI to net income, Gross		1	1	2
Total other comprehensive income, Gross		1	1	6
Unrealized gain on cash flow hedges, Tax		0	0	(1)
Reclassification from AOCI to net income, Tax		0	0	(1)
Total other comprehensive income, Tax		0	0	(2)
Unrealized gain on cash flow hedges, Net		0	0	3
Reclassification from AOCI to net income, Net		1	1	1
Total other comprehensive income, net of tax		$ 1	$ 1	$ 4

[1] Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

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Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income [Abstract]
Net unrealized losses from cash flow hedges, tax benefit	$ 1	$ 2

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

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Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) - Natural Gas Contract Expected to be Settled in Year 2018 [Member]	Dec. 31, 2017 MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7

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Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 1,000,000	$ 0
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 liabilities	1,000,000
Natural gas derivative assets		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 liabilities	0
Natural gas derivative assets		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 liabilities	1,000,000
Natural gas derivative assets		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 liabilities	0	0
Natural gas derivative assets	0	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 liabilities	$ 0
Natural gas derivative assets		$ 0

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Fair Value Measurements - Additional Information (Detail) - USD ($)	Dec. 31, 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	1,000,000	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	0
Derivative liabilities	$ 0	$ 0

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Variable Interest Entities - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 46	$ 104	$ 79
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 16	$ 62	$ 34
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	121
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	250

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 45	$ 6
Additional liabilities	1	36
Liabilities settled	(1)	0
Revisions to estimated cash flows	0	3
Other	2	0
Ending balance	$ 47	$ 45

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Stock-Based Compensation - Additional Information (Detail) - Performance Share Unit Plan [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
PSUs performance cycles	3 years
Number of trading days	50 days
Compensation cost recognized	$ 2
Tax benefits related to compensation cost	1
Unrecognized compensation cost	$ 4
Weighted-average period expected to be recognized	2 years

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Stock-Based Compensation - Summary of Activity Related to Employee PSUs (Detail) - Performance Share Unit Plan [Member] CAD / shares in Units, shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD CAD / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Outstanding as of December 31, 2016 | shares	0
Number of Units, Granted including DRIP | shares	144
Number of Units, Exercised | shares	(5)
Number of Units, Forfeited | shares	(17)
Number of Units, Transferred | shares	11
Number of Units, Outstanding as of December 31, 2017 | shares	133
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2016 | CAD / shares	CAD 0
Weighted Average Grant Date Fair Value, Granted including DRIP | CAD / shares	45.40
Weighted Average Grant Date Fair Value, Exercised | CAD / shares	30.57
Weighted Average Grant Date Fair Value, Forfeited | CAD / shares	45.41
Weighted Average Grant Date Fair Value, Transferred | CAD / shares	38.51
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2017 | CAD / shares	CAD 45.11
Aggregate Intrinsic Value, Outstanding as of December 31, 2016 | CAD	CAD 0
Aggregate Intrinsic Value, Granted including DRIP | CAD	6
Aggregate Intrinsic Value, Exercised | CAD	0
Aggregate Intrinsic Value, Forfeited | CAD	(1)
Aggregate Intrinsic Value, Transferred | CAD	1
Aggregate Intrinsic Value, Outstanding as of December 31, 2017 | CAD	CAD 6

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Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Uncollectible Accounts - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 1	$ 1	$ 1
Charged to Income		5	3	3
Other Charges		0	0	0
Payments & Deductions	[1]	5	3	3
Balance at End of Period		$ 1	$ 1	$ 1

[1] Write-off of individual bad debt accounts