10-K 1 ck0000096271-10k_20171231.htm 10-K ck0000096271-10k_20171231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2017

OR

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

For the transition period from                      to                     

 

Commission

File No.

  

Exact name of each Registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number

  

I.R.S. Employer

Identification

Number

1-5007

  

TAMPA ELECTRIC COMPANY

  

59-0475140

 

  

(a Florida corporation)

  

 

 

  

TECO Plaza

  

 

 

  

702 N. Franklin Street

  

 

 

  

Tampa, Florida 33602

  

 

 

  

(813) 228-1111

  

 

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

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

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

YES      NO  

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

YES      NO  

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

YES      NO  

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

YES      NO  

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  

Smaller reporting company

 

 

 

 

 

 

 

 

 

 

 

  

Emerging growth company

 

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

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

YES      NO  

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

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

 

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

 

 

 

 

 


DEFINITIONS

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

 

Term

  

Meaning

ABS

 

asset-backed security

AFUDC

 

allowance for funds used during construction

AFUDC-debt

 

debt component of allowance for funds used during construction

AFUDC-equity

 

equity component of allowance for funds used during construction

AOCI

 

accumulated other comprehensive income

APBO

 

accumulated postretirement benefit obligation

ARO

 

asset retirement obligation

ASC

 

Accounting Standards Codification

BACT

 

Best Available Control Technology

CAD

 

Canadian dollars

CAIR

 

Clean Air Interstate Rule

CCRs

 

coal combustion residuals

CMO

 

collateralized mortgage obligation

CNG

 

compressed natural gas

CPI

 

consumer price index

CSAPR

 

Cross State Air Pollution Rule

CO2

 

carbon dioxide

CT

 

combustion turbine

ECRC

 

environmental cost recovery clause

EEI

 

Edison Electric Institute

EGWP

 

Employee Group Waiver Plan

Emera

 

Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada

EPA

 

U.S. Environmental Protection Agency

ERISA

 

Employee Retirement Income Security Act

EROA

 

expected return on plan assets

EUSHI

 

Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock

FASB

 

Financial Accounting Standards Board

FDEP

 

Florida Department of Environmental Protection

FERC

 

Federal Energy Regulatory Commission

FPSC

 

Florida Public Service Commission

GHG

 

greenhouse gas(es)

HAFTA

 

Highway and Transportation Funding Act

IGCC

 

integrated gasification combined-cycle

IOU

 

investor owned utility

IRS

 

Internal Revenue Service

ISDA

 

International Swaps and Derivatives Association

ITCs

 

investment tax credits

KW

 

kilowatt(s)

kWac

 

kilowatt on an alternating current basis

MAP-21

 

Moving Ahead for Progress in the 21st Century Act

MBS

 

mortgage-backed securities

MD&A

 

the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations

Merger

 

Merger of Merger Sub Company with and into TECO Energy, with TECO Energy as the surviving corporation

MGP

 

manufactured gas plant

Merger Agreement

 

Agreement and Plan of Merger dated September 4, 2015, by and among TECO Energy, Emera and Merger Sub Company

Merger Sub Company

 

Emera US Inc., a Florida corporation

MMA

 

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

MMBTU

 

one million British Thermal Units

MRV

 

market-related value

MW

 

megawatt(s)

MWH

 

megawatt-hour(s)

NAESB

 

North American Energy Standards Board

3


Term

  

Meaning

NAV

 

net asset value

Note

 

Note to consolidated financial statements

NOx

 

nitrogen oxide

NPNS

 

normal purchase normal sale

NYMEX

 

New York Mercantile Exchange

O&M expenses

 

operations and maintenance expenses

OCI

 

other comprehensive income

OPC

 

Office of Public Counsel

OPEB

 

other postretirement benefits

OTC

 

over-the-counter

PBGC

 

Pension Benefit Guarantee Corporation

PBO

 

postretirement benefit obligation

PGA

 

purchased gas adjustment

PGS

 

Peoples Gas System, the gas division of Tampa Electric Company

PPA

 

power purchase agreement

PRP

 

potentially responsible party

R&D

 

research and development

REIT

 

real estate investment trust

RFP

 

request for proposal

ROE

 

return on common equity

Regulatory ROE

 

return on common equity as determined for regulatory purposes

ROW

 

rights-of-way

S&P

 

Standard and Poor’s

SCR

 

selective catalytic reduction

SEC

 

U.S. Securities and Exchange Commission

SO2

 

sulfur dioxide

SoBRAs

 

solar base rate adjustments

SERP

 

Supplemental Executive Retirement Plan

STIF

 

short-term investment fund

Tampa Electric

 

Tampa Electric, the electric division of Tampa Electric Company

TEC

 

Tampa Electric Company

TECO Energy

 

TECO Energy, Inc., the direct parent company of Tampa Electric Company

TSI

 

TECO Services, Inc.

U.S. GAAP

 

generally accepted accounting principles in the United States

VIE

 

variable interest entity

WRERA

 

The Worker, Retiree and Employer Recovery Act of 2008

 

 

 

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PART I

 

 

Item 1. BUSINESS

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

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

Merger with Emera

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

TEC Revenues

 

(millions)

 

2017

 

 

2016

 

 

2015

 

Tampa Electric division

 

$

2,054

 

 

$

1,965

 

 

$

2,018

 

PGS division

 

 

438

 

 

 

439

 

 

 

407

 

Eliminations

 

 

(22

)

 

 

(8

)

 

 

(6

)

Total revenues

 

$

2,470

 

 

$

2,396

 

 

$

2,419

 

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

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

TAMPA ELECTRIC – Electric Operations

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

5


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

Tampa Electric Operating Revenue

 

(millions)

 

2017

 

 

2016

 

 

2015

 

Residential

 

$

1,006

 

 

$

1,036

 

 

$

1,040

 

Commercial

 

 

578

 

 

 

593

 

 

 

608

 

Industrial

 

 

158

 

 

 

161

 

 

 

160

 

Other retail sales of electricity

 

 

168

 

 

 

175

 

 

 

177

 

Total retail

 

 

1,910

 

 

 

1,965

 

 

 

1,985

 

Sales for resale

 

 

8

 

 

 

6

 

 

 

4

 

Other

 

 

136

 

 

 

(6

)

 

 

29

 

Total operating revenues

 

$

2,054

 

 

$

1,965

 

 

$

2,018

 

Megawatt-hour Sales

 

(thousands)

 

2017

 

 

2016

 

 

2015

 

Residential

 

 

9,029

 

 

 

9,188

 

 

 

9,045

 

Commercial

 

 

6,362

 

 

 

6,310

 

 

 

6,301

 

Industrial

 

 

2,024

 

 

 

1,928

 

 

 

1,870

 

Other retail sales of electricity

 

 

1,771

 

 

 

1,808

 

 

 

1,791

 

Total retail

 

 

19,186

 

 

 

19,234

 

 

 

19,007

 

Sales for resale

 

 

239

 

 

 

206

 

 

 

115

 

Total energy sold

 

 

19,425

 

 

 

19,440

 

 

 

19,122

 

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

Regulation

Base Rates

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

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

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

This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that an expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. The agreement provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, any party to the agreement other than Tampa Electric could seek a review of its base rates. In addition, Tampa Electric is required to file a depreciation study no fewer than 60 days but no more than one year before filing its next base rate request. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital, and Tampa Electric also began using a 15-year amortization period for all computer software

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beginning on January 1, 2013.

 

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

 

The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue requirement adjustments for the SoBRAs: $31 million for 150 MWs effective September 1, 2018, $51 million for 250 MWs effective January 1, 2019, $31 million for 150 MWs effective January 1, 2020, and an additional $10 million for 50 MWs effective on January 1, 2021. In order for each tranche of SoBRAs to take effect, Tampa Electric must show they are cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction.

 

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

 

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

 

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

 

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

Other Cost Recovery

Tampa Electric has four additional cost recovery clauses.

 

(1)

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

 

(2)

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

 

(3)

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

 

(4)

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

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

7


FERC and Other Regulations

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

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

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

Competition

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

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

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

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

Generation Sources

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

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

 

Average cost per MMBTU

 

2017

 

 

2016

 

 

2015

 

Natural Gas (1)

 

$

4.01

 

 

$

3.79

 

 

$

4.34

 

Coal (2)

 

 

3.30

 

 

 

3.61

 

 

 

3.44

 

Oil (3)

 

 

2.54

 

 

 

2.14

 

 

 

2.36

 

Composite (4)

 

 

3.69

 

 

 

3.61

 

 

 

3.78

 

 

8


(1)

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

(2)

Represents the cost of coal and transportation.

(3)

Represents the cost of oil, including petroleum coke.

(4)

Represents the average cost for all fuels listed.

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

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

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

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

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

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

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

Franchises and Other Rights

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

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

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

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

9


Environmental Matters

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

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

PEOPLES GAS SYSTEM – Gas Operations

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

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

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

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

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

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

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

 

 

 

Revenues

 

 

Therms

 

(millions)

 

2017

 

 

2016

 

 

2015

 

 

2017

 

 

2016

 

 

2015

 

Residential

 

$

138

 

 

$

140

 

 

$

137

 

 

 

77

 

 

 

78

 

 

 

75

 

Commercial

 

 

144

 

 

 

143

 

 

 

139

 

 

 

489

 

 

 

488

 

 

 

471

 

Industrial

 

 

15

 

 

 

13

 

 

 

13

 

 

 

330

 

 

 

321

 

 

 

289

 

Off-system sales

 

 

70

 

 

 

73

 

 

 

50

 

 

 

201

 

 

 

245

 

 

 

166

 

Power generation

 

 

5

 

 

 

5

 

 

 

7

 

 

 

750

 

 

 

760

 

 

 

758

 

Other revenues

 

 

54

 

 

 

53

 

 

 

50

 

 

 

-

 

 

 

-

 

 

 

-

 

Total

 

$

426

 

 

$

427

 

 

$

396

 

 

 

1,847

 

 

 

1,892

 

 

 

1,759

 

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

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Regulation

Base Rates

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

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

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

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The settlement agreement provided that bottom of the range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement.

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

Cost Recovery Clauses and Riders

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

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

FPSC and Other Regulation

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

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

Competition

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

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

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

Gas Supplies

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

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

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

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

Franchises and Other Rights

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

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

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

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

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Environmental Matters

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

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

 

Item 1A. RISK FACTORS

General Risks

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

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

Developments in technology could reduce demand for electricity and gas.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Potential competitive changes may adversely affect TEC.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

 

May need to remove or abandon its facilities on the property covered by rights-of-way or franchises and seek alternative

locations for its transmission or distribution facilities;

 

 

 

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

 

 

 

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

 

 

 

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

customers.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

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Item 2. PROPERTIES

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

TAMPA ELECTRIC

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

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

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

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

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

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

PEOPLES GAS SYSTEM

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

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

Item 3. LEGAL PROCEEDINGS

From time to time, TEC is involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. For a discussion of legal proceedings and environmental matters, see Note 9, Commitments and Contingencies, of the 2017 Annual TEC Consolidated Financial Statements.

 

 

 

 

18


PART II

 

 

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

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

 

 

Item 6. SELECTED FINANCIAL DATA OF TAMPA ELECTRIC COMPANY

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

 

 

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

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

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

OVERVIEW

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

 

MERGER WITH EMERA

TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned subsidiary of Emera. Therefore, TEC became an indirect, wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. See Notes 8 and 10 to the 2017 Annual TEC Consolidated Financial Statements for further information regarding the Merger and related party transactions between TEC and its affiliates, respectively.

2017 PERFORMANCE

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

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

OUTLOOK

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

19


 

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

 

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

 

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

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

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

 

U.S. TAX REFORM

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

 

Key provisions impacting TEC:

 

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

 

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

 

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

 

Repeal of section 199 domestic production deduction.

 

Impact on December 31, 2017 results:

 

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

 

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

 

Future impacts:

 

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

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

20


 

OPERATING RESULTS

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

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

(millions)

 

 

 

2017

 

 

2016

 

 

2015

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tampa Electric

 

$

2,054

 

 

$

1,965

 

 

$

2,018

 

 

 

PGS

 

 

438

 

 

 

439

 

 

 

407

 

 

 

Eliminations

 

 

(22

)

 

 

(8

)

 

 

(6

)

 

 

TEC

 

$

2,470

 

 

$

2,396

 

 

$

2,419

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tampa Electric

 

$

273

 

 

$

251

 

 

$

241

 

 

 

PGS

 

 

43

 

 

 

35

 

 

 

35

 

 

 

TEC

 

$

316

 

 

$

286

 

 

$

276

 

TAMPA ELECTRIC

Electric Operations Results

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

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

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

21


Summary of Operating Results

 

(millions, except customers and total degree days)

 

2017

 

 

% Change

 

 

2016

 

 

% Change

 

 

2015

 

Revenues

 

$

2,054

 

 

 

5

 

 

$

1,965

 

 

 

(3

)

 

$

2,018

 

O&M expense

 

 

399

 

 

 

(6

)

 

 

424

 

 

 

1

 

 

 

421

 

Depreciation and amortization expense

 

 

300

 

 

 

12

 

 

 

268

 

 

 

4

 

 

 

257

 

Taxes, other than income

 

 

162

 

 

 

3

 

 

 

157

 

 

 

1

 

 

 

156

 

Non-fuel operating expenses

 

 

861

 

 

 

1

 

 

 

849

 

 

 

2

 

 

 

834

 

Fuel expense

 

 

608

 

 

 

7

 

 

 

568

 

 

 

(12

)

 

 

644

 

Purchased power expense

 

 

46

 

 

 

(56

)

 

 

104

 

 

 

32

 

 

 

79

 

Total fuel & purchased power expense

 

 

654

 

 

 

(3

)

 

 

672

 

 

 

(7

)

 

 

723

 

Total operating expenses

 

 

1,515

 

 

 

(0

)

 

 

1,521

 

 

 

(2

)

 

 

1,557

 

Operating income

 

$

539

 

 

 

21

 

 

$

444

 

 

 

(4

)

 

$

461

 

AFUDC-equity

 

$

2

 

 

 

(92

)

 

$

24

 

 

 

41

 

 

$

17

 

Provision for income taxes

 

$

171

 

 

 

32

 

 

$

130

 

 

 

(10

)

 

$

144

 

Net income

 

$

273

 

 

 

9

 

 

$

251

 

 

 

4

 

 

$

241

 

Megawatt-Hour Sales (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 

9,029

 

 

 

(2

)

 

 

9,188

 

 

 

2

 

 

 

9,045

 

Commercial

 

 

6,362

 

 

 

1

 

 

 

6,310

 

 

 

0

 

 

 

6,301

 

Industrial

 

 

2,024

 

 

 

5

 

 

 

1,928

 

 

 

3

 

 

 

1,870

 

Other

 

 

1,771

 

 

 

(2

)

 

 

1,808

 

 

 

1

 

 

 

1,791

 

Total retail

 

 

19,186

 

 

 

(0

)

 

 

19,234

 

 

 

1

 

 

 

19,007

 

Sales for resale

 

 

239

 

 

 

16

 

 

 

206

 

 

 

79

 

 

 

115

 

Total energy sold

 

 

19,425

 

 

 

(0

)

 

 

19,440

 

 

 

2

 

 

 

19,122

 

Retail customers—(thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31

 

 

748

 

 

 

2

 

 

 

736

 

 

 

2

 

 

 

724

 

Retail net energy for load

 

 

20,297

 

 

 

1

 

 

 

20,165

 

 

 

0

 

 

 

20,103

 

Total degree days

 

 

4,520

 

 

 

1

 

 

 

4,462

 

 

 

(6

)

 

 

4,729

 

Operating Revenues

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

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

Customer and Energy Sales Growth Outlook

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

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

22


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

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

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

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

Operating Expenses

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

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

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

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

 

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

Fuel Prices and Fuel Cost Recovery

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

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

 

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

Solar Initiatives

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

23


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

 

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

 

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

 

PGS

Operating Results

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

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

 

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

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

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

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

24


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

Summary of Operating Results

 

(millions, except customers)

 

2017

 

 

% Change

 

 

2016

 

 

% Change

 

 

2015

 

Revenues

 

$

438

 

 

 

(0

)

 

$

439

 

 

 

8

 

 

$

407

 

Cost of gas sold

 

 

153

 

 

 

(4

)

 

 

159

 

 

 

17

 

 

 

136

 

Operating expenses

 

 

201

 

 

 

(5

)

 

 

211

 

 

 

5

 

 

 

201

 

Operating income

 

$

84

 

 

 

22

 

 

$

69

 

 

 

(1

)

 

$

70

 

Net income

 

$

43

 

 

 

23

 

 

$

35

 

 

 

0

 

 

$

35

 

Therms sold – by customer segment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 

77

 

 

 

(1

)

 

 

78

 

 

 

4

 

 

 

75

 

Commercial

 

 

489

 

 

 

0

 

 

 

488

 

 

 

4

 

 

 

471

 

Industrial

 

 

330

 

 

 

3

 

 

 

321

 

 

 

11

 

 

 

289

 

Off-system sales

 

 

201

 

 

 

(18

)

 

 

245

 

 

 

48

 

 

 

166

 

Power generation

 

 

750

 

 

 

(1

)

 

 

760

 

 

 

0

 

 

 

758

 

Total

 

 

1,847

 

 

 

(2

)

 

 

1,892

 

 

 

8

 

 

 

1,759

 

Therms sold – by sales type

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

System supply

 

 

303

 

 

 

(13

)

 

 

347

 

 

 

29

 

 

 

269

 

Transportation

 

 

1,544

 

 

 

(0

)

 

 

1,545

 

 

 

4

 

 

 

1,490

 

Total

 

 

1,847

 

 

 

(2

)

 

 

1,892

 

 

 

8

 

 

 

1,759

 

Customer (thousands) – at December 31(1)

 

 

378

 

 

 

3

 

 

 

368

 

 

 

3

 

 

 

359

 

(1)

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

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

PGS Outlook

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

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

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

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

OTHER ITEMS IMPACTING NET INCOME

Other Income, Net

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

25


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

Interest Expense

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

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

Income Taxes

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

 

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

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

 

LIQUIDITY, CAPITAL RESOURCES

Balances as of December 31, 2017  

 

 

 

 

 

 

(millions)

 

 

 

 

Credit facilities

 

$

775

 

Drawn amounts/LCs

 

 

306

 

Available credit facilities

 

 

469

 

Cash and short-term investments

 

 

13

 

Total liquidity

 

$

482

 

26


Cash from Operating Activities

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

Cash from Investing Activities

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

Cash from Financing Activities

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

Cash and Liquidity Outlook

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

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

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

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

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

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

27


Short-Term Borrowings

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

 

 

 

December 31, 2017

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

Letters of

 

 

 

 

 

 

 

 

 

 

Letters of

 

 

 

Credit

 

 

Borrowings

 

 

Credit

 

 

Credit

 

 

Borrowings

 

 

Credit

 

(millions)

 

Facilities

 

 

Outstanding(1)

 

 

Outstanding

 

 

Facilities

 

 

Outstanding(1)

 

 

Outstanding

 

5-year facility (2)

 

$

325

 

 

$

5

 

 

$

1

 

 

$

325

 

 

$

40

 

 

$

1

 

3-year accounts receivable facility (3)

 

 

150

 

 

 

0

 

 

 

0

 

 

 

150

 

 

 

130

 

 

 

0

 

1-year term facility (4)

 

 

300

 

 

 

300

 

 

 

0

 

 

 

0

 

 

 

0

 

 

 

0

 

   Total

 

$

775

 

 

$

305

 

 

$

1

 

 

$

475

 

 

$

170

 

 

$

1

 

(1)

Borrowings outstanding are reported as notes payable.

(2)

This 5-year facility matures March 22, 2022.

(3)

This 3-year facility matures on March 23, 2018.

(4)

This 1-year facility matures on November 1, 2018.

These credit facilities require commitment fees ranging from 12.5 to 30.0 basis points.  The weighted average interest rate on outstanding amounts payable under the credit facilities at December 31, 2017 and 2016 was 2.07% and 1.49%, respectively. For a complete description of the credit facilities see Note 6 to the 2017 Annual TEC Consolidated Financial Statements.

 

 

 

Maximum

 

 

Minimum

 

 

Average

 

 

Average

 

 

 

drawn

 

 

drawn

 

 

drawn

 

 

interest

 

(millions)

 

amount

 

 

amount

 

 

amount