ck0000096271-10k_20181231.htm

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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

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.

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.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

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.

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).

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of June 30, 2018 was zero.

As of February 12, 2019, 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.

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

Term		Meaning

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
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
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)
IGCC		integrated gasification combined-cycle
IOU		investor owned utility
IRS		Internal Revenue Service
ITCs		investment tax credits
KW		kilowatt(s)
kWac		kilowatt on an alternating current basis
LNG		liquefied natural gas
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
MMBTU		one million British Thermal Units
MRV		market-related value
MW		megawatt(s)
MWH		megawatt-hour(s)
NAV		net asset value
Note		Note to consolidated financial statements
NO_x		nitrogen oxide
NPNS		normal purchase normal sale
NYMEX		New York Mercantile Exchange
O&M expenses		operations and maintenance expenses
OCI		other comprehensive income

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 764,000 customers in West Central Florida with a net winter system generating capacity of 5,238 MW at December 31, 2018. 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 392,000 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 2018 was approximately 2.0 billion therms. TEC had approximately 2,680 employees as of December 31, 2018. All of TEC’s common stock is owned by TECO Energy, a holding company.

TEC makes its SEC 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 the SEC. TEC’s electronic SEC filings are also available on the SEC’s website (www.sec.gov).

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.

TEC’s revenues consist of sales to residential, commercial, industrial and other customers. TEC’s residential load generally comprises of 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 TEC’s revenue and other financial information by operating segments, see Note 11 to the 2018 Annual TEC Consolidated Financial Statements.

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 eight photovoltaic power stations, five in Hillsborough County (of which two were placed in service in early 2019) and three in Polk County, Florida (of which one was placed in service in early 2019). Tampa Electric had approximately 2,050 employees as of December 31, 2018, of which 750 were represented by the International Brotherhood of Electrical Workers and 220 were represented by the Office and Professional Employees International Union.

In 2018, Tampa Electric’s total operating revenue was derived approximately 52% from residential sales, 28% from commercial sales, 8% from industrial sales and 12% from other sales, including sales to public authorities and off-system sales to other utilities. The sources of operating revenue and MWH sales were as follows:

(millions)	2018			2017		2016
Residential	$	1,067		$	1,006	$	1,036
Commercial		582			578		593
Industrial		161			158		161
Other sales of electricity		187			168		175
Regulatory deferrals and unbilled revenue		(2	)		78		(60	)
Total energy sales		1,995			1,988		1,905
Off system sales		11			8		6
Other		60			58		54
Total revenues	$	2,066		$	2,054	$	1,965

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.

Tampa Electric’s retail operations are regulated by the FPSC. The FPSC’s 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, including solar projects and 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 2017 and 2016 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 an additional $110 million of annual revenues 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 90 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.

Tampa Electric’s results for 2018 reflect an amended and restated settlement agreement, approved by the FPSC on November 6, 2017, that replaced the existing 2013 base rate settlement agreement described above and extended it another four years through 2021.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 2018, $51 million for 250 MWs effective January 2019, $31 million for 150 MWs effective January 2020, and an additional $10 million for 50 MWs effective on January 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. See Note 3 to the 2018 Annual TEC Consolidated Financial Statements for information regarding TEC’s SoBRA petitions. TEC began receiving revenues of $24 million annually for the first tranche in September 2018 and $46 million annually for the second tranche in January 2019.

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 (see Note 4 to the 2018 Annual TEC Consolidated Financial Statements for further information on tax reform). Additionally, an asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are achieved 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 in 2017, the amount of costs charged to the storm reserve regulatory liability in 2017 exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet. For additional information regarding storm costs, see Note 3 to the 2018 Annual TEC Consolidated Financial Statements.

On January 30, 2018, Tampa Electric filed an implementation settlement agreement with the FPSC that addressed both the recovery of storm costs and the return of tax reform benefits to customers while keeping customer rates stable in 2018. The agreement, which was approved by the FPSC on March 1, 2018, authorized Tampa Electric to net the estimated amount of storm cost recovery, including replenishment of the storm reserve to the $56 million level that existed as of October 31, 2013, against Tampa Electric’s estimated 2018 tax reform benefits. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense. See Note 3 to the 2018 Annual TEC Consolidated Financial Statements for further information on the settlement agreement.

During November 2018, the FPSC approved cost-recovery rates for the above clauses for 2019.

Tampa Electric is 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 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).

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 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.

In 2018 and 2017, approximately 82% and 69%, respectively, of Tampa Electric’s generation of electricity was natural gas-fired, with coal representing approximately 15% and 24%, respectively, oil/petroleum coke representing 2% and 6%, respectively, and solar representing 1% and 0.2%, respectively. Generation sources were impacted by running Big Bend Power Station units 1 and 2 on natural gas for all of 2018, rather than on coal as in prior years. In 2018 and 2017, Tampa Electric used its generating units to meet approximately 94% and 96%, respectively, of the total system load requirements, with the remaining 6% and 4%, respectively, coming from purchased power. 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 expects to spend approximately $850 million during 2017 through 2021 related to the 600 MW solar project recoverable under the SoBRAs as discussed above and in Note 3 to the 2018 Annual TEC Consolidated Financial Statements and approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station. The Big Bend modernization project will retire Big Bend Unit 2 and repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel, which will improve land, water and air emissions at Tampa Electric. This project is estimated to provide savings to customers compared to operating the unit on coal to the end of its life. The project will be capable of producing 1,090 MW when completed in 2023. Big Bend Unit 2 will be retired early. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric is not required to file an asset recovery filing for early retired assets. Tampa Electric expects to recover the remaining net book value of retired assets through the normal regulatory process. These investments are expected to change Tampa Electric’s fuel mix to approximately 75% natural gas, 12% coal, 7% solar and 6% other sources in 2023.

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

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 (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.

Natural Gas. Tampa Electric maintains gas commodity, pipeline transportation and storage contracts. As of December 31, 2018, approximately 60% of Tampa Electric’s 2.0 million BCF gas storage capacity was full. Tampa Electric has contracted for 75% of its expected gas needs for the April 2019 through October 2019 period. Tampa Electric expects to issue RFPs to meet its remaining 2019 gas needs and begin contracting for its 2020 requirements. Additional volume requirements are purchased in the short-term spot market.

Coal. Tampa Electric burned approximately 1.6 million tons of coal during 2018 and estimates that its coal consumption will be about 0.8 million tons in 2019. During 2018, Tampa Electric purchased approximately 80% of its coal under contracts with six suppliers, and approximately 20% of its coal in the spot market. Tampa Electric expects to obtain 100% of its coal requirements in 2019 under contracts with two suppliers. Tampa Electric has coal transportation agreements with trucking, rail, barge and ocean vessel companies.

Tampa Electric’s 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 2018, 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.

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 rights-of-way 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 March 2019 through May 2048 and are expected to be renewed under similar terms and conditions.

Franchise fees expense totaled $47 million and $44 million in 2018 and 2017, 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.

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.

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 392,000 customers. The system includes approximately 13,000 miles of gas mains and 7,400 miles of service lines (see PGS’s Franchises and Other Rights section below).

PGS had approximately 630 employees as of December 31, 2018. Approximately 120 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

In 2018, the total throughput for PGS was approximately 2.0 billion therms. Of this total throughput, 6% was gas purchased and resold to customers by PGS, 83% 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 33% of total revenues were from residential customers in 2018.

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. PGS provides transportation service to customers utilizing gas-fired technology in the production of electric power. In addition, PGS provides gas transportation service to recently constructed large LNG facilities located in Jacksonville, Florida. PGS has also seen continuing interest and development in natural gas vehicles. There are 50 compressed natural gas filling stations connected to the PGS distribution system. See the PGS Operating Results section of the MD&A for information on the impact of natural gas vehicles on PGS’s operations.

	Revenues						Therms
(millions)	2018		2017		2016		2018		2017		2016
Residential	$	157	$	138	$	140		87		77		78
Commercial		151		144		143		510		489		488
Industrial		16		15		13		361		330		321
Off-system sales		78		70		73		217		201		245
Power generation		5		5		5		791		750		760
Other revenues		69		54		53		-		-		-
Total	$	476	$	426	$	427		1,966		1,847		1,892

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.

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 rate setting hearings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.

In May 2009, PGS’s base rates and an ROE range of 9.75% to 11.75% were established with base rates set at the middle of the range at 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. On February 7, 2017, the FPSC approved a settlement agreement filed by PGS and OPC 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. No change in customer rates resulted from this agreement.

As part of the 2017 settlement, PGS and OPC agreed that 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 2017 PGS settlement did not contain a provision for tax reform. The FPSC approved that tax reform benefits should be applied to customers beginning on February 6, 2018 for utilities in Florida without an existing tax reform settlement provision. In September 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate in 2018 the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018.

In January 2019, PGS will reduce its base rates by $12 million for the impact of tax reform and reduce depreciation rates by $10 million in accordance with the settlement agreement. PGS is permitted to initiate a general base rate proceeding in 2020 if it forecasts that ROE will fall below its allowed range.

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 current PGA cap rate was approved by the FPSC in November 2018.

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 2029 under the rider.

The FPSC 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.

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).

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. There is also competition from other local distributors of natural gas to establish service territories in unserved areas of Florida.

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.

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 25,400 transportation-only customers as of December 31, 2018 out of approximately 38,900 eligible customers.

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 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.

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 2019 through 2048. PGS expects to negotiate 17 franchise renewals in 2019 under similar terms. Franchise fees expense totaled $10 million and $9 million in 2018 and 2017,

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.

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 8 to the 2018 Annual TEC Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

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 decline, adversely affecting TEC’s results of operations, net income and cash flows. A factor in 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.

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.

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 trends in customer energy-usage patterns. The ability of TEC to increase energy sales and earnings could be negatively impacted if customers further reduce their energy usage 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. PGS typically has a short but significant winter peak period that is dependent on cold weather; Tampa Electric has both summer and winter peak periods that are dependent on weather conditions. Tampa Electric and PGS forecast energy sales on the basis of normal weather, which represents a long-term historical average. If there is unusually mild weather, or if climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

TEC is subject to a number of risks that arise or may arise from weather and climate change, including seasonal variations, the risk of changes in regulations, more frequent and intense weather events, and warming air temperatures, which could have an effect on TEC’s results of operations, financial conditions or cash flows.

The amount of electricity or natural gas used by customers can vary significantly in response to seasonal changes in weather. In the absence of a regulatory recovery mechanism for unanticipated resulting revenue losses, such events could have an effect on TEC’s results of operations, financial conditions or cash flows.

Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, wildfires, flooding and storm surge. Extreme weather events create a risk of physical damage to TEC’s assets. High winds can damage structures, and cause widespread damage to transmission and distribution infrastructure. Increased frequency and severity of weather events increases the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased intensity of flooding could adversely affect the operations of TEC’s facilities.

The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce greater damage to coastal located generation and other facilities. TEC has programs for storm hardening of transmission and distribution facilities to minimize damage, but there can be no assurance that these measures will fully mitigate the risk. This risk to transmission and distribution facilities is generally not insured, and as such the restoration cost is generally recovered through regulatory processes, either in advance through reserves or designated self-insurance funds, or after the fact through the establishment of regulatory assets. Recovery is not assured and is subject to prudency review.

Climate change may also cause changes in historical patterns in global air temperatures. For example, increased air temperatures may bring increased frequency and severity of wildfires, including within TEC’s service territories. Increased air temperatures could also result in decreased efficiencies over time of both generation and transmission facilities.

In the case of a wildfire, if TEC is found to be responsible for such a fire, TEC could suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory cost recovery or other processes and could materially affect TEC’s business and financial results including its reputation with customers, regulators, governments and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value, increased insurance costs and costs arising from damages and losses incurred by third parties.

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.

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. See Note 4 of the TEC 2018 Annual Consolidated Financial Statements for further information regarding TEC’s income taxes.

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.

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.

On August 21, 2018, the EPA released a proposed rule named the Affordable Clean Energy (ACE) rule. The ACE rule, which replaces the Clean Power Plan adopted in 2015, proposes to establish emission guidelines for states to address GHG emissions from existing fossil fuel-fired electric generating units. Tampa Electric expects to have emission units that are subject to the ACE rule, if adopted.

The State of Florida has not begun the rulemaking process to reduce GHG’s and is currently awaiting further legal developments. The outcome of the pending litigation and the EPA rulemaking process and its impact on Tampa Electric’s business is therefore uncertain. Tampa Electric is continuing to evaluate the potential impact of the rule, but currently expects prudently incurred related costs for compliance to be recovered through rates. Increases in rates charged to customers could result in reduced sales.

TEC is exposed to potential risks related to cyberattacks and unauthorized access, which could cause system failures, disrupt operations or adversely affect safety.

TEC increasingly relies on information technology systems and network infrastructure to manage its business and safely operate its assets; including controls for interconnected systems of generation, distribution and transmission as well as financial, billing and other business systems. TEC also relies on third party service providers in order to conduct business. As TEC operates critical infrastructure, it may be at greater risk of cyberattacks by third parties, which could include nation-state controlled parties.

Cyberattacks can reach TEC’s networks with access to critical assets and information via their interfaces with less critical internal networks or via the public internet. Cyberattacks can also occur via personnel with direct access to critical assets or trusted networks. Methods used to attack critical assets could include general purpose or energy-sector-specific malware delivered via network transfer, removable media, viruses, attachments or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect.

Despite security measures in place, TEC’s systems, assets and information could experience security breaches that could cause system failures, disrupt operations or adversely affect safety. Such breaches could compromise customer, employee-related or other information systems and could result in loss of service to customers or the unavailability, release, destruction or misuse of critical, sensitive or confidential information. These breaches could also delay delivery or result in contamination or degradation of hydrocarbon products TEC transports, stores or distributes.

Should such cyberattacks or unauthorized accesses materialize, TEC could suffer costs, losses and damages all, or some of which, may not be recoverable through insurance, legal, regulatory cost recovery or other processes and could materially adversely affect TEC’s business and financial results including its reputation and standing with customers, regulators, governments and financial markets. Resulting costs could include, amongst others, response, recovery and remediation costs, increased protection or insurance costs and costs arising from damages and losses incurred by third parties. If any such security breaches occur, there is no assurance that they can be adequately addressed in a timely manner.

TEC aligns to a common set of cybersecurity standards, program maturity objectives and strategy derived, in part, on the National Institute of Standards and Technology’s Cyber Security Framework. With respect to certain of its assets, TEC is required to comply with rules and standards relating to cybersecurity and information technology including, but not limited to, those mandated by bodies such as the North American Electric Reliability Corporation. Despite these measures, TEC cannot be assured that its operations will not be negatively impacted by a cyberattack.

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 or voters, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

Deregulation or restructuring of the electric industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. There is currently a proposed constitutional initiative in Florida which, if passed, would grant customers of investor-owned utilities the right to choose their electricity provider and to generate and sell electricity and would limit the business of investor-owned utilities to construction, operation, and repair of electrical transmission and distribution systems. This initiative is going through the process for potential inclusion as an amendment to the Florida Constitution to be voted on in November 2020. Such a vote would be subject to Florida Supreme Court approving the placing of the amendment on the ballot and conditional on the initiative attracting a sufficient number of petition signatures. In the event the amendment achieves the 60% required votes, the implementing legislation would be required to be passed by no later than June 1, 2023 and with effect by no later than 2025.

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.

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, terrorist or physical attacks, 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. For example, there have also been physical attacks on critical infrastructure around the world. 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. 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:

Failure to attract and retain an appropriately qualified workforce, or workforce disruptions, 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 workforce disruptions due to work stoppages or strikes, 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.

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, 2018, 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, 2019 measurement date, TECO Energy’s pension plan was fully funded. 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 or costs are not recoverable through rates.

For 2019, 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 2019, 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 or are not recoverable, 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.

In the event TEC’s ratings were downgraded to below investment grade, counterparties to its 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, 2018, TEC 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 is estimated to be approximately $70 million. None of the credit facilities or debt agreements have ratings downgrade covenants that would require immediate repayment or collateralization.

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 has electric generating stations in service, with a December 2018 net winter generating capability of 5,238 MW. Tampa Electric assets include the Big Bend Power Station (842 MW capacity from two coal units, 665 MW from two natural gas 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). Also included in Tampa Electric’s assets at December 31, 2018 are five solar arrays (167 MW). In addition, solar arrays totaling 173 MW were placed in service in early 2019.

Tampa Electric owns 182 substations having an aggregate transformer capacity of 22,900 mega volts amps. The transmission system consists of approximately 1,340 total circuit miles of high voltage transmission lines, including underground and double-circuit lines. The distribution system consists of approximately 6,250 circuit miles of overhead lines and approximately 5,400 circuit miles of underground lines. As of December 31, 2018, there were 778,400 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.

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 20,400 miles of pipe, including approximately 13,000 miles of mains and 7,400 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

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

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 8 of the 2018 Annual TEC Consolidated Financial Statements.

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.

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.

TEC has regulated electric and gas utility operations in Florida. At December 31, 2018, Tampa Electric served approximately 764,000 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 5,238 MW. PGS, Florida’s largest gas distribution utility, served approximately 392,000 residential, commercial, industrial and electric power generating customers at December 31, 2018 in all major metropolitan areas of the state, with a total natural gas throughput of approximately 2.0 billion therms in 2018.

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 Note 10 to the 2018 Annual TEC Consolidated Financial Statements for information regarding related party transactions.

All amounts included in this MD&A are pre-tax, except net income and income taxes.

In 2018, TEC’s net income was $341 million, compared with $316 million in 2017. The most significant factors impacting net income were higher revenues in 2018 due to favorable weather, customer growth and higher base rates, and higher AFUDC earnings due to the construction of solar projects. These were partially offset by higher O&M and depreciation and amortization expenses in 2018. See below for further detail.

TEC’s earnings are most directly impacted by the rate of return on equity and the capital structures approved by the FPSC, the prudent management of operating costs, the approved recovery of regulatory deferrals, weather and its impact on energy sales, and the timing and amount of capital expenditures.

Tampa Electric and PGS anticipate earning within their allowed ROE ranges in 2019 and expect rate base and earnings to be higher than in prior years. Tampa Electric expects customer growth rates in 2019 to be consistent with 2018, reflecting economic growth in Florida. Assuming normal weather in 2019, Tampa Electric sales volumes are expected to be consistent with 2018 sales volumes (see Customer and Energy Sales Growth Outlook for further details). PGS also expects customer growth rates in 2019 to be consistent with 2018, reflecting economic growth and the optimization of existing opportunities as the utility increases its market penetration in Florida. Assuming normal weather in 2019, PGS sales volumes are expected to increase at a level lower than customer growth as 2018 energy sales benefitted from favorable weather.

In September 2018, Tampa Electric announced its intention to invest approximately $235 million during 2018 through 2022 for an AMI (Advanced Meter Infrastructure) project, including the installation of approximately 800,000 smart meters.

On May 24, 2018, Tampa Electric announced its intention to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station. See Business- Tampa Electric- Generation Sources for further details.

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. On May 8, 2018, the FPSC approved Tampa Electric’s first SoBRA. This SoBRA represents 145 MW and $24 million annually in estimated revenue requirements. Tampa Electric began collecting these revenues in September 2018. On October 29, 2018, the FPSC approved Tampa Electric’s second SoBRA. This SoBRA, effective January 1, 2019, represents 260 MW and $46 million annually in estimated revenue requirements. See Solar Initiatives for further details.

In September 2017, Tampa Electric was impacted by Hurricane Irma and incurred restoration costs of approximately $102 million. The amount charged to the storm reserve exceeded the balance in the reserve by $47 million at December 31, 2017. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric authorizing the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. Total O&M expense due to the allowed netting of the storm cost recovery with tax reform benefits was approximately $103 million in 2018. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved a reduction in base rates of $103 million annually beginning in 2019 as a result of lower tax expense.

On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility to amortize $11 million of its MGP environmental regulatory asset and net it against its estimated 2018 tax reform benefits. Beginning in January 2019, PGS

will lower base rates by $12 million to reflect the impact of tax reform and reduce depreciation rates by $10 million in accordance with the settlement agreement.

In 2019, TEC expects to invest approximately $1.2 billion, including AFUDC, in capital projects compared to $1.1 billion in 2018. Capital projects support normal system reliability and growth at the utilities. Tampa Electric investments include the modernization of the Big Bend Power Station, solar projects and AMI activities. AFUDC will be earned during the construction periods. PGS will make investments to expand its system and support customer growth, including expected investments related to compressed natural gas fueling stations and liquefied natural gas facilities, and continued replacement of obsolete plastic, cast iron and bare steel pipe.

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).

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 (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 2018 Annual TEC Consolidated Financial Statements).

(millions)		2018			2017			2016
Revenues
	Tampa Electric	$	2,066		$	2,054		$	1,965
	PGS		488			438			439
	Eliminations		(30	)		(22	)		(8	)
	TEC	$	2,524		$	2,470		$	2,396

Net income
	Tampa Electric	$	294		$	273		$	251
	PGS		47			43			35
	TEC	$	341		$	316		$	286

Net income in 2018 was $294 million, compared with $273 million in 2017, driven by higher revenues from weather and 1.6% higher average number of customers. Results reflected higher base revenues and higher AFUDC earnings, partially offset by lower clause-related revenues and higher depreciation expense. Base revenues are energy sales excluding revenues from clauses, gross receipts taxes and franchise fees. Clauses, gross receipts taxes and franchise fees do not have a material effect on net income as these revenues substantially represent a dollar-for-dollar recovery of clauses and other pass-through costs. Full-year net income in 2018 included $10 million of AFUDC-equity, which increased, compared with $2 million of AFUDC-equity in 2017, due to the solar expansion and modernization of the Big Bend Power Station. See the Operating Revenues and Operating Expenses sections below for additional information. O&M expense increased due to storm cost, which was offset by a decrease in taxes due to tax reform. This was approved by the FPSC in a settlement agreement in March 2018. See Note 3 to the 2018 Annual TEC Consolidated Financial Statements for additional information regarding the settlement agreement.

Net income in 2017 was $273 million, compared with $251 million in 2016, driven by higher revenues from 1.9% higher average number of customers. Results reflected 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 sections for additional information.

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

(millions, except customers and total degree days)	2018		% Change			2017		% Change			2016
Revenues	$	2,066		1		$	2,054		5		$	1,965
O&M expense		504		26			399		(6	)		424
Depreciation and amortization expense		312		4			300		12			268
Taxes, other than income		168		4			162		3			157
Non-fuel operating expenses		984		14			861		1			849
Fuel expense		578		(5	)		608		7			568
Purchased power expense		59		28			46		(56	)		104
Total fuel & purchased power expense		637		(3	)		654		(3	)		672
Total operating expenses		1,621		7			1,515		(0	)		1,521
Operating income	$	445		(17	)	$	539		21		$	444
AFUDC-equity	$	10		400		$	2		(92	)	$	24
Provision for income taxes	$	65		(62	)	$	171		32		$	130
Net income	$	294		8		$	273		9		$	251
Megawatt-Hour Sales (thousands)
Residential		9,418		4			9,029		(2	)		9,188
Commercial		6,266		(2	)		6,362		1			6,310
Industrial		2,014		(0	)		2,024		5			1,928
Other		1,933		9			1,771		(2	)		1,808
Total retail		19,631		2			19,186		(0	)		19,234
Off system sales		286		20			239		16			206
Total energy sold		19,917		3			19,425		(0	)		19,440
Retail customers—(thousands)
At December 31		764		2			748		2			736
Retail net energy for load		20,663		2			20,297		1			20,165
Total degree days		4,711		4			4,520		1			4,462

In 2018, revenues were $12 million higher than in 2017 primarily due to higher base revenues, which were partially offset by lower clause related revenues. Base revenues were $29 million higher than 2017, primarily driven by weather, customer growth and higher base rates as a result of the tranche 1 solar expansion, which went in service in September 2018 and the Polk Power Station expansion, which went in service in January 2017. In 2018, total degree days (a measure of heating and cooling demand) in Tampa Electric's service area were 11% above normal and 4% above the 2017 period. In 2018, total net energy for load, which is a calendar measurement of energy generation output rather than a billing cycle measurement, was 1.8% higher than in 2017.

In 2017, revenues were $89 million higher than in 2016, primarily due to higher base revenues, which were partially offset by lower clause related revenues. Base revenues were $118 million higher than 2016 driven by approximately $113 million higher base rates as a result of the 2013 rate case settlement related to the expansion of the Polk Power Station in January 2017. 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 in 2017 compared to 2016, 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.

The Florida labor market continues to outperform the U.S. labor market. The local Tampa area unemployment rate decreased to 3.3% in 2018 compared with 3.9% in 2017 and 4.5% in 2016, which is below the Florida rate of 3.7% and the U.S. rate of 3.9% for 2018. The unemployment rate is expected to drop further in 2019. From 2018 to 2021, the economies of Florida’s and Tampa Electric’s service area, as measured by Real Gross State Product, are forecasted to expand at an average annual rate of 3.0%, outpacing the forecasted U.S. rate of 2.3%.

Population growth is forecasted to continue to be a major driver of customer growth for many years. Tampa Electric expects customer growth to be 1.8% annually over the next few years, and to grow at an average annual rate of 1.6% over the longer-term, assuming continued economic growth and business expansion.

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. It is expected to continue to decline annually at an average annual rate of 0.5%.

In 2019, retail energy sales are expected to be consistent with 2018 levels as 2018 energy sales benefitted from favorable weather while 2019 projections are based on normal weather and projected decreased sales in the phosphate sector. Excluding the phosphate sector, 2019 energy sales are expected to grow at a rate close to 0.4%. Over the longer-term, energy sales growth are expected to range between 1.2% and 1.4%. 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 2019 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.

Total operating expense was 7% higher in 2018 compared to 2017, driven primarily by O&M expenses, which includes the FPSC-approved settlement agreement allowing the netting of the recovery of storm costs with tax reform benefits of $103 million (see Note 3 to the 2018 Annual TEC Consolidated Financial Statements), and higher purchased power expense, partially offset by lower fuel expense (see Fuel Prices and Fuel Cost Recovery below). O&M expenses (excluding all FPSC-approved cost-recovery clauses and the impact of the FPSC-approved settlement agreement) increased $4 million in 2018, reflecting higher employee benefit costs, partially offset by cost management activities.

Total operating expense was slightly 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.

In 2018 and 2017, depreciation and amortization expense increased $12 million and $32 million, respectively, reflecting additions to facilities to serve customers, including expansion of the Polk Power Station in January 2017. In 2019, 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 2019 is expected to be higher than in 2018 reflecting higher costs to safely and reliably serve customers.

In November 2018, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2019. The rates include the expected cost for natural gas and coal in 2019, and a net prior period over-recovery true-up of fuel, purchased power and capacity clause expense. These rates are typically set annually, based on information provided in August of the year prior to the year the rates take effect.

In January 2019, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, to be effective beginning in April 2019, due to higher than originally projected fuel and purchased power costs in 2018 and 2019, partially offset by lower capacity costs during 2019. The FPSC is expected to decide the request in March 2019.

Total fuel expense decreased in 2018 primarily due to an increase in fuel clause current year under-recoveries, which will be collected in future periods. Increased natural gas-fired generation and greater volumes of cost-effective energy available for purchase helped mitigate the impact of higher fuel prices by reducing the need to run more costly generation. Delivered natural gas prices increased 1.5% in 2018 as abundant supplies of natural gas from on-shore domestic natural gas produced were offset by increased demand from LNG production and gas-fired electric generation. Delivered coal costs increased 2.3% in 2018. The average coal and natural gas costs were $3.37/MMBTU and $4.07/MMBTU, respectively, in 2018, compared with $3.30/MMBTU and $4.01/MMBTU, respectively, in 2017.

Despite the request for a fuel rate adjustment, total 2019 fuel and purchased power costs are still expected to be less than incurred during 2018, which will be achieved through the increased use of gas-fired generation and cost-effective energy purchases.

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. TEC began receiving $24 million annually for the first tranche in September 2018 and $46 million annually for the second tranche in January 2019. See Note 3 to the 2018 Annual TEC Consolidated Financial Statements for additional information. In addition, Tampa Electric completed 22.5 MW of solar photovoltaic energy projects over the past several years. Tampa Electric owns the solar photovoltaic arrays, and the electricity they produce goes to the grid to benefit all Tampa Electric customers. Additionally, Tampa Electric has installed 2,135 KW of solar panels to generate electricity at eight community sites.

In 2018, PGS reported net income of $47 million, compared with $43 million in 2017. Revenues were $50 million higher than in 2017 primarily due to higher clause-related revenues, higher off system sales and higher base revenues. Base revenues were $11 million higher than 2017, reflecting 3.5% customer growth and higher therm sales primarily due to cooler first quarter weather compared to 2017. Excluding all FPSC-approved cost-recovery clauses, O&M expense increased $9 million in 2018 primarily due to higher employee benefit costs and compliance costs. Depreciation and amortization expense increased $10 million due to the tax reform settlement agreement authorizing PGS to accelerate amortization of its regulatory asset associated with the MGP environmental liability (see Note 3 to the 2018 Annual TEC Consolidated Financial Statements) and normal asset growth. Return on investment in cast iron and bare steel replacement rider was $1 million higher in 2018.

In 2017, PGS reported net income of $43 million, compared with $35 million in 2016. Revenues were $1 million lower than in 2016 primarily due to slightly lower clause-related revenues. Base revenue was $3 million higher than in 2016 reflecting 2.7% customer growth offset by milder 2017 weather. 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 2018 and 2017, total throughput for PGS was approximately 2 billion therms and 1.8 billion therms, respectively. See Business - Peoples Gas System- Gas Operations for information regarding therms by type of customer.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida. PGS provides transportation service to customers utilizing gas-fired technology in the production of electric power. In addition, PGS provides gas transportation service to recently constructed large LNG facilities located in Jacksonville, Florida. 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 33 million therms sold in 2018 compared to 31 million therms in 2017 and 26 million therms in 2016. Currently, there are 50 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 fuel cost than Tampa Electric.

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

(millions, except customers)	2018		% Change			2017		% Change			2016
Revenues	$	488		11		$	438		(0	)	$	439
Cost of gas sold		180		18			153		(4	)		159
Operating expenses		231		15			201		(5	)		211
Operating income	$	77		(8	)	$	84		22		$	69
Net income	$	47		9		$	43		23		$	35
Therms sold – by customer segment
Residential		87		13			77		(1	)		78
Commercial		510		4			489		0			488
Industrial		361		9			330		3			321
Off-system sales		217		8			201		(18	)		245
Power generation		791		5			750		(1	)		760
Total		1,966		6			1,847		(2	)		1,892
Therms sold – by sales type
System supply		328		8			303		(13	)		347
Transportation		1,638		6			1,544		(0	)		1,545
Total		1,966		6			1,847		(2	)		1,892
Customer (thousands) – at December 31⁽¹⁾		392		4			378		3			368

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

PGS expects customer growth rates in 2019 to be in line with 2018, 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 in 2019, PGS sales volumes are expected to increase at a level slightly lower than customer growth as 2018 energy sales benefitted from favorable winter weather. In January 2019, a base rate reduction will go into effect to return US tax reform benefits to customers in accordance with the FPSC-approved tax reform settlement. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense in 2019 is expected to be higher than in 2018, driven by an increase in technology related costs, initiatives to enhance customer experience, and additional expense necessary to safely and reliably operate and maintain a growing distribution system. Depreciation and amortization expense is expected to decrease in 2019 due to lower MGP environmental amortization and lower depreciation rates in accordance with the tax reform settlement.

Complementing the strong residential construction market is PGS’s focus 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 2019 and expects earnings and rate base growth as a result of continued customer growth and expansion of the PGS system.

Other income, net was $18 million, $10 million and $31 million in 2018, 2017 and 2016, respectively, and included AFUDC-equity and other items and services. AFUDC-equity at Tampa Electric was $10 million, $2 million and $24 million in 2018, 2017 and 2016, respectively. The 2018 increase in AFUDC-equity is due to Tampa Electric’s construction of solar generation, AMI and the Big Bend modernization as discussed in the Outlook section above. The 2017 decrease in AFUDC-equity is due to Tampa Electric’s Polk Power Station expansion being placed in service in January 2017.

In 2018, interest expense, excluding AFUDC-debt, was $123 million compared to $120 million in 2017 and $117 million in 2016. In 2018, interest expense increased, reflecting higher short-term interest rates and long-term borrowings. In 2017, interest expense increased, reflecting higher short-term interest rates and balances.

Interest expense is expected to increase in 2019, reflecting higher interest rates and balances.

The provision for income taxes decreased in 2018 primarily due to tax reform impacts. Income tax expense as a percentage of income before taxes was 19.2% in 2018, 38.4% in 2017 and 34.8% in 2016. TEC expects the 2019 annual effective tax rate to be consistent with 2018.

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 $77 million, $13 million and $(3) million in 2018, 2017 and 2016, respectively. The cash payments (refunds) mainly differ year over year due to pre-tax income and timing of bonus depreciation deductions. The 2017 tax payments are lower as compared to 2018 payments due to the 2017 Polk Power Station expansion bonus depreciation deduction.

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 Note 4 to the 2018 Annual TEC Consolidated Financial Statements.

Cash flows from operating activities in 2018 were $802 million, an increase of $190 million compared to 2017. The increase is primarily due to lower clause under-recoveries in 2018, lower pension contributions and lower storm costs, partially offset by higher inventory purchases due to a change in service agreements and the replenishment of materials and supplies.

Cash flows from investing activities in 2018 resulted in a net use of cash of $1.1 billion, which primarily reflects capital expenditures. TEC expects capital spending in 2019 to be approximately $1.2 billion. See the Capital Investments section for additional information.

Cash flows from financing activities in 2018 resulted in net cash inflows of $308 million. TEC received $345 million of equity contributions from Parent and $714 million from long-term debt issuances (see Note 7 to the 2018 Annual TEC Consolidated Financial Statements for details). These increases in cash flows were partially offset by the repayment of long-term debt of $304 million, the net repayment of short-term debt of $84 million and dividend payments to Parent of $362 million.

TEC’s tariff-based gross margins are the principal source of cash from operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides TEC with a reasonably predictable source of cash. In addition to using cash generated from operating activities, TEC uses available cash and credit facility borrowings to support normal operations and capital requirements. TEC may reduce short-term borrowings with cash from operations, long-term borrowings, or capital contributions from TECO Energy. TEC expects to make significant capital expenditures in 2019 as it invests in new solar projects, the modernization of the Big Bend power plant, smart meters, gas distribution system expansion and other

improvements. See Capital Investments section below for further detail on TEC’s projected capital expenditures. TEC intends to fund those capital expenditures with available cash on hand, cash generated from operating activities, cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with the regulatory arrangements. Future financial market conditions could increase TEC’s interest costs which could reduce earnings and cash flows.

As noted earlier, cash from operating activities and short-term borrowings are used to fund capital expenditures, which may result in periodic working capital deficits. The working capital deficit as of December 31, 2018 was primarily caused by short-term borrowings, liabilities due to customer deposits and periodic fluctuations in assets and liabilities related to FPSC clauses and riders. At December 31, 2018, TEC’s unused capacity under its credit facilities was $253 million.

TEC has credit facilities that provide $475 million of credit, including $150 million maturing in 2021 and $325 million available to 2022. See Note 6 to the 2018 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.

TEC expects cash from operations in 2019 to be similar to 2018, with lower base rates beginning on January 1, 2019 due to tax reform offset by customer growth and increased revenues due to solar investments at Tampa Electric (see Note 3 to the 2018 Annual TEC Consolidated Financial Statements). TEC plans to use cash in 2019 to fund capital spending and to pay dividends to its shareholder, TECO Energy. Dividends are declared and paid at the discretion of TEC’s Board of Directors.

TEC’s credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). TEC estimates that it could fully utilize the total available capacity under its facilities in 2019 and remain within the covenant restrictions.

At December 31, 2018 and 2017, the following credit facilities and related borrowings existed.

	December 31, 2018						December 31, 2017
					Letters of						Letters of
	Credit		Borrowings		Credit		Credit		Borrowings		Credit
(millions)	Facilities		Outstanding⁽¹⁾		Outstanding		Facilities		Outstanding⁽¹⁾		Outstanding
5-year facility ⁽²⁾	$	325	$	131	$	1	$	325	$	5	$	1
3-year accounts receivable facility ⁽³⁾		150		90		0		150		0		0
1-year term facility⁽⁴⁾		0		0		0		300		300		0
Total	$	475	$	221	$	1	$	775	$	305	$	1

These credit facilities require commitment fees ranging from 12.5 to 35.0 basis points. The weighted average interest rate on outstanding amounts payable under the credit facilities at December 31, 2018 and 2017 was 3.14% and 2.07%, respectively. For a complete description of the credit facilities see Note 6 to the 2018 Annual TEC Consolidated Financial Statements.

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, 2018, 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, 2018. Reference is made to the specific agreements and instruments for more details.

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.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. TEC’s access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of its securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 13 to the 2018 Annual TEC Consolidated Financial Statements).

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.

	Payments Due by Period
(millions)	Total		2019		2020		2021		2022		2023		After 2023
Long-term debt ⁽¹⁾	$	2,604	$	0	$	0	$	279	$	250	$	0	$	2,075
Interest payment obligations⁽²⁾		2,490		124		121		113		106		99		1,927
Transportation⁽³⁾		1,764		194		175		141		133		108		1,013
Pension plan⁽⁴⁾		202		0		0		15		61		38		88
Capital projects⁽⁵⁾		436		298		89		33		8		2		6
Fuel and gas supply⁽³⁾		370		257		106		3		3		1		0
Long-term service agreements⁽⁶⁾		115		7		6		6		7		11		78
Operating leases		44		2		2		2		2		2		34
Demand side management⁽³⁾		6		5		1		0		0		0		0
Total contractual obligations	$	8,031	$	887	$	500	$	592	$	570	$	261	$	5,221

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, 2018. See Note 8 to the 2018 Annual TEC Consolidated Financial Statements.

Tampa Electric’s 2018 capital expenditures included solar generation projects (see Note 3 to the 2018 Annual TEC Consolidated Financial Statements for information related to the 600 MW solar project recoverable under the SOBRAs), the Big Bend modernization (see Business- Tampa Electric- Generation Sources for further information), storm hardening for the transmission and distribution systems, and the maintenance and refurbishment of existing generating facilities. In 2019, Tampa Electric expects capital expenditures related to solar generation projects, the Big Bend modernization, new technology for distribution system modernization and automated metering equipment.

Capital expenditures in 2018 for PGS included maintenance of the existing system, expansion of the system and replacement of cast iron, bare steel and obsolete plastic pipe. In addition, PGS expects to invest in 2019 for projects associated with customer growth, system expansion to serve large commercial and industrial customers, including continued interest in the conversion of vehicle fleets to CNG, renewable natural gas facilities, potentially LNG facilities, and information technology investments. The remainder of PGS’s capital expenditure forecast for 2019 includes amounts related to ongoing renewal, replacement and system safety, including the replacement 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 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).

Tampa Electric and PGS maintained capital structures consistent with their regulatory arrangements. At December 31, 2018, TEC’s year-end capital structure was 46% debt and 54% common equity. At December 31, 2017, TEC’s year-end capital structure was 45% debt and 55% common equity.

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities and disclosures. 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. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the 2018 Annual TEC Consolidated Financial Statements for a description of TEC’s significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, TEC estimates the current tax exposure and assesses 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 TEC determines 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, 2018, TEC had a net deferred income tax liability of $799 million, attributable primarily to property-related items.

See further discussion of uncertainty in income taxes, impacts of tax reform and other tax items in Note 4 to the 2018 Annual TEC Consolidated Financial Statements.

TEC is a participant in the retirement plans of TECO Energy. TECO Energy sponsors a defined benefit pension plan (pension plan), a fully-funded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management and an unfunded non-qualified, non-contributory Restoration Plan that allows certain members of senior management to receive contributions as if no IRS limits were in place. 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 6.85% in 2018 and 7.00% during 2017 and 2016. Given an expected change in the asset allocation, management expects to increase the expected return on assets to 7.15% for 2019. Actual earned losses in 2018 were approximately 8%.

The discount rate assumption used to measure the 2018 and 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 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. For the December 31, 2018 measurement, TECO Energy used a discount rate of 3.63% for pension benefits under its qualified plan and 3.70% 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 2018 and is anticipated to have in 2019 the following impact on TEC’s after-tax pension cost:

TECO Energy uses a mortality projection scale that utilizes the same data and methodology used in the Society of Actuaries (SOA)-developed scale but modifies it to use a 0.75% ultimate annual improvement rate and a 10-year grade-down period. In 2016, 2017 and 2018, the SOA updated the projection scale. For mortality improvements reflected in the 2016, 2017 and 2018 year-end measurements, TECO Energy used an updated projection scale based on the SOA’s 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.

The Health Care Reform Acts contain certain 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. On January 22, 2018, Congress passed a two-year delay of the excise tax, bringing the effective date from 2020 to 2022. 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.

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 2018 Annual TEC Consolidated Financial Statements.

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, Tampa Electric and PGS 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.

TEC regularly assesses 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 will 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 2018 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 Note 3 to the 2018 Annual TEC Consolidated Financial Statements).

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2018, are described as follows:

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the US Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. TEC early adopted the standard in June 2018 and elected to not reclassify tax effects resulting from the US Tax Cuts and Jobs Act stranded in accumulated other comprehensive income to retained earnings as amounts were not material. TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released.

On January 1, 2018, TEC adopted ASU 2014-09, Revenue from Contracts with Customers and all the related amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as ASC Topic 606. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

TEC adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to TEC’s opening retained earnings as of the adoption date. The impact of the adoption of the new standard was immaterial to TEC’s net income and is expected to be immaterial on an ongoing basis.

presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

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 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. TEC adopted ASU 2017-01 effective January 1, 2018. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

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.

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 previous 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. TEC will not early adopt the standard.

In January 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. TEC will make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. TEC will make this election. Additionally, TEC will elect the options that allow it to not reassess whether any expired or existing contracts contain leases, carry forward existing lease classification, use hindsight to determine the lease term for existing leases and not separate lease components from non-lease components for all lessee and lessor arrangements.

Over the past several years, TEC developed and executed a project plan which included holding training sessions with key stakeholders throughout the organization, gathering detailed information on existing lease arrangements, evaluating implementation alternatives and calculating the lease asset and liability balances associated with individual contractual arrangements. TEC has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. Updates to systems are not required as a result of implementation of this standard. The adoption of this standard will affect TEC’s financial position by increasing assets and liabilities related to operating leases by approximately $20 million, with no impact to TEC’s Consolidated Statements of Income. There will be no significant changes to TEC’s accounting for lessor arrangements as a result of the adoption of the standard. TEC is in the process of assessing the disclosure requirements and continues to monitor FASB amendments to ASC Topic 842.

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.

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. The adoption of this standard will have no impact on TEC’s consolidated financial statements.

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. TEC is currently evaluating the transition methods and the impact of the adoption of this standard on the consolidated financial statements.

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.

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 diversified 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.

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.

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 35%, bringing emissions to below 1990 levels. Tampa Electric CO₂ emissions continue to remain below 1990 levels. In addition to the emission decreases in 2005 as the result of the repowering two Gannon Station coal units to natural gas and the shut-down of the remaining Gannon Station coal-fired units, Tampa Electric has optimized its existing coal units to operate on natural gas. During this same time frame, the number of retail customers and retail energy sales have risen by approximately 36% and 21%, respectively. Tampa Electric is also substantially reducing CO₂ emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine, and retiring Big Bend Unit 2. By 2021, Tampa Electric expects to have 6 million solar panels in 10 new photovoltaic solar projects, for a total of 600MW. By 2023, the Big Bend Unit 1 modernization project, capable of producing 1,090 megawatts of power, will lead to system-wide emissions that are nearly half of 1998-level emissions.

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 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. On March 28, 2017 President Trump issued an Executive Order calling for the review of the CPP and the New Source Performance Standards and to suspend, revise or rescind the rule if appropriate.

On August 21, 2018, EPA released a proposed rule to replace the CPP, named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing fossil fuel-fired electric generating units (EGUs). It proposes emission guidelines to replace the CPP and inform the development of state plans to reduce GHG emissions from certain EGUs. In the guidelines, EPA is proposing to determine that heat rate improvement measures are the best system of emission reduction for existing coal-fired EGUs. This action also proposes implementing regulations for emission guidelines issued under Section 111(d) of the Clean Air Act and revisions to the New Source Review (NSR) program to prevent NSR from being a barrier to implementing efficiency projects at EGUs. Tampa Electric is expected to have emission units that are subject to this rule and provided comments to support the rulemaking process. EPA intends to issue a final rule in 2019.

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 ACE rule 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.

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 November 2, 2018, the EPA published a notice of availability of the draft Integrated Review Plan (IRP) for the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone and sought comments regarding the proposed plan. Under the Clean Air Act, EPA is required to review the NAAQS every five years and, if appropriate, revise them. The draft IRP contains a proposed timetable for the entire ozone NAAQS review, EPA’s general approach for conducting the review, and the key scientific and policy issues that will guide EPA’s review proposed to be completed in 2020. The review of the standard could result in revisions to the standard affecting compliance in Tampa Electric’s service territory. The impact of this potential new standard on the operations of Tampa Electric will depend on the outcome of litigation or other developments.

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) that require compliance with the rule. Compliance includes the completion of the biological, technical, and financial study elements required by the rule. These study elements have been completed and submitted for Bayside and will ultimately be used by FDEP to determine the necessity of cooling water system retrofits. Big Bend is negotiating an alternative schedule (as allowed by the rule) and will be completing a portion of the compliance requirements with the Big Bend Modernization Project with the remainder to be completed at a later date. 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. The 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. In its Final 2016 Effluent Guidelines Program Plan released in 2018, the EPA said it will potentially revise the effluent limitations for bottom ash transport water and FGD wastewater, with a proposed rule expected in March 2019 and a final rule by December 2019. Gasification limits are not under consideration, and Polk Power Station will be expected to achieve compliance in accordance with the original dates.

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. In June 2018, EPA and the Corps issued a draft prepublication notice to clarify, supplement and seek additional comment to the July 27, 2017 proposal to repeal the 2015 WOTUS Rule and restore the regulatory text that existed prior to the 2015 rule. On August 16, 2018, a federal court in South Carolina restored the 2015 rule, putting it back into effect in 26 states but not in the other 24 states with federal court injunctions against it. Both Florida and New Mexico remain under the federal court injunctions.

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, 2018, TEC has estimated its ultimate financial liability to be $28 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites 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 2018 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.

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 ECRC. On December 12, 2017, the FPSC approved an additional petition for recovery of expenses associated with the closure of Tampa Electric’s Big Bend Economizer Ash and Pyrite Ponds which began in late November 2018. Closure of Tampa Electric’s West Slag Dewatering Pond and improvements to Tampa Electric’s North Gypsum Stackout Area are scheduled to commence and be completed in 2019. In June 2018, EPA finalized Phase I revisions to the rule which provide clarifications and additional flexibility to certain rule requirements. Phase II revisions are scheduled for promulgation in 2019. TEC submitted a Petition for Environmental Cost Recovery in December 2018 for recovery of expenses related to its ongoing South Gypsum Storage Area Closure Project. This petition is currently under review by the FPSC, which has scheduled a hearing for this project in April 2019. See Note 12 to the 2018 Annual TEC Consolidated Financial Statements for information regarding the estimated impact on Tampa Electric’s AROs.

In November 2014, the FPSC established new Demand Side Management (DSM) goals for the 10-year period from 2015 to 2024 for all Florida investor-owned electric utilities. In 2018, Tampa Electric continued with the 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 2018 and continued facilitating the DSM goals development for the next upcoming period (2020-2029). These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. 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.

In 2018, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled it to meet its required DSM goals, reduce weather-sensitive peak demand and conserve energy. During the year, Tampa Electric added one new DSM program, the LED Street and Outdoor Lighting Conversion program. This DSM program will convert all of Tampa Electric’s remaining metal halide and high-pressure sodium lamps to LED over a projected five-year period. Tampa Electric continued the R&D of several potential future programs which include battery storage and commercial low-income weatherization. Since their inception, Tampa Electric’s conservation programs have contributed to reducing the summer peak demand by 709 MW and the winter peak demand by 1,211 MW.

In 2018, PGS developed and filed for the approval of DSM goals which would cover the 2019-2028 period and two new DSM programs, an online energy audit program for residential customers and a walkthrough energy audit for commercial customers. Approval by the FPSC is expected to occur in 2019.

See the Business section (Tampa Electric – Electric Operations and Peoples Gas System – Gas Operations sections) and Note 3 to the 2018 Annual TEC Consolidated Financial Statements for a description of the utilities’ base rates, cost-recovery clauses and competition.

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 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.

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, TEC enters into futures, forwards, swaps and option contracts to limit the exposure to items such as:

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The 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 2018 Annual TEC Consolidated Financial Statements). As of December 31, 2018, TEC had no hedges of natural gas purchases in place.

TEC has a rigorous process for the establishment of new trading counterparties and evaluation of current counterparties. This process includes an evaluation of each counterparty’s credit ratings, as applicable, and/or its 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 manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all counterparties, and deposits or collateral are requested on any high-risk accounts.

Certain of TEC’s derivative instruments, including NPNS agreements as disclosed in Note 13 to the 2018 Annual TEC Consolidated Financial Statements, 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 or not be rated, 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 is exposed to changes in interest rates primarily as a result of 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, 2018, TEC had no hedges of interest rates in place. As of December 31, 2018 and 2017, a hypothetical 10% increase in TEC’s weighted-average interest rate on its variable rate debt during the subsequent year would not have resulted in a material impact on pre-tax earnings. This is driven by the low amounts of variable rate debt at TEC. A hypothetical 10% increase in interest rates would have decreased the fair market value of our long-term debt by 5.2% at December 31, 2018 and 4.0% at December 31, 2017. See the Financing Activity section and Notes 6 and 7 to the 2018 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 TEC’s financial structure and could be affected by changes in TEC’s credit ratings, changes in general economic conditions or other external factors (see the Risk Factors section).

TEC faces varying degrees of exposure to commodity risks including natural gas, coal, fuel oil, petcoke 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.

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 82% in 2018 from 69% in 2017 (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 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, 2018 and 2017, 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).

We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Tampa Electric Company (the Company) as of December 31, 2018, the related consolidated statements of income and comprehensive income, retained earnings and cash flows for the year ended December 31, 2018, and the related notes and schedule of valuation and qualifying accounts and reserves for the year ended December 31, 2018 (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 at December 31, 2018, and the results of its operations and its cash flows for the year ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. 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 audit 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 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 internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the 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 financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

We have audited the consolidated balance sheet and statement of capitalization of Tampa Electric Company and its subsidiaries (the “Company”) as of December 31, 2017, and the related consolidated statements of income and comprehensive income, of cash flows and of retained earnings for each of the two 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 two 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 the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America.

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.

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.

Assets	December 31,			December 31,
(millions)	2018			2017
Property, plant and equipment
Utility plant
Electric	$	9,645		$	8,794
Gas		1,793			1,633
Utility plant, at original costs		11,438			10,427
Accumulated depreciation		(3,214	)		(2,994	)
Utility plant, net		8,224			7,433
Other property		12			11
Total property, plant and equipment, net		8,236			7,444

Current assets
Cash and cash equivalents		15			13
Receivables, less allowance for uncollectibles of $2 and $1 at December 31, 2018 and 2017, respectively		258			257
Due from affiliates		4			5
Inventories, at average cost
Fuel		46			60
Materials and supplies		100			90
Regulatory assets		88			77
Prepayments and other current assets		6			13
Total current assets		517			515

Deferred debits
Regulatory assets		370			356
Other		32			49
Total deferred debits		402			405
Total assets	$	9,155		$	8,364

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

Liabilities and Capital	December 31,			December 31,
(millions)	2018			2017
Capitalization
Common stock	$	2,990		$	2,645
Accumulated other comprehensive loss		(1	)		(2	)
Retained earnings		314			335
Total capital		3,303			2,978
Long-term debt, less amount due within one year		2,575			1,860
Total capital		5,878			4,838

Current liabilities
Long-term debt due within one year		0			304
Notes payable		221			305
Accounts payable		251			233
Due to affiliates		24			21
Customer deposits		132			131
Regulatory liabilities		44			58
Accrued interest		16			14
Accrued taxes		13			12
Other		84			44
Total current liabilities		785			1,122

Long-term liabilities
Deferred income taxes		799			825
Regulatory liabilities		1,266			1,227
Deferred credits and other liabilities		427			352
Total deferred credits		2,492			2,404

Commitments and Contingencies (see Note 8)

Total liabilities and capital	$	9,155		$	8,364

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

(millions)
For the years ended December 31,	2018			2017			2016
Revenues
Electric	$	2,063		$	2,052		$	1,964
Gas		461			418			432
Total revenues		2,524			2,470			2,396
Expenses
Fuel		551			588			561
Purchased power		59			46			104
Cost of natural gas sold		180			153			159
Operations & maintenance		632			513			538
Depreciation and amortization		372			350			328
Taxes, other than income		208			198			193
Total expenses		2,002			1,848			1,883
Income from operations		522			622			513
Other income
Allowance for other funds used during construction		10			2			24
Other income, net		8			8			7
Total other income		18			10			31
Interest charges
Interest expense		123			120			117
Allowance for borrowed funds used during construction		(5	)		(1	)		(11	)
Total interest charges		118			119			106
Income before provision for income taxes		422			513			438
Provision for income taxes		81			197			152
Net income		341			316			286
Other comprehensive income, net of tax
Gain on cash flow hedges		1			1			1
Total other comprehensive income, net of tax		1			1			1
Comprehensive income	$	342		$	317		$	287

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

(millions)
For the years ended December 31,	2018			2017			2016
Cash flows from operating activities
Net income	$	341		$	316		$	286
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		372			350			328
Deferred income taxes and investment tax credits		(1	)		192			87
Allowance for equity funds used during construction		(10	)		(2	)		(24	)
Deferred recovery clauses		(55	)		(83	)		54
Receivables, less allowance for uncollectibles		(2	)		(43	)		18
Inventories		4			13			16
Taxes accrued		6			(9	)		68
Accounts payable		11			(16	)		63
Regulatory assets and liabilities		98			(100	)		(11	)
Other⁽²⁾		38			(6	)		(54	)
Cash flows from operating activities		802			612			831
Cash flows used in investing activities
Capital expenditures⁽¹⁾		(1,109	)		(640	)		(727	)
Net proceeds from sale of assets		1			0			9
Cash flows used in investing activities		(1,108	)		(640	)		(718	)
Cash flows from or used in financing activities
Equity contributions from TECO Energy		345			190			150
Proceeds from long-term debt issuance		714			0			0
Repayment of long-term debt		(304	)		0			(83	)
Net change in short-term debt (maturities of 90 days or less)		216			(165	)		109
Proceeds from other short-term debt (maturities over 90 days)		0			300			0
Repayment of other short-term debt (maturities over 90 days)		(300	)		0			0
Dividends to TECO Energy		(362	)		(292	)		(289	)
Other financing activities		(1	)		(2	)		1
Cash flows from/(used in) financing activities		308			31			(112	)
Net increase in cash and cash equivalents		2			3			1
Cash and cash equivalents at beginning of the year		13			10			9
Cash and cash equivalents at end of the year	$	15		$	13		$	10

Supplemental disclosure of cash paid (received):
Interest	$	112		$	115		$	103
Income taxes	$	77		$	13		$	(3	)
Supplemental disclosure of non-cash activities
(1) Change in accrued capital expenditures	$	40		$	(16	)	$	(9	)

(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.

At December 31, 2018 and 2017, TEC had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2018			2017
Tampa Electric	Installment contracts payable ⁽¹⁾ :
	5.65% Refunding bonds	2018	$	0		$	54
	Notes ⁽²⁾⁽³⁾ : 6.10%	2018		0			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
	4.30%	2048		275			0
	4.45%	2049		350			0
	Total long-term debt of Tampa Electric			2,292			1,921
PGS	Notes ⁽²⁾⁽³⁾ : 6.10%	2018		0			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
	4.30%	2048		75			0
	4.45%	2049		25			0
	Total long-term debt of PGS			312			262
Total long-term debt of TEC				2,604			2,183
Unamortized debt discount, net				(7	)		(3	)
Debt issuance costs				(22	)		(16	)
Total carrying amount of long-term debt				2,575			2,164
Less amount due within one year			0				304
Total long-term debt			$	2,575		$	1,860

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

At December 31, 2018, long-term debt had a carrying amount of $2,575 million and an estimated fair market value of $2,686 million. At December 31, 2017, total long-term debt had a carrying amount of $2,164 million and an estimated fair market value of $2,412 million. The fair value of debt securities determined using Level 1 measurements was zero and $55 million at December 31, 2018 and 2017, 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 2019 through 2023 and thereafter are as follows:

													Total
As of December 31, 2018													Long-Term
(millions)	2019		2020		2021		2022		2023		Thereafter		Debt
Tampa Electric	$	0	$	0	$	232	$	225	$	0	$	1,835	$	2,292
PGS		0		0		47		25		0		240		312
Total long-term debt maturities	$	0	$	0	$	279	$	250	$	0	$	2,075	$	2,604

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

TEC has two operating segments. Its Tampa Electric division 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:

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.

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 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.

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.

For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

(millions)	Estimated Useful Lives	December 31, 2018			December 31, 2017
Electric generation	21-56 years	$	5,038		$	4,766
Electric transmission	28-77 years		880			859
Electric distribution	14-56 years		2,568			2,437
Gas transmission and distribution	16-77 years		1,678			1,534
General plant and other	8-43 years		613			579
Total cost			10,777			10,175
Less accumulated depreciation			(3,214	)		(2,994	)
Construction work in progress			673			263
Total property, plant and equipment, net		$	8,236		$	7,444

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.7% and 3.5% for 2018, 2017 and 2016, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $345 million, $332 million and $304 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, reduced PGS’s annual depreciation expense by $16 million beginning in 2016 and an additional $10 million beginning January 1, 2019.

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

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 2018, 2017 and 2016, the rate was 6.46%. Total AFUDC for the years ended December 31, 2018, 2017 and 2016 was $15 million, $2 million and $36 million, respectively. The increase in 2018 is a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology. The decrease in 2017 is a result of the Polk Power Station conversion project, which was completed in January 2017.

TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke 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.

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3).

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.

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, 2018 and 2017, ITCs were $74 million and $22 million, respectively. The increase is due to solar projects placed in service in 2018.

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by

estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather and line losses.

Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.

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.

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $226 million and $229 million as of December 31, 2018 and 2017, respectively. 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 fuel prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

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, 2018 and 2017, unbilled revenues of $67 million and $66 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Tampa Electric and PGS are 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 by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $120 million, $113 million and $117 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Other deferred credits primarily include accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 8), asset retirement obligations (see Note 12), and a reserve for auto, general and workers’ compensation liability claims.

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, 2018 and 2017 ranged from 4.00% to 4.01% and 2.74% to 4.00%, respectively.

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. See Note 13 for further information regarding derivatives.

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.

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2018, are described as follows:

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

On January 1, 2018, TEC adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all of the related amendments. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

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. The adoption of this standard will have no impact on TEC’s consolidated financial statements.

service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. TEC is currently evaluating the transition methods and the impact of the adoption of this standard on the consolidated financial statements.

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.

This agreement provided for an additional $110 million in base revenue 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.

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 first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019.

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. See “Tampa Electric Tax Reform and Storm Settlement” below for information regarding the impact of tax reform. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are achieved 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 Tampa Electric’s 2013 rate case settlement, 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. In the third quarter of 2017, Tampa Electric

was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. At December 31, 2017, the amount of costs charged to the storm reserve regulatory liability exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. This regulatory asset amount was eliminated in 2018 to reflect the effective recovery as discussed in Tampa Electric Tax Reform and Storm Settlement below. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $10 million in restoration costs from prior named storms 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.

On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addressed 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. Beginning on April 1, 2018, the agreement authorized Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. As a result, during 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of $47 million and O&M expense and an increase in the storm reserve regulatory liability of $56 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense.

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. On December 15, 2016, PGS and OPC filed a settlement with the FPSC (which was approved by the FPSC on February 7, 2017) 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. No change in customer rates resulted from this agreement.

As part of the settlement, PGS and OPC agreed that 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 2017 PGS settlement agreement did not contain a provision for tax reform. In 2018, the FPSC approved a settlement agreement filed authorizing the utility to accelerate the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability in 2018 up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018.

In accordance with the settlement agreement, PGS will reduce its base rates by $12 million for the impact of tax reform and reduce depreciation rates by $10 million beginning in January 2019. PGS is permitted to initiate a general base rate proceeding in 2020 if it forecasts that ROE will fall below its allowed range.

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. 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 or the advance recovery of expenditures for approved costs.

Details of the regulatory assets and liabilities are presented in the following table:

	December 31,		December 31,
(millions)	2018		2017
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	56	$	45
Cost-recovery clauses ⁽²⁾		55		13
Environmental remediation ⁽³⁾		23		33
Postretirement benefits ⁽⁴⁾		295		272
Storm reserve ⁽⁵⁾		3		47
Other		26		23
Total regulatory assets		458		433
Less: Current portion		88		77
Long-term regulatory assets	$	370	$	356
Regulatory liabilities:
Regulatory tax liability ⁽⁶⁾	$	715	$	730
Cost-recovery clauses ⁽²⁾		17		32
Storm reserve ⁽⁷⁾		56		0
Accumulated reserve—cost of removal ⁽⁸⁾		513		518
Other		9		5
Total regulatory liabilities		1,310		1,285
Less: Current portion		44		58
Long-term regulatory liabilities	$	1,266	$	1,227

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.

At December 31, 2017, TEC provisionally revalued all deferred tax assets and liabilities, $194 million and $1,019 million, respectively, based on the rates at which they are expected to reverse in the future, which is 21% for federal tax purposes. At December 31, 2017, 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. Provisional amounts primarily related to the uncertainty of the application of 100% asset expensing rules after September 27, 2017, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. On August 3, 2018, the U.S Department of Treasury in conjunction with the IRS issued proposed regulations clarifying the immediate expensing depreciation provisions enacted by the Act related to whether regulated utility property acquired after September 27, 2017 and placed in service by December 31, 2017 qualifies for 100% expensing. At December 31, 2018, the amounts recorded are no longer provisional, however, TEC does not expect any material impact resulting from the proposed regulations.

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 2018, 2017 and 2016, TEC recorded net tax provisions of $81 million, $197 million and $152 million, respectively.

(millions)
For the year ended December 31,	2018			2017			2016
Current income taxes
Federal	$	72		$	(1	)	$	53
State		10			6			12
Deferred income taxes
Federal		(13	)		170			76
State		13			23			11
Investment tax credits amortization		(1	)		(1	)		0
Total income tax expense	$	81		$	197		$	152

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

(millions)
For the year ended December 31,	2018			2017			2016
Income before provision for income taxes	$	422		$	513		$	438
Federal statutory income tax rates		21	%		35	%		35	%
Income taxes, at statutory income tax rate		89			180			153
Increase (decrease) due to
State income tax, net of federal income tax		19			19			15
Excess deferred tax amortization		(24	)		0			0
AFUDC-equity		(2	)		(1	)		(8	)
Tax credits		(2	)		(3	)		(7	)
Other		1			2			(1	)
Total income tax expense on consolidated statements of income	$	81		$	197		$	152
Income tax expense as a percent of income from continuing operations, before income taxes		19.2	%		38.4	%		34.8	%

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,	2018		2017
Deferred tax liabilities ⁽¹⁾
Property related	$	969	$	919
Pension and postretirement benefits		105		100
Total deferred tax liabilities		1,074		1,019
Deferred tax assets ⁽¹⁾
Loss and credit carryforwards ⁽²⁾		146		91
Medical benefits		24		24
Insurance reserves		17		(5	)
Pension and postretirement benefits		63		57
Capitalized energy conservation assistance costs		16		13
Other		9		14
Total deferred tax assets		275		194
Total deferred tax liability, net	$	799	$	825

At December 31, 2018, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $340 million and $274 million, respectively, expiring between 2033 and 2037. TEC has unused general business credits of $78 million, expiring between 2028 and 2038. 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.

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:

As of December 31, 2018 and 2017, TEC’s uncertain tax positions for federal R&D tax credits were $8 million for both years, 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, 2018 and 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 expense” in the Consolidated Statements of Income. In 2018, 2017 and 2016, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2018, 2017 and 2016. 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 2015 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 was 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.

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 and the unfunded obligations of the Restoration Plan. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. The Restoration Plan is a non-qualified, non-contributory defined benefit retirement plan that allows certain members of senior management to receive contributions as if no IRS limits were in place.

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.

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)	2018			2017			2018			2017
Change in benefit obligation
Net benefit obligation at beginning of year	$	812		$	770		$	193		$	175
Service cost		21			20			2			2
Interest cost		29			31			7			7
Plan participants’ contributions		0			0			4			3
Plan curtailment		0			(1	)		0			0
Plan settlement		(7	)		(26	)		0			0
Benefits paid		(55	)		(51	)		(19	)		(16	)
Actuarial loss (gain)		(50	)		69			(14	)		22
Net benefit obligation at end of year	$	750		$	812		$	173		$	193

Change in plan assets
Fair value of plan assets at beginning of year	$	766		$	649		$	0		$	0
Actual return on plan assets		(63	)		122			0			0
Employer contributions		10			46			0			0
Employer direct benefit payments		8			27			15			13
Plan participants’ contributions		0			0			4			3
Plan settlement		(7	)		(26	)		0			0
Benefits paid		(54	)		(51	)		(19	)		(16	)
Direct benefit payments		(1	)		(1	)		0			0
Fair value of plan assets at end of year ⁽¹⁾	$	659		$	766		$	0		$	0

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:

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $705 million at December 31, 2018 and $762 million at December 31, 2017.

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:

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.

	Pension Benefits						Other Benefits
	2018			2017			2018			2017
Discount rate		4.33	%		3.62	%		4.38	%		3.70	%
Rate of compensation increase-weighted average		3.75	%		3.32	%		3.75	%		3.31	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.31	%		6.58	%
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:

The discount rate assumption used to determine the December 31, 2018 and 2017 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.

TECO Energy	Pension Benefits													Other Benefits ⁽¹⁾
	2018					2017					2016			2018			2017			2016
(millions)
Service cost	$	21				$	20				$	19		$	2		$	2		$	2
Interest cost		29					31					31			7			7			7
Expected return on plan assets		(49	)				(48	)				(46	)		0			0			0
Amortization of:
Actuarial loss		19					17					16			1			0			0
Prior service (benefit) cost		0					0					0			(2	)		(2	)		(2	)
Curtailment loss (gain)		0					0					1			0			0			0
Settlement loss		2		⁽³	⁾		7		⁽²	⁾		1			0			0			0
Net periodic benefit cost	$	22				$	27				$	22		$	8		$	7		$	7

New prior service cost	$	0		$	0		$	1		$	0		$	0	$	0
Net loss (gain) arising during the year		62			(5	)		47			(14	)		22		5
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2			2		2
Amortization or settlement of actuarial gain (loss)		(20	)		(24	)		(17	)		(1	)		0		0
Total recognized in OCI and regulatory assets	$	42		$	(29	)	$	31		$	(13	)	$	24	$	7
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	64		$	(2	)	$	53		$	(5	)	$	31	$	14

TEC’s portion of the net periodic benefit costs for pension benefits was $16 million, $14 million and $13 million for 2018, 2017 and 2016, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $8 million, $6 million and $6 million for 2018, 2017 and 2016, respectively. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”.

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 $12 million. There are no prior service credits to be amortized from regulatory assets into net periodic benefit cost in 2019 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 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.

TEC recognized a settlement charge in 2018 relating to the retirement of an executive in the SERP plan. TEC expects to recognize a settlement charge of approximately $1 million in 2019 related to the retirement of a SERP participant. TEC expects to recognize settlement charges of approximately $1 million in 2019 related to the retirement of Restoration plan participants.

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

	Pension Benefits									Other Benefits
	2018			2017			2016			2018			2017			2016
Discount rate		3.62	%		4.11	%		4.69	%		3.70	%		4.28	%	4.67%/3.85%
Expected long-term return on plan assets		6.85	%		7.00	%		7.00	%	N/A			N/A			N/A
Rate of compensation increase		3.32	%		2.57	%		2.59	%		3.31	%		2.48	%		2.50	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.58	%		6.83	%		7.05	%
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			2038

The discount rate assumption used to determine the benefit cost for 2018, 2017 and from the Merger date to December 31, 2016 was based on the same technique that was used to determine the December 31, 2018 and 2017 benefit obligation as discussed above. The discount rate assumption used to determine the January 1, 2016 through June 30, 2016 benefit cost 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.

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, 2018, TECO Energy’s pension plan’s actual earned losses were approximately 8%.

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 (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 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 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.

TECO Energy	At Fair Value as of December 31, 2018
(millions)
	Level 1			Level 2			Level 3		NAV ⁽¹⁾		Total
Cash	$	(3	)	$	0		$	0	$	0	$	(3	)
Accounts receivable		10			0			0		0		10
Accounts payable		(51	)		0			0		0		(51	)
Short-term investment funds (STIFs)		17			0			0		0		17
Common stocks		32			0			0		0		32
Real estate investment trusts (REITs)		3			0			0		0		3
Mutual funds		97			0			0		0		97
Municipal bonds		0			1			0		0		1
Government bonds		0			59			0		0		59
Corporate bonds		0			55			0		0		55
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Long Futures		6			0			0		0		6
Swaps		0			3			0		0		3
Purchase options (swaptions)		0			1			0		0		1
Written options (swaptions)		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		111			119			0		0		230
Common and collective trusts ⁽¹⁾		0			0			0		330		330
Mutual fund ⁽¹⁾		0			0			0		99		99
Total investments	$	111		$	119		$	0	$	429	$	659

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	)
STIFs		14			0			0		0		14
Common stocks		44			0			0		0		44
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
MBS		0			(1	)		0		0		(1	)
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

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

Additionally, the non-qualified SERP had $14 million and $17 million of assets as of December 31, 2018 and 2017, 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, 2018 and 2017.

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

The qualified pension plan’s actuarial value of assets, including credit balance, was 112.5% of the Pension Protection Act funded target as of January 1, 2018 and is estimated at 110.6% of the Pension Protection Act funded target as of January 1, 2019.

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 2018, 2017 and 2016, which met the minimum funding requirements for 2018, 2017 and 2016. TEC’s portion of the contribution in 2018 was $8 million and in 2017 was $36 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2019 contribution to be $15 million. TEC estimates its portion of annual contributions from 2020 to 2023 will range from $14 million to $17 million per year based on current assumptions. The amounts TECO Energy expects to contribute are in excess of the minimum funding required under ERISA guidelines.

TEC’s portion of the contributions to the SERP in 2018, 2017 and 2016 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2019. TEC made SERP payments of approximately $7 million from the trust in 2018 and expects to make a SERP payment of approximately $5 million from the trust in 2019.

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 2019, TEC expects to make a contribution of about $10 million. Postretirement benefit levels are substantially unrelated to salary.

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

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, 2018, 2017 and 2016, TEC’s portion of expense totaled $11 million, $11 million and $8 million, respectively, related to the matching contributions made to this plan.

	December 31, 2018						December 31, 2017
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding ⁽¹⁾		Outstanding		Facilities		Outstanding ⁽¹⁾		Outstanding
5-year facility ⁽²⁾	$	325	$	131	$	1	$	325	$	5	$	1
3-year accounts receivable facility ⁽³⁾		150		90		0		150		0		0
1-year term facility ⁽⁴⁾		0		0		0		300		300		0
Total	$	475	$	221	$	1	$	775	$	305	$	1

At December 31, 2018, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2018 and 2017 was 3.14% and 2.07%, respectively.

On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). Throughout the term of the facility, TEC will pay program and liquidity fees, which total 70 basis points at December 31, 2018. 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 Bank of Tokyo-Mitsubishi UFJ, Ltd.’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, 2018, TEC was in compliance with the requirements of the Loan Agreement.

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.

On June 7, 2018, TEC completed a sale of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048. Until December 15, 2047, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2047, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. Until December 15, 2048, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2048, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

At December 31, 2018 and 2017, $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.

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.

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, 2018, TEC has estimated its ultimate financial liability to be $28 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 Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

TEC has commitments for long-term leases (primarily for land, building space, vehicles and office equipment), long-term service agreements and capital projects, including Tampa Electric’s solar projects (see Note 3) and the modernization of the Big Bend power station. Rental expense for these leases included in “Operations & maintenance expense” on the Consolidated Statements of Income for the years ended December 31, 2018, 2017 and 2016, totaled $2 million, $2 million and $2 million, respectively. 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 minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2018:


			Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Transportation		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2019	$	194	$	298	$	257	$	7	$	2	$	5	$	763
2020		175		89		106		6		2		1		379
2021		141		33		3		6		2		0		185
2022		133		8		3		7		2		0		153
2023		108		2		1		11		2		0		124
Thereafter		1,013		6		0		78		34		0		1,131
Total future minimum payments	$	1,764	$	436	$	370	$	115	$	44	$	6	$	2,735

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2018 and 2017, TEC was in compliance with all required financial covenants.

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2018	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,067		$	0	$	0		$	1,067
Commercial		582			0		0			582
Industrial		161			0		0			161
Regulatory deferrals and unbilled revenue		(2	)		0		0			(2	)
Other ⁽¹⁾		258			0		(3	)		255
Total electric revenue		2,066			0		(3	)		2,063
Gas revenue
Residential		0			157		0			157
Commercial		0			151		0			151
Industrial ⁽²⁾		0			21		0			21
Other ⁽³⁾		0			159		(27	)		132
Total gas revenue		0			488		(27	)		461
Total revenue	$	2,066		$	488	$	(30	)	$	2,524

(1) Other includes sales to public authorities, off-system sales to other utilities and various other items.

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $135 million. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033.

Services received from affiliates primarily include shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary. 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 FPSC-approved cost-causative allocation methods or the Modified Massachusetts Formula.

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 764,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 392,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2018
Revenues - external	$	2,063	$	461	$	0			$	2,524
Sales to affiliates		3		27		(30	)			0
Total revenues		2,066		488		(30	)			2,524
Depreciation and amortization		312		60		0				372
Total interest charges		102		16		0				118
Provision for income taxes		65		16		0				81
Net income		294		47		0				341
Total assets		8,235		1,407		(487	)	⁽¹⁾		9,155
Capital expenditures		940		169		0				1,109
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

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.

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

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

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 and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines.

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.

On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which replaces the 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 (see Note 3). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had zero derivative assets and liabilities on its Consolidated Balance Sheets as of December 31, 2018 and it had $1 million of derivative liabilities as of December 31, 2017.

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 and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity 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 these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (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, 2018, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected.

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 and to optimize the value of natural gas storage capacity. 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, 2018, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

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:

As of December 31, 2018 and 2017, 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 Note 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.

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 entered into PPAs with wholesale energy providers in Florida, which expired in December 2018. These agreements ranged in size from 121 MW to 250 MW of available capacity, were with similar entities and contained similar provisions. In the first quarter of 2019, Tampa Electric entered into a PPA with a wholesale energy provider in Florida with up to 360 MW of available capacity. 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 reviewed these risks and determined that the owners of these entities retain 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 $15 million, $16 million and $62 million under these PPAs for the three years ended December 31, 2018, 2017 and 2016, respectively.

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. 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.

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, resulting in a cash payment. 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 paid in the form of 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 termination, disability or death.

A summary of the activity related to TEC employee PSUs is presented in the following table:

Compensation cost recognized for the PSU plan for the years ended December 31, 2018 and 2017 was $4 million and $2 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2018 and 2017 were $1 million and $1 million, respectively. As of December 31, 2018 and 2017, there was $6 million and $4 million, respectively, of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.

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

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, 2018 (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.

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, 2018 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, 2018.

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.

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.

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

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.

On November 10, 2017, Ernst & Young LLP (EY) was engaged as TEC’s independent registered public accounting firm for the fiscal year ending December 31, 2018, replacing PricewaterhouseCoopers LLP (PwC), TEC’s independent registered public accounting firm prior to 2018. The change in accounting firm was approved by the Board of Directors of Emera. EY serves as the independent accounting firm for Emera.

PwC’s audit reports on TEC’s consolidated financial statements for each of the fiscal years ended December 31, 2017 and 2016 did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles. During the fiscal years ended December 31, 2017 and 2016, there were (i) no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement, if not resolved to the satisfaction of PwC, would have caused PwC to make reference to the subject matter of the disagreement in its reports on the consolidated financial statements for such years, and (ii) no “reportable events” within the meaning of Item 304(a)(1)(v) of Regulation S-K.

The following table presents fees for professional audit services and other services rendered by EY and PwC for the audit of TEC’s annual financial statements and other services for the years ended December 31, 2018 and 2017, respectively.

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 EY and PwC, including fees for assessments and recommendations related to specific transactions, regulatory accounting advice and other miscellaneous services.

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

Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

Consolidated Statements of Retained Earnings for the Years Ended December 31, 2018, 2017 and 2016

Consolidated Statements of Capitalization for the Years Ended December 31, 2018 and 2017

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

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions ⁽¹⁾		Period
Allowance for Uncollectible Accounts:
2018	$	1	$	7	$	0	$	6	$	2
2017	$	1	$	5	$	0	$	5	$	1
2016	$	1	$	3	$	0	$	3	$	1

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.

Exhibits 10.1 through 10.4, above are management contracts or compensatory plans or arrangements in which executive officers or directors of Tampa Electric Company participate.

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.

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 19, 2019:

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.

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

Average cost per MMBTU	2018		2017		2016
Natural Gas ⁽¹⁾	$	4.07	$	4.01	$	3.79
Coal ⁽²⁾		3.37		3.30		3.61
Oil/petroleum coke		3.10		2.54		2.14
Composite ⁽³⁾		3.89		3.69		3.61


(millions)
Credit facilities	$	475
Drawn amounts/LCs		222
Available credit facilities		253
Cash and short-term investments		15
Total liquidity	$	268


			Calculation
Instrument	Financial Covenant ⁽¹⁾	Requirement/Restriction	at December 31, 2018
Credit facility- $325 million ⁽²⁾	Debt/capital	Cannot exceed 65%	45.8%
Accounts receivable credit facility - $150 million ⁽²⁾	Debt/capital	Cannot exceed 65%	45.8%


Year	1% Decrease in Assumed Expected Return on Assets	1% Decrease in Assumed Discount Rate
2018	$4 million increase	$2 million increase
2019	$6 million increase	$2 million increase

Term		Meaning
OPC		Office of Public Counsel
OPEB		other postemployment benefits
Parent		TECO Energy, Inc., the direct parent company of Tampa Electric Company
PBGC		Pension Benefit Guarantee Corporation
PBO		projected 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
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

(thousands)	2018		2017		2016
Residential		9,418		9,029		9,188
Commercial		6,266		6,362		6,310
Industrial		2,014		2,024		1,928
Other sales of electricity		1,933		1,771		1,808
Total retail		19,631		19,186		19,234
Off system sales		286		239		206
Total energy sold		19,917		19,425		19,440


	•		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

(millions)	Actual 2018			Forecasted 2019
Tampa Electric ⁽¹⁾
Transmission	$	47		$	50
Distribution		201			235
Generation		150			375
Renewable generation		506			205
Facilities, equipment, vehicles and other		66			105
Tampa Electric total		970			970
PGS		172			240
Net cash effect of accruals, retentions and AFUDC		(33	)		0
Total	$	1,109		$	1,210

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2018			2017			2018			2017
Accrued benefit costs and other current liabilities	$	(5	)	$	(7	)	$	(10	)	$	(10	)
Deferred credits and other liabilities		(68	)		(30	)		(137	)		(154	)
	$	(73	)	$	(37	)	$	(147	)	$	(164	)

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2018		2017		2018		2017
Net actuarial loss (gain)	$	251	$	215	$	45	$	70
Prior service cost (credit)		0		1		0		(13	)
Amount recognized	$	251	$	216	$	45	$	57

TECO Energy	2018 Target Allocation		Actual Allocation, End of Year
Asset Category			2018			2017
Equity securities	47%-53%			46	%		51	%
Fixed income securities	47%-53%			54	%		49	%
Total		100%		100	%		100	%

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2019	$	57	$	12
2020		55		12
2021		59		12
2022		60		12
2023		60		12
2024-2028		333		59


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.

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2017		133		$	45.11	$	6
Granted including DRIP		130			47.98		6
Exercised		(4	)		38.85		(1	)
Forfeited		(1	)		45.41		0
Outstanding as of December 31, 2018		258		$	46.68	$	11

	2018		2017
Audit fees	$	680,001	$	915,897
Audit-related fees		0		7,395
Tax fees
Tax compliance fees		168,684		0
Tax planning fees		0		0
All other fees		0		0
Total	$	848,685	$	923,292

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 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).	*

4.2	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).	*

4.3	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).	*

4.4	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).	*

4.5	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).	*

4.6	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).	*

4.7	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).	*

4.8	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).	*

4.9	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).	*

4.10	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).	*

4.11	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).	*

4.12	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).	*

4.13	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).	*

Exhibit No.	Description
4.14	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).	*

4.15	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).	*
4.16	Thirteenth Supplemental Indenture dated as of June 7, 2018, 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 (Exhibit 4.9, Form 8-K dated June 7, 2018 of Tampa Electric Company).	*
4.17	Fourteenth Supplemental Indenture dated as of October 4, 2018 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 (Exhibit 4.11, Form 8-K dated October 4, 2018 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	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).	*

10.6	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.).	*

10.7	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.).	*

10.8	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).	*

10.9	Amendment No. 2 dated as of March 23, 2018 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 8-K dated March 23, 2018 of Tampa Electric Company).	*


10.10	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).	*

Exhibit No.	Description
10.11	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).	*

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

	TAMPA ELECTRIC COMPANY

Dated: February 19, 2019	By:	/s/ Nancy Tower
		Nancy Tower
		President and Chief Executive Officer
		(Principal Executive Officer)