10-K 1 ck0000096271-10k_20161231.htm 10K-20161231 ck0000096271-10k_20161231.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, 2016

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  

Smaller reporting company

 

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, 2016 was zero.

As of February 8, 2017, 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.

 

 

 

 

 

 


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

ADR

 

American depository receipts

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

AMT

 

alternative minimum tax

AOCI

 

accumulated other comprehensive income

APBO

 

accumulated postretirement benefit obligation

ARO

 

asset retirement obligation

BACT

 

Best Available Control Technology

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

HCIDA

 

Hillsborough County Industrial Development Authority

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)

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

NMGC

 

New Mexico Gas Company, Inc.

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

PPSA

 

Power Plant Siting Act

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

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 736,000 customers in West Central Florida with a net winter system generating capacity of 4,731 MW at December 31, 2016. 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 374,000 customers at December 31, 2016, 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 2016 was approximately 1.9 billion therms. TEC had approximately 2,600 employees as of December 31, 2016. All of TEC’s common stock is owned by TECO Energy, a holding company for regulated utilities and other businesses.

TEC makes its SEC (www.sec.gov) filings available free of charge on TECO Energy’s website (www.tecoenergy.com) 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. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. See Note 8 to the 2016 Annual TEC Consolidated Financial Statements for further information regarding the Merger.

TEC Revenues

 

(millions)

 

2016

 

 

2015

 

 

2014

 

Tampa Electric division

 

$

1,964.5

 

 

$

2,018.3

 

 

$

2,021.0

 

PGS division

 

 

439.3

 

 

 

407.5

 

 

 

399.6

 

Eliminations

 

 

(8.0

)

 

 

(6.6

)

 

 

(1.6

)

Total revenues

 

$

2,395.8

 

 

$

2,419.2

 

 

$

2,419.0

 

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 2016 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 electric generating stations in or near Tampa and one electric generating station in southwestern Polk County, Florida.

Tampa Electric had 2,039 employees as of December 31, 2016, of which 819 were represented by the International Brotherhood of Electrical Workers and 168 were represented by the Office and Professional Employees International Union.

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In 2016, Tampa Electric’s total operating revenue was derived approximately 53% from residential sales, 30% from commercial sales, 8% from industrial sales and 9% from other sales, including bulk power sales for resale. The sources of operating revenue and MWH sales for the years indicated were as follows:

Tampa Electric Operating Revenue

 

(millions)

 

2016

 

 

2015

 

 

2014

 

Residential

 

$

1,035.5

 

 

$

1,040.3

 

 

$

1,007.6

 

Commercial

 

 

593.4

 

 

 

608.0

 

 

 

602.0

 

Industrial

 

 

161.1

 

 

 

160.2

 

 

 

164.5

 

Other retail sales of electricity

 

 

174.4

 

 

 

177.2

 

 

 

181.9

 

Total retail

 

 

1,964.4

 

 

 

1,985.7

 

 

 

1,956.0

 

Sales for resale

 

 

6.3

 

 

 

3.7

 

 

 

13.0

 

Other

 

 

(6.2

)

 

 

28.9

 

 

 

52.0

 

Total operating revenues

 

$

1,964.5

 

 

$

2,018.3

 

 

$

2,021.0

 

Megawatt- hour Sales

 

(thousands)

 

2016

 

 

2015

 

 

2014

 

Residential

 

 

9,188

 

 

 

9,045

 

 

 

8,656

 

Commercial

 

 

6,310

 

 

 

6,301

 

 

 

6,142

 

Industrial

 

 

1,928

 

 

 

1,870

 

 

 

1,901

 

Other retail sales of electricity

 

 

1,808

 

 

 

1,791

 

 

 

1,827

 

Total retail

 

 

19,234

 

 

 

19,007

 

 

 

18,526

 

Sales for resale

 

 

206

 

 

 

115

 

 

 

259

 

Total energy sold

 

 

19,440

 

 

 

19,122

 

 

 

18,785

 

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

Tampa Electric’s retail operations are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuance of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.

In general, 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 for the electric system, are recovered through base rates. These costs include O&M expenses, depreciation, taxes, and a return on investment in assets used and useful in 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 revenue requirement and 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 results of a Stipulation and Settlement Agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $57.5 million effective November 1, 2013, an additional $7.5 million effective November 1, 2014, an additional $5.0 million effective November 1, 2015, and an additional $110.0 million effective the date that an expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a

6


potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. 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 beginning on January 1, 2013.

Tampa Electric’s storm reserve was $56.1 million at both December 31, 2016 and 2015. Tampa Electric ceased accruing $8.0 million annually to the FPSC-approved self-insured storm damage reserve effective November 1, 2013. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million, the level of the reserve as of October 31, 2013. As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric has incurred $8.6 million of storm costs in 2016. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five-month period ended December 31, 2017.

Tampa Electric has a fuel recovery clause, approved by the FPSC, 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 through electricity rates in a year are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year. 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. Through its conservation cost recovery clause, Tampa Electric also 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 November 2016, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2017.

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. Given TECO Energy’s (TEC’s parent) acquisition of NMGC in 2014, Tampa Electric and TECO Energy jointly requested a waiver from FERC in order to continue to supply a de-minimis level of non-power goods and services to affiliates, which the FERC granted without conditions effective as of January 1, 2015. Through TSI, TECO Energy provides TEC with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. For additional information regarding TSI, see Note 10 to the 2016 Annual TEC Consolidated Financial Statements.

On June 30, 2014, Tampa Electric filed its required triennial market-power analysis in support of the company’s continued ability to effect wholesale market-based rate transactions everywhere, except in Tampa Electric’s balancing-authority area. FERC accepted Tampa Electric’s filing on November 24, 2015. Tampa Electric will file its next triennial market power analysis with FERC by June 30, 2017.

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. At the present time, 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 as well as other power generators. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale markets is affected by the state’s PPSA, which sets the state’s electric energy and environmental policy, and governs the building of new generation involving steam capacity

7


of 75 MW or more. Tampa Electric is not a major participant in the wholesale market because it uses its lower-cost generation to serve its retail customers rather than the wholesale market.

FPSC rules promote cost-competitiveness in the building of new steam generating 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 greater than 75 MW. These rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids and provide more stringent standards for the IOUs to recover cost overruns in the event that the self-build option is deemed the most cost-effective.

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, called 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. See the Solar Initiative section of the MD&A.

Fuel

Approximately 56% of Tampa Electric’s generation of electricity for 2016 was natural gas-fired, with coal representing approximately 38% and oil/petroleum coke representing 6%. Tampa Electric used its generating units to meet approximately 87% of the total system load requirements, with the remaining 13% coming from purchased power. Tampa Electric is required to maintain a generation capacity greater than firm peak demand. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20% reserve margin over firm peak demand.

Tampa Electric’s average delivered fuel cost per MMBTU and average delivered cost per unit of coal burned have been as follows:

 

Average cost per MMBTU

 

2016

 

 

2015

 

 

2014

 

Natural Gas (1)

 

$

3.79

 

 

$

4.34

 

 

$

5.68

 

Coal (2)

 

 

3.61

 

 

 

3.44

 

 

 

3.58

 

Oil (3)

 

 

2.14

 

 

 

2.36

 

 

 

2.66

 

Composite (4)

 

 

3.61

 

 

 

3.78

 

 

 

4.16

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average cost per ton of coal burned

 

$

85.38

 

 

$

80.83

 

 

$

84.40

 

 

(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, and compliance with environmental standards and regulations.

In 2016, 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 a combination of high-sulfur coal and petroleum coke; 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, 2016, approximately 66% of Tampa Electric’s 1,500,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 84% of its expected gas needs for the April 2017 through October 2017 period. In early March 2017, Tampa Electric expects to issue RFPs to meet its remaining 2017 gas needs and begin contracting for its 2018 requirements. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

The combined cycle unit at the Polk Power Station began commercial operations in January 2017. Existing natural gas supplies and interstate pipeline capacity are sufficient to support its operations.

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Coal. Tampa Electric burned approximately 3.0 million tons of coal during 2016 and estimates that its coal consumption will be about 3.6 million tons in 2017. During 2016, Tampa Electric purchased approximately 94% of its coal under long-term contracts with four suppliers, and approximately 6% of its coal in the spot market. Tampa Electric expects to obtain approximately 56% of its coal requirements in 2017 under long-term contracts with four suppliers and the remaining 44% in the spot market. 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 2016, approximately 96% of Tampa Electric’s coal supply was deep-mined and approximately 4% 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. Tampa Electric cannot predict, however, the effect of any future mining laws and regulations.

Oil. Tampa Electric purchases low sulfur No. 2 fuel oil and petroleum coke for its Big Bend and Polk Power stations 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 rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.

Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. The City of Temple Terrace reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed in 2017. In the absence of such right to purchase caused by non-renewal, Tampa Electric would be able to continue to use public rights-of-way within the municipality based on judicial precedent, subject to reasonable rules and regulations imposed by the municipalities.

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from September 2017 through August 2043 and are expected to be renewed under similar terms and conditions.

Franchise fees expense totaled $46.5 million in 2016 and 2015. Franchise fees are calculated using a formula based primarily on electric revenues and are recovered from customers on a dollar-for-dollar basis.

Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities 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 Commissioners 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 for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.

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 2016 capital expenditures included approximately $11 million related to environmental compliance and improvement programs, primarily for scrubber improvements, SCR catalyst replacements and electrostatic precipitators 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.

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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 370,000 customers. The system includes approximately 12,400 miles of mains and 7,000 miles of service lines (see PGS’s Franchises and Other Rights section below). Gas mains are distribution lines that serve as a common source of supply for more than one service line.

PGS had 539 employees as of December 31, 2016. A total of 140 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

In 2016, the total throughput for PGS was approximately 1.9 billion therms. Of this total throughput, 5% was gas purchased and resold to customers by PGS, 82% was third-party supplied gas that was delivered to transportation-only customers and 13% was gas sold off-system (i.e., to customers not connected to PGS’s distribution system). Industrial and power generation customers consumed approximately 57% of PGS’s annual therm volume, commercial customers consumed approximately 26%, off-system sales customers consumed 13% and the remaining balance was consumed by residential customers.

While the residential market represents only a small percentage of total therm volume, approximately 33% of total revenues were from residential customers in 2016.

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 increased interest and development in natural gas vehicles. There are 44 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)

 

2016

 

 

2015

 

 

2014

 

 

2016

 

 

2015

 

 

2014

 

Residential

 

$

139.7

 

 

$

137.0

 

 

$

144.1

 

 

 

77.6

 

 

 

74.9

 

 

 

80.8

 

Commercial

 

 

142.7

 

 

 

138.8

 

 

 

139.1

 

 

 

488.3

 

 

 

470.8

 

 

 

460.5

 

Industrial

 

 

13.6

 

 

 

13.0

 

 

 

13.1

 

 

 

321.0

 

 

 

289.0

 

 

 

274.3

 

Off-system sales

 

 

72.7

 

 

 

49.8

 

 

 

39.4

 

 

 

245.1

 

 

 

166.4

 

 

 

84.0

 

Power generation

 

 

5.3

 

 

 

7.2

 

 

 

6.8

 

 

 

759.5

 

 

 

758.3

 

 

 

643.5

 

Other revenues

 

 

52.8

 

 

 

50.5

 

 

 

48.5

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

426.8

 

 

$

396.3

 

 

$

391.0

 

 

 

1,891.5

 

 

 

1,759.4

 

 

 

1,543.1

 

No significant part of PGS’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 PGS. PGS’s business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.

Regulation

The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC 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 basic 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 reflects an ROE of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.

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 $16.1 million in 2016, accelerate the amortization of the regulatory asset

10


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 new 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 will be amortized over a two-year recovery period beginning in 2016. In 2016, PGS recorded $16 million of this amortization expense.  

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the 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. In November 2016, the FPSC approved PGS’s 2017 PGA cap factor for the period January 2017 through December 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 mentioned above. The conservation charge is intended to permit PGS to recover, on a dollar-for-dollar basis, 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 eligible replacements under the existing cast iron bare steel rider to include certain plastic materials and pipe deemed obsolete by Pipeline Safety and Hazardous Materials 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.

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. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, of the Code of Federal Regulations.

PGS is also 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 distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, 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. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

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. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. 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 affect 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 24,400 transportation-only customers as of December 31, 2016 out of approximately 37,600 eligible customers.

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

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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, although in certain events they are subject to forfeiture.

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 2017 through 2044. PGS expects to negotiate ten franchises in 2017. Franchise fees expense totaled $9.5 million in 2016. Franchise fees are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are recovered on a dollar-from-dollar basis from only those 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.

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 2016 Annual TEC Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

During the year ended December 31, 2016, PGS did not incur any material capital expenditures to meet environmental requirements as none were required, nor are any anticipated for the 2017 through 2021 period.

12


EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, current positions and principal occupations during the last five years of the current executive officers of TEC are described below.

 

 

  

 

  

Current Positions and Principal

Name

  

Age

  

Occupations During The Last Five Years

 

 

 

Gordon L. Gillette

 

56

 

President, TEC, July 2009 to date; and Chief Executive Officer, TEC, September 2016 to date.

 

 

 

Gregory W. Blunden

 

52

 

Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TEC, September 2016  to date; Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, September 2016 to date; Chief Financial Officer, Emera, March 2016 to date; Vice President, Corporate Strategy & Planning, Emera, July 2015 to February 2016; Executive Vice President, Customer, Business & Financial Services, Nova Scotia Power Inc., January 2014 to June 2015; Vice President, Business Development, Emera, April 2012 to December 2013; and Vice President, Business Development, Bangor Hydro Electric Company (now Emera Maine, a subsidiary of Emera), June 2009 to March 2012.

 

 

 

Thomas J. Szelistowski

 

56

 

President, PGS, August 2016 to date; Vice President-Gas Delivery, TEC, January 2016 to August 2016; Managing Director of Regulatory Affairs, TEC, March 2011 to January 2016; and Director of Energy Delivery, Engineering and Operational Services of TEC, February 2010 to March 2011.

 

 

 

There is no family relationship between any of the persons named above or between executive officers and any director of TEC. The term of office of each officer extends until such officer’s successor is elected and qualified.

 

 

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 the existing generating facilities of Tampa Electric 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, economic conditions 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.

13


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 prices 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 earnings and cash flow.

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, called distributed generation, by individual residential, commercial and industrial customers. 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.

Potential changes in solar energy could adversely impact Tampa Electric.

In 2015, there was a proposed constitutional ballot initiative for the 2016 election approved by the Florida Supreme Court to promote increased direct sale and use of solar energy to generate electricity. Not enough signatures were collected for it to qualify for the 2016 ballot.  It may be placed on the 2018 ballot if sufficient signatures are collected. A constitutional amendment was approved on the August 2016 primary election ballot that, subject to legislative action, will allow property exemptions for renewal energy devices used in commercial applications.

TEC anticipates enactment of legislation that would encourage the use of solar energy by retail customers and third parties, and could potentially allow sales of electricity by non-utility generators. Increased use of solar generation and sales by third parties would reduce energy sales and revenues at Tampa Electric. In addition, Tampa Electric could be compelled to make investments in facilities to serve customers who will move to use solar energy when solar energy becomes available to them, so that those investments may not be profitable over the long term.

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.  This rule regulates CCRs as non-hazardous solid waste and required Tampa Electric to begin incurring O&M and capital expenses in 2016 to achieve compliance.   However, these expenses were recoverable under the Florida Environmental Cost Recovery Clause (ECRC), as approved by the Florida Public Service Commission (PSC) on February 2, 2016.  Similarly, future expenses would be eligible for recovery upon petition by Tampa Electric and approval by the PSC.  

14


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 the new regulations will be eligible for favorable 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 accord to the 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, 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 critical information or systems, or otherwise adversely affect its business and financial results and condition.

There have been an increasing number of cyberattacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems inside of the organization.

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 adequacy. Despite these efforts, TEC cannot be assured that a cyberattack will not cause electric or gas system operational problems, property damage, customer information to be stolen, private information to be accessed, disruptions of service to customers, or important data or systems to be compromised. In addition, a cyberattack could subject TEC to additional regulation, litigation or damage to its reputation, which could result in loss of revenues and increased costs, including the costs incurred to repair and restore systems and the implementation of additional security measures.

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. Although not expected in the foreseeable

15


future, 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 margins on 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. If transmission is disrupted, or if capacity is inadequate, TEC’s ability to sell and deliver natural gas and supply natural gas to its customers and its electric generating stations may be hindered.

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

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

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

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

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

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

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

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

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

TEC’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures, vandalism, potentially catastrophic events such as the occurrence of 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 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 recovered in rates. In certain cases, there is potential that such an event may not excuse TEC’s utility companies from servicing customers as required by their respective tariffs.

The franchise rights held by TEC’s utilities could be lost in the event of a breach by such TEC utilities or could expire and not be renewed.

TEC’s utilities 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 TEC utility. In addition, these agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Some agreements also contain provisions allowing municipalities to purchase the portion of the applicable utility’s system located within a given municipality’s boundaries under certain conditions.

16


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, including with the workforce needs associated with major construction projects and ongoing operations. Failure to hire and adequately obtain replacement 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 and may adversely affect TEC’s ability to manage and operate its business. If TEC is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

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

TEC has indebtedness which results in fixed charges 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, 2016, 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. If TEC’s cash flows and capital resources are insufficient to fund its debt service obligations, it may be forced 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 will 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. The terms of existing or future debt instruments may restrict TEC from adopting some of these alternatives.

TEC also incurs obligations that do not appear on its balance sheet, such as leases and letters of credit.

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 2018 and 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. If TEC is not able to issue new debt, or TEC issues debt at interest rates higher than expected, its financial results or condition could be adversely affected.

17


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, 2017 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; however, TEC may make additional cash contributions from time to time. Any future declines in the financial markets or further declines in 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 2017, Tampa Electric is forecasting capital expenditures to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability and to maintain generating unit reliability and efficiency. For 2017, 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 cannot be sure that it will be able to obtain additional financing, in which case its financial position could be adversely affected.

TEC’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade, and TEC cannot be assured of any rating improvements in the future.

The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A3’ and by Fitch at ‘A-’. A downgrade to below investment grade by the rating agencies, which would require a four-notch downgrade by Moody’s and Fitch, 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. TEC may also experience greater interest expense than it would have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any downgrades. In addition, 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.

 

 

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 2016 net winter generating capability of 4,731 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 732 MW from four CTs). On January 16, 2017, the combined cycle unit at the Polk Power Station was placed in service and expanded the plant by approximately 460 MW. See the Tampa Electric – Polk Power Station Units 2-5 Combined Cycle Conversion section of the MD&A for information regarding this project.

Tampa Electric has two solar arrays which went into service in 2015 and 2016 at Tampa International Airport (2 MW capacity) and LEGOLAND Florida (1.8 MW capacity), respectively. Tampa Electric is installing a 23 MW solar array at the Big Bend Power Station, which is expected to be placed in service in February 2017.      

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,621 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 that share poles or trenches. The distribution system consists of approximately 6,260 circuit miles of overhead lines and approximately 5,150 circuit miles of underground lines. As of December 31, 2016, there were 757,100 meters in service. All of this property is located in Florida.

18


All plants and important fixed assets are owned by Tampa Electric 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. It has the power of eminent domain under Florida law for the acquisition of any such ROW for the operation of transmission and distribution lines. 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 19,400 miles of pipe, including approximately 12,400 miles of mains and 7,000 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. While most of the operations and administrative facilities are owned, a small number are leased.

Item 3. LEGAL PROCEEDINGS.

From time to time, TEC is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition, or cash flows.

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Note 9, Commitments and Contingencies, of the 2016 Annual TEC Consolidated Financial Statements.

 

 

 

 

19


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 to maintain TEC’s targeted capital structure. In 2016, 2015 and 2014, TEC paid quarterly dividends on its common stock substantially equal to its net income (see the Consolidated Statements of Cash Flows in the 2016 Annual TEC Consolidated Financial Statements).

 

Item 6. SELECTED FINANCIAL DATA OF TAMPA ELECTRIC COMPANY

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

Revenues

 

$

2,395.8

 

 

$

2,419.2

 

 

$

2,419.0

 

 

$

2,342.8

 

 

$

2,378.0

 

Net income

 

 

285.7

 

 

 

276.3

 

 

 

260.3

 

 

 

225.6

 

 

 

227.2

 

Total assets (1)

 

 

8,082.6

 

 

 

7,708.6

 

 

 

7,257.5

 

 

 

6,861.0

 

 

 

6,728.5

 

Long-term debt, including current portion (1)

 

 

2,162.9

 

 

 

2,245.0

 

 

 

2,080.3

 

 

 

1,866.0

 

 

 

1,916.5

 

Dividends paid (2)

 

288.2

 

 

268.4

 

 

262.6

 

 

222.1

 

 

228.3

 

(1)

Amounts shown include reclassifications to reflect the accounting pronouncement adopted in 2016 related to debt issuance costs as discussed in Note 2 to the 2016 Annual TEC Consolidated Financial Statements.

(2)

All of TEC’s common stock is owned by TECO Energy as discussed in Item 5.

 

 

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 736,000 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 4,731 MW at December 31, 2016. PGS, Florida’s largest gas distribution utility, served approximately 374,000 residential, commercial, industrial and electric power generating customers at December 31, 2016 in all major metropolitan areas of the state, with a total natural gas throughput of approximately 1.9 billion therms in 2016.

 

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. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. See Notes 8 and 10 to the 2016 Annual TEC Consolidated Financial Statements for further information regarding the Merger and related party transactions between TEC and its affiliates, respectively.

20


2016 PERFORMANCE

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

In 2016, our net income was $285.7 million, compared with $276.3 million in 2015. The most significant factors impacting the year-over-year-comparison of net income were higher base revenues driven by customer growth and a strong economy, higher AFUDC due to the construction of the Polk conversion project, and lower taxes primarily due to tax benefits related to AFUDC-equity and federal R&D tax credits, partially offset by higher O&M expense and depreciation expense.

OUTLOOK

Our 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.

 

Tampa Electric and PGS anticipate earning within their allowed ROE ranges in 2017 and expect rate base and earnings to be higher than in prior years. Tampa Electric and PGS expect slightly higher customer growth rates in 2017 than those experienced in 2016, reflective of the economic growth in Florida. Assuming normal weather, sales are expected to increase primarily due to customer growth. Under a 2013 settlement agreement with the FPSC, Tampa Electric’s base rates increased by $110 million effective January 2017. This base rate increase will be more than offset in customer rates by a reduction in fuel expense in 2017. Depreciation expense is expected to increase in 2017 as the Polk unit was placed in service and from continued capital investments in facilities to reliably serve customers. In February 2017, the FPSC approved a settlement agreement filed by PGS and OPC, which resulted in a $16 million annual reduction to PGS’s depreciation expense beginning in 2016, which was offset by the acceleration of amortization of the regulatory asset associated with MGP environmental remediation costs. The MGP amortization from 2016 through 2020 will be at least $32 million, which includes $16 million recorded in 2016. Absent any base rate case filing, through 2020 PGS’s bottom of the allowed ROE range will be decreased 50 basis points to 9.25% and the top of the range will continue to be 11.75%. In addition, the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. No change in customer rates resulted from this order. See Note 3 to the 2016 Annual TEC Consolidated Financial Statements for further information on the settlement agreement.

In 2017, we expect to invest approximately $550 million in capital projects compared to $727 million in 2016. This reduction is a result of the Polk Power Station being completed in January 2017. These include capital expenditures to support normal system reliability and growth at Tampa Electric and PGS; the programs for Tampa Electric transmission and distribution system storm hardening and transmission system reliability requirements; utility scale solar photo voltaic projects at Tampa Electric; and incremental investments above normal maintenance capital to expand the PGS system.

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).  

 

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, 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 2016 Annual TEC Consolidated Financial Statements).  

(millions)

 

 

 

2016

 

 

2015

 

 

2014

 

Segment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tampa Electric

 

$

1,964.5

 

 

$

2,018.3

 

 

$

2,021.0

 

 

 

PGS

 

 

439.3

 

 

 

407.5

 

 

399.6

 

 

 

Eliminations

 

 

(8.0

)

 

 

(6.6

)

 

 

(1.6

)

 

 

 

 

$

2,395.8

 

 

$

2,419.2

 

 

$

2,419.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tampa Electric

 

$

250.8

 

 

$

241.0

 

 

$

224.5

 

 

 

PGS

 

 

34.9

 

 

 

35.3

 

 

35.8

 

 

 

 

 

$

285.7

 

 

$

276.3

 

 

$

260.3

 

21


TAMPA ELECTRIC

Electric Operations Results

Net income in 2016 was $250.8 million, compared with $241.0 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 $24.1 million of AFUDC-equity, $6.5 million of federal R&D tax credits and other tax deductions including Section 199 deduction, compared with $17.2 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.

Net income in 2015 was $241.0 million, compared with $224.5 million in 2014, driven by higher revenues resulting from a 1.8% increase in average number of customers and higher energy sales resulting from customer growth, warmer than normal spring and early winter weather and a stronger economy. Higher operations and maintenance, depreciation and interest expenses partially offset the higher revenues. Full-year net income in 2015 included $17.2 million of AFUDC-equity, compared with $10.5 million in 2014. See the Operating Revenues and Operating Expenses sections below for additional information.

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

Summary of Operating Results

 

(millions, except customers and total degree days)

 

2016

 

 

% Change

 

 

2015

 

 

% Change

 

 

2014

 

Revenues

 

$

1,964.5

 

 

 

(2.7

)

 

$

2,018.3

 

 

 

(0.1

)

 

$

2,021.0

 

O&M expense

 

 

424.0

 

 

 

0.8

 

 

 

420.6

 

 

 

0.5

 

 

 

418.4

 

Depreciation and amortization expense

 

 

268.4

 

 

 

4.6

 

 

 

256.7

 

 

 

3.3

 

 

 

248.6

 

Taxes, other than income

 

 

156.6

 

 

 

0.1

 

 

 

156.4

 

 

 

1.1

 

 

 

154.7

 

Non-fuel operating expenses

 

 

849.0

 

 

 

1.8

 

 

 

833.7

 

 

 

1.4

 

 

 

821.7

 

Fuel expense

 

 

568.3

 

 

 

(11.8

)

 

 

644.4

 

 

 

(6.9

)

 

 

692.5

 

Purchased power expense

 

 

104.1

 

 

 

31.9

 

 

 

78.9

 

 

 

10.5

 

 

 

71.4

 

Total fuel & purchased power expense

 

 

672.4

 

 

 

(7.0

)

 

 

723.3

 

 

 

(5.3

)

 

 

763.9

 

Total operating expenses

 

 

1,521.4

 

 

 

(2.3

)

 

 

1,557.0

 

 

 

(1.8

)

 

 

1,585.6

 

Operating income

 

$

443.1

 

 

 

(3.9

)

 

$

461.3

 

 

 

5.9

 

 

$

435.4

 

AFUDC-equity

 

$

24.1

 

 

 

40.1

 

 

$

17.2

 

 

 

63.8

 

 

$

10.5

 

Provision for income taxes

 

$

129.8

 

 

 

(9.6

)

 

$

143.6

 

 

 

7.8

 

 

$

133.2

 

Net income

 

$

250.8

 

 

 

4.1

 

 

$

241.0

 

 

 

7.3

 

 

$

224.5

 

Megawatt-Hour Sales (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 

9,188

 

 

 

1.6

 

 

 

9,045

 

 

 

4.5

 

 

 

8,656

 

Commercial

 

 

6,310

 

 

 

0.1

 

 

 

6,301

 

 

 

2.6

 

 

 

6,142

 

Industrial

 

 

1,928

 

 

 

3.1

 

 

 

1,870

 

 

 

(1.6

)

 

 

1,901

 

Other

 

 

1,808

 

 

 

0.9

 

 

 

1,791

 

 

 

(2.0

)

 

 

1,827

 

Total retail

 

 

19,234

 

 

 

1.2

 

 

 

19,007

 

 

 

2.6

 

 

 

18,526

 

Sales for resale

 

 

206

 

 

 

79.1

 

 

 

115

 

 

 

(55.5

)

 

 

259

 

Total energy sold

 

 

19,440

 

 

 

1.7

 

 

 

19,122

 

 

 

1.8

 

 

 

18,785

 

Retail customers—(thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31

 

 

736.0

 

 

 

1.7

 

 

 

723.6

 

 

 

1.8

 

 

 

710.9

 

Retail net energy for load

 

 

20,165

 

 

 

0.3

 

 

 

20,103

 

 

 

4.1

 

 

 

19,315

 

Total degree days

 

 

4,462

 

 

 

(5.6

)

 

 

4,729

 

 

 

17.1

 

 

 

4,038

 

Operating Revenues

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. Pretax base revenue was $11.7 million higher than in 2015, including approximately $5 million of higher pretax base revenue due to the base rate increase effective November 1, 2015, as a result of the 2013 rate case settlement. Pretax base revenues exclude revenues that recover costs from customers through clauses and riders. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, increased 0.3% in 2016 compared to 2015. Energy sales were higher compared to 2015 due to customer growth. In 2016, total degree days in Tampa Electric's service area were 7% above normal and 6% below 2015 levels.

22


In 2016, retail energy sales to residential and commercial customers increased primarily due to customer growth.  Sales to non-phosphate industrial customers increased due to the strength of the Tampa area economy. Sales to lower-margin industrial-phosphate customers increased as a result of increased mining operations plus the decrease of self-generation.  

In 2015, retail MWh sales, measured on a billing cycle basis as shown in the table above grew 2.6% from 2014 levels.  Sales in 2015 reflected warmer than normal second and fourth quarter weather, strong customer growth and a stronger local economy.  Pretax base revenue was more than $37 million higher than in 2014, including approximately $8 million of higher pretax base revenue due to the base rate increases effective November 1, 2014 and November 1, 2015, as a result of the 2013 rate case settlement. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, was 4.1% higher than in 2014. Higher energy sales were driven by more favorable weather in 2015 than in 2014. In 2015, total degree days in Tampa Electric's service area were 12% above normal and 17% above 2014.

Tampa Electric is not a major participant in the wholesale market because it uses its own generation to serve its retail customers rather than selling into the wholesale market. In 2016, gross revenues from wholesale sales, which includes fuel that is a pass-through cost, was less than 1% of total revenues.  Sales for resale increased 79.1% in 2016 due to warmer than normal temperatures in the third quarter which drove additional power sales. Sales for resale decreased 55.5% in 2015 due to the availability of low-cost natural gas fired generation in the state mitigating the need for Tampa Electric’s generating resources.  

Customer and Energy Sales Growth Outlook

The Florida economy has continued to grow, as evidenced by success in local economic development activities, by job growth, and by improvements in the new housing construction market, which has been a major driver of growth in the Florida economy for many years (see the Risk Factors section). In 2016, there was an almost 20% increase in new single family home building permits in Tampa Electric’s service area and an increase of more than 60% in multifamily building permits compared to 2015. In general, economists are forecasting a continued improvement in the state and local economies in 2017 and beyond. For the past several years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, smaller single-family houses and increased multi-family housing. In 2017, weather-normalized retail energy sales to residential, commercial and non-phosphate industrial customers are expected to grow at a rate of approximately 1.5%.

Longer-term, assuming continued economic growth and business expansion, Tampa Electric expects annual customer growth to average 1.6% and weather-normalized average retail energy sales growth at a rate of approximately 1.3% to 1.5% in the near term, and about 1.5% over the longer-term. This energy sales growth projection reflects increased lighting and appliance efficiency, increased percentage of multi-family homes, changes in usage patterns and changes in population trends. These growth projections assume continued local area economic growth, normal weather, and a continuation of the current energy market structure.

The economy in Tampa Electric’s service area continued to grow in 2016. The Tampa metropolitan area added over 38,000 new jobs in 2016. Job growth was concentrated in business and other services. The total nonfarm employment in the Tampa metropolitan area increased 3.1% in 2016 following a 3.4% increase in 2015. The local Tampa area unemployment rate decreased to 4.6% in 2016 compared with 5.1% in 2015 and 6.0% in 2014. The Tampa area 2016 unemployment rate was below the state of Florida’s unemployment rate of 4.8% and the national unemployment rate of 4.9%.

Tampa Electric anticipates earnings within the allowed ROE range in 2017 and expects earnings and rate base growth as a result of continued customer growth and a focus on cost control.

Operating Expenses

Total pretax 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, increased $9.2 million in 2016, reflecting higher costs to safely and reliably serve customers.

Total pretax operating expense was 1.8% lower in 2015 compared to 2014, driven primarily by lower fuel expense partially offset by higher O&M expense. O&M expenses, excluding all FPSC-approved cost-recovery clauses, increased $5.4 million in 2015, reflecting higher costs to safely and reliably serve customers partially offset by lower employee-related expenses.

In 2016 and 2015, depreciation and amortization expense increased $7.2 million and $5.0 million, respectively, reflecting additions to facilities to serve customers. In 2017, depreciation expense is expected to increase due to normal plant additions and the addition of Polk 2-5 combined cycle coming into service in January 2017.

Excluding all FPSC-approved cost-recovery clause-related expense, O&M expense in 2017 is expected to be lower than in 2016 due to fewer planned outages in 2017.  

23


Fuel Prices and Fuel Cost Recovery

In November 2016, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2017. The rates include the expected cost for natural gas and coal in 2017, and the net over-recovery of fuel, purchased power and capacity clause expense.

Total fuel cost decreased in 2016, due to increased lower-cost natural gas-fired generation and lower costs for natural gas. Purchased-power expense increased in 2016 due to higher volumes of energy purchased from others. Delivered natural gas prices decreased 12.7% in 2016 due to abundant supplies of natural gas from on-shore domestic natural gas produced from shale formations, and storage inventories above historic averages. Delivered coal costs increased 4.9% in 2016. The average coal and natural gas costs were $3.61/MMBTU and $3.79/MMBTU, respectively, in 2016, compared with $3.44/MMBTU and $4.34/MMBTU, respectively, in 2015.

 

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 be in the $3.50 to $4.00/MMBTU range in 2017, and between $2.75 and $4.00 in 2018, both of which are higher than the 2016 NYMEX natural gas price of $2.46. Current natural gas prices reflect reduced natural gas drilling, offset by high storage levels due to a mild start to the winter heating season and low-cost production from shale basins in the U.S.  Compared to 2016, delivered coal prices are expected to decrease slightly in 2017. Tampa Electric continues to burn primarily Illinois Basin coal with small amounts of Northern Appalachian coal, petroleum coke, and South American coal.  The price for coal commodity in 2017 is expected to be relatively similar to 2016, but lower transportation costs will provide a slightly lower delivered cost.

Solar Initiatives

In 2015, Tampa Electric announced plans for a 23-MW utility-scale solar photo voltaic project to be installed 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. Upon completion, which is expected to occur in February 2017, it will have the capacity to power more than 3,500 homes.  In 2015, Tampa Electric completed the construction of a 2-MW solar photo voltaic energy installation at Tampa International Airport, which is Tampa Electric’s first large-scale solar facility.  In 2016, Tampa Electric completed the construction of a 1.8-MW solar photo voltaic energy installation at LEGOLAND Florida. Tampa Electric owns the solar photo voltaic arrays, and the electricity they produce goes to the grid to benefit all Tampa Electric customers, including the airport and LEGOLAND.  Tampa Electric anticipates developing additional similarly sized small-scale solar photo voltaic installations and is seeking opportunities for additional utility-scale installations.

Tampa Electric has installed 2,135 KW of solar panels to generate electricity at eight community sites including two schools, Tampa Electric’s Manatee Viewing Center, the Museum of Science and Industry, Tampa’s Lowry Park Zoo, the Florida Aquarium, and LEGOLAND Florida.

In Florida, a constitutional amendment was proposed that would allow the sale of up to 2 MW of power direct to other customers from rooftop solar panels, potentially bypassing any utility. The Florida Supreme Court ruled that the amendment met constitutional and statutory requirements to appear on the ballot; however, supporters were unable to gather and certify the required number of signatures by the deadline to have it placed on the ballot in 2016.  Supporters of the amendment have indicated that they plan to try to have the amendment placed on the ballot in 2018. Legislation was proposed for consideration in the 2016 Florida legislative session that essentially mirrored the intent of the constitutional amendment, but it did not pass. A second Florida constitutional amendment regarding solar power, known as Amendment 1, was on the 2016 ballot but it was not passed by the voters.

Polk Power Station Units 2 – 5 Combined Cycle Conversion

On January 16, 2017, the combined cycle unit at the Polk Power Station was placed in service and available to meet winter demand needs of its customers. The 2016 capital expenditures for the conversion of the Polk CTs to combined cycle and the related transmission system improvements to support the additional generating capacity are included in the Capital Investments section below. Under a 2013 settlement agreement with the FPSC, Tampa Electric’s base rates increased by $110 million pre-tax effective January 16, 2017, when the Polk 2 – 5 conversion entered commercial service.

PGS

Operating Results

In 2016, PGS reported net income of $34.9 million, compared with $35.3 million in 2015. Results reflect higher residential sales volumes driven by 2.5% higher average number of customers and higher commercial sales volumes driven by a strong economy. Off-system sales increased due to weather related power demand, coal to gas switching by power generators, and pipeline transportation

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constraints in some areas of the state. Excluding all FPSC-approved cost-recovery clauses, O&M expense was $3.6 million higher in 2016 than in 2015, driven by higher operating and employee benefit costs. Depreciation and amortization expense increased $1.9 million, which includes a $16 million pretax decrease in depreciation offset by a $16 million pretax increase in amortization of the regulatory asset associated with environmental remediation costs per the settlement agreement approved by the FPSC.

In 2015, PGS reported net income of $35.3 million, compared with $35.8 million in 2014. Results reflect a 2.1% higher average number of customers and lower therm sales to residential customers due to mild winter weather. Higher commercial sales volumes were driven by a strong economy and an almost 30% increase in therms sold to CNG vehicle fleets. Sales to power generation customers increased due to higher state-wide electricity demand due to warmer than normal second and fourth quarter weather. Off-system sales increased due to weather related power demand, coal to gas switching by power generators, and pipeline transportation constraints in some areas of the state. Non-fuel O&M expense was $1.9 million higher in 2015 than in 2014, driven by higher operating costs, partially offset by lower employee-related costs, primarily due to the level of short-term incentive accruals for all employees in 2015 compared to 2014. O&M expense in 2014 reflected a first-quarter recovery of $1.6 million of costs incurred in connection with a 2010 outage incident. Depreciation and amortization expense increased slightly due to normal additions to facilities to serve customers.

In 2016 and 2015, total throughput for PGS was approximately 1.9 billion therms and 1.8 billion therms, respectively. The increase is due primarily to off-system sales. In 2016, total throughput increased 7.5% from 2015 levels due to the higher volumes transported for industrial customers and higher off-system sales. In 2016, industrial and power generation customers represented approximately 57% of annual therm volume, commercial customers used approximately 26%, approximately 13% was sold off-system, and the remainder was consumed by residential customers.

Residential customers comprised approximately 33% of total revenues in 2016, down from 35% of total revenues in 2015 due to the mix of higher commercial, industrial, and off -system sales revenue in 2016. New residential construction, which includes natural gas and conversions of existing residences to natural gas, increased in 2016 and 2015 as the economy and the housing market in select markets in Florida rebounded.

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 experienced increased interest in the usage of CNG as an alternative fuel for vehicles. Therms sold to CNG stations increased approximately 30% in 2016 and 2015, respectively, to 25.6 million therms and 19.8 million therms in 2016 and 2015, respectively.  Currently, there are 44 CNG fueling stations connected to the PGS system serving over 1,450 vehicles of various sizes. In 2017, the number of vehicles already converted or committed to conversion are expected to consume almost 26 million therms annually, the equivalent consumption of more than 109,000 typical Florida residential customers. Additional stations are expected to be added in 2017, driven by attractive economics, even in the current low-oil price environment, and by lower emissions profile of CNG vehicles. In 2016, PGS placed three company owned CNG filling stations in service, and the cost of these stations will be recovered over time through a special rate approved by the FPSC.  CNG conversions add therm sales, at lower-margin transportation rates, to the gas system without requiring significant capital investment by PGS.

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

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

Summary of Operating Results

 

(millions, except customers)

 

2016

 

 

% Change

 

 

2015

 

 

% Change

 

 

2014

 

Revenues

 

$

439.3

 

 

 

7.8

 

 

$

407.5

 

 

 

2.0

 

 

$

399.6

 

Cost of gas sold

 

 

158.7

 

 

 

16.9

 

 

 

135.8

 

 

 

(0.9

)

 

 

137.0

 

Operating expenses

 

 

211.2

 

 

 

5.0

 

 

 

201.1

 

 

5.6

 

 

 

190.5

 

Operating income

 

$

69.4

 

 

 

(1.7

)

 

$

70.6

 

 

 

(2.1

)

 

$

72.1

 

Net income

 

$

34.9

 

 

 

(1.1

)

 

$

35.3

 

 

 

(1.4

)

 

$

35.8

 

Therms sold – by customer segment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 

77.6

 

 

 

3.6

 

 

 

74.9

 

 

 

(7.3

)

 

 

80.8

 

Commercial

 

 

488.3

 

 

 

3.7

 

 

 

470.8

 

 

 

2.2

 

 

 

460.5

 

Industrial

 

 

321.0

 

 

 

11.1

 

 

 

289.0

 

 

 

5.4

 

 

 

274.3

 

Off-system sales

 

 

245.1

 

 

 

47.3

 

 

 

166.4

 

 

 

98.1

 

 

 

84.0

 

Power generation

 

 

759.5

 

 

 

0.2

 

 

 

758.3

 

 

 

17.8

 

 

 

643.5

 

Total

 

 

1,891.5

 

 

 

7.5

 

 

 

1,759.4

 

 

 

14.0

 

 

 

1,543.1

 

Therms sold – by sales type

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

System supply

 

 

347.0

 

 

 

29.1

 

 

 

268.7

 

 

 

38.3

 

 

 

194.2

 

Transportation

 

 

1,544.5

 

 

 

3.6

 

 

 

1,490.7

 

 

 

10.5

 

 

 

1,348.9

 

Total

 

 

1,891.5

 

 

 

7.5

 

 

 

1,759.4

 

 

 

14.0

 

 

 

1,543.1

 

Customer (thousands) – at December 31

 

 

374.1

 

 

 

2.6

 

 

 

364.7

 

 

 

2.1

 

 

 

357.2

 

In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. 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 impact to PGS when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to customers through its “NaturalChoice” program. At year-end 2016, approximately 64% of the 37,640 of PGS’s eligible non-residential customers had elected to take service under this program.

PGS Outlook

In 2017, PGS expects customer growth at rates in line with those experienced in 2016, reflecting its expectations that the housing markets in many areas of the state that it serves will continue to grow. Assuming normal weather, therm sales to weather-sensitive customers, especially residential customers, are expected to increase in 2017 at rates that are in line with customer growth. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense in 2017 is expected to be slightly higher than in 2016, with higher costs to operate and maintain the system and to reliably serve customers as well as technology related costs. Depreciation and amortization expense is expected to be lower due to the recently approved depreciation rates and associated environmental amortization (see Note 3 to the 2016 Annual TEC Consolidated Financial Statements).

PGS has expanded its gas distribution system into areas of Florida not previously served by natural gas, such as the lower southwest coast in the Fort Myers and Naples areas and the northeast coast in the Jacksonville area. In 2017, PGS expects capital spending to increase to support residential and commercial customer growth, system expansion to serve large commercial and industrial customers, liquefied natural gas opportunities, continued interest in conversion of vehicle fleets to CNG and replacement of cast iron, bare steel pipe and other pipe deemed obsolete by the Pipeline Safety and Hazardous Materials Administration.

The current rate of new residential development in Florida has recovered significantly since the economic recession. Complementing the renewed residential construction is the PGS business model for system expansion to focus on extending the system to serve large commercial or industrial customers that are currently using petroleum or propane as fuel. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future, and the lower emissions levels from using natural gas compared to other fuels, make it attractive for these customers to convert from other fuels even in the current low oil-price environment.

PGS anticipates earnings within the allowed ROE range in 2017 and expects earnings and rate base growth as a result of continued customer growth.

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OTHER ITEMS IMPACTING NET INCOME

Other Income, Net

Other income, net was $31.2 million, $19.6 million and $15.3 million in 2016, 2015 and 2014, respectively, and included AFUDC-equity and other items and services such as lightning surge protection equipment. AFUDC-equity at Tampa Electric was $24.1 million, $17.2 million, and $10.5 million in 2016, 2015 and 2014, respectively. The increase in AFUDC-equity is due to the Polk conversion project (see the Polk Power Station Units 2 – 5 Combined Cycle Conversion section above). AFUDC is expected to decrease in 2017 primarily due to the Polk conversion project 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 2016, interest expense, excluding AFUDC-debt, was $117.3 million compared to $117.9 million in 2015 and $111.7 million in 2014. In 2016, interest expense was similar to 2015 due to no new debt issuances at TEC and similar short-term borrowing levels related to its capital spending program. Interest expense in 2015 increased compared to 2014 due to additional borrowings to support its capital spending program.

Interest expense is expected to increase in 2017, reflecting lower AFUDC-debt and higher short-term interest rates and balances.

Income Taxes

The provision for income taxes decreased in 2016, primarily due to tax benefits related to AFUDC-equity and federal R&D tax credits.  Income tax expense as a percentage of income before taxes was 34.8% in 2016, 37.5% in 2015 and 37.5% in 2014. We expect our 2017 annual effective tax rate to be approximately 38.6%. The expected increase is due to the tax benefits in 2016 which are not expected in 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 $(3.0) million, $63.7 million and $52.6 million in 2016, 2015 and 2014, respectively. See Cash from Operating Activities below for further information regarding the cash payments.

For more information on our income taxes, including a reconciliation between the statutory federal income tax rate and the effective tax rate, see Note 4 to the 2016 Annual TEC Consolidated Financial Statements.

 

LIQUIDITY, CAPITAL RESOURCES

Balances as of December 31, 2016  

 

 

 

 

 

 

(millions)

 

 

 

 

Credit facilities

 

$

475.0

 

Drawn amounts/LCs

 

 

170.5

 

Available credit facilities

 

 

304.5

 

Cash and short-term investments

 

 

9.5

 

Total liquidity

 

$

314.0

 

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Cash from Operating Activities

Cash flows from operating activities in 2016 increased compared to 2015. The change is primarily due to higher accounts payable as a result of higher fuel accruals and higher costs to safely and reliably operate the system; lower fuel inventory balances due to higher fuel consumption; lower customer accounts receivable balances due to lower revenue in the fourth quarter of 2016; and a higher deferred recovery clause balance due to over-recovery in 2016 as fuel prices were lower than projected. In addition, TEC received $61 million in tax refunds from TECO Energy in 2016, and TEC’s tax payments decreased due to the impact of the extension of bonus depreciation in December 2015. Cash from operations in 2016 and 2015 also reflect pension contributions of $31 million and $44 million, respectively.

Cash from Investing Activities

Our investing activities in 2016 resulted in a net use of cash of $718 million, which primarily reflects capital expenditures. We expect capital spending in 2017 to be approximately $550 million. The expected decrease compared to 2016 is due to the completion in January 2017 of the Polk Power Station Units 2 – 5 combined cycle conversion and the Customer Relationship Management and Billing System implementation. See the Capital Investments section for additional information.

Cash from Financing Activities

Our financing activities in 2016 resulted in net cash outflows of $113 million. TEC repaid $83 million of maturing long-term debt and paid $288 million of dividends to TECO Energy, which was partially offset by $150 million of equity contributions from TECO Energy and a net increase in borrowings from credit facilities of $109 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 temporary 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 2017 as we invest in our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to fund those capital expenditures with available cash on hand, cash generated from operating activities, and equity contributions and debt issuances so that we maintain our capital structures consistent with our existing regulatory arrangements.

The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2016. The working capital deficit as of December 31, 2016 was primarily the result of increases in short-term liabilities due 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, 2016, our liquidity was $314 million.  

TEC has multiyear credit facilities that cumulatively provide $475 million of credit through 2018. See Note 6 to the 2016 Annual TEC Consolidated Financial Statements for additional information regarding the credit facilities. TEC believes that its liquidity is adequate given its expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect its ability to execute its expected operating, capital, or financing plans.

We expect cash from operations in 2017 to be lower than in 2016, due in large part to prior year fuel clause over-recoveries included in the 2017 fuel rate. We plan to use cash in 2017 to fund capital spending estimated at $550 million, and to pay dividends to our shareholder, TECO Energy. Dividends are declared and paid at the discretion of TEC’s Board of Directors.

We expect to utilize cash from operations and equity contributions from TECO Energy to support our capital spending programs, supplemented with incremental long-term debt and utilization of our credit facilities to maintain strong utility capital structures. 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 2017 and remain within the covenant restrictions.

Our expected cash flow could be affected by variables discussed in the individual operating company sections, such as customer growth, weather and usage changes at our regulated businesses. In addition, actual fuel and other regulatory clause net recoveries will typically vary from those forecasted; however, the differences are generally recovered within the next calendar year. It is possible, however, that unforeseen cash requirements and/or shortfalls, or higher capital spending requirements, could cause us to fall short of our liquidity target (see the Risk Factors section).

TEC currently holds investment grade credit ratings from Moody’s, S&P and Fitch (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

28


instruments were triggered as of December 31, 2016, 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.

Short-Term Borrowings

At December 31, 2016 and 2015, the following credit facilities and related borrowings existed.

 

 

 

December 31, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

Letters of

 

 

 

 

 

 

 

 

 

 

Letters of

 

 

 

Credit

 

 

Borrowings

 

 

Credit

 

 

Credit

 

 

Borrowings

 

 

Credit

 

(millions)

 

Facilities

 

 

Outstanding(1)

 

 

Outstanding