10-K 1 te-10k_20141231.htm 10-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

x

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

For the fiscal year ended December 31, 2014

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

1-8180

  

TECO ENERGY, INC.

  

59-2052286

 

  

(a Florida corporation)

  

 

 

  

TECO Plaza

  

 

 

  

702 N. Franklin Street

  

 

 

  

Tampa, Florida 33602

  

 

 

  

(813) 228-1111

  

 

 

 

 

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:

 

Title of each class

 

Name of each exchange on which registered

TECO Energy, Inc.

 

 

Common Stock, $1.00 par value

 

New York Stock Exchange

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

Indicate by check mark if TECO Energy, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES  x    NO  ¨

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  x

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

YES  ¨    NO  x

Indicate by check mark whether the registrants (1) have 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) have been subject to such filing requirements for the past 90 days.

YES  x    NO  ¨


Indicate by check mark whether the registrants have submitted electronically and posted on their 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 registrants were required to submit and post such files).

YES  x    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 registrants’ 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.  x

Indicate by check mark whether TECO Energy, Inc. 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

 

x

  

Accelerated filer

 

¨

 

 

 

 

Non-accelerated filer

 

¨

  

Smaller reporting company

 

¨

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

 

x

  

Smaller reporting company

 

¨

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Act).

YES  ¨    NO  x

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

YES  ¨    NO  x

The aggregate market value of TECO Energy, Inc.’s common stock held by non-affiliates of the registrant as of June 30, 2014 was approximately $3.97 billion based on the closing sale price as reported on the New York Stock Exchange.

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of June 30, 2014 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Feb. 13, 2015 was 235,528,791. As of Feb. 13, 2015, 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.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement relating to the 2015 Annual Meeting of Shareholders of TECO Energy, Inc. are incorporated by reference into Part III.

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

This combined Form 10-K represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Tampa Electric Company makes no representations as to the information relating to TECO Energy, Inc.’s other operations.

 

 

 

 

 


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 receipt

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

BTU

 

British Thermal Unit

CAA

 

Federal Clean Air Act

CAIR

 

Clean Air Interstate Rule

capacity clause

 

capacity cost-recovery clause, as established by the FPSC

CCRs

 

coal combustion residuals

CES

 

Continental Energy Systems

CGESJ

 

Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala

CMO

 

collateralized mortgage obligation

CNG

 

compressed natural gas

company

 

TECO Energy, Inc.

CPI

 

consumer price index

CSAPR

 

Cross State Air Pollution Rule

CO2

 

carbon dioxide

CT

 

combustion turbine

DR-CAFTA

 

Dominican Republic Central America – United States Free Trade Agreement

ECRC

 

environmental cost recovery clause

EEGSA

 

Empresa Eléctrica de Guatemala, S.A.

EEI

 

Edison Electric Institute

EGWP

 

Employee Group Waiver Plan

EPA

 

U.S. Environmental Protection Agency

EPS

 

earnings per share

ERISA

 

Employee Retirement Income Security Act

EROA

 

expected return on plan assets

ERP

 

enterprise resource planning

FASB

 

Financial Accounting Standards Board

FDEP

 

Florida Department of Environmental Protection

FERC

 

Federal Energy Regulatory Commission

FGT

 

Florida Gas Transmission Company

FPSC

 

Florida Public Service Commission

fuel clause

 

fuel and purchased power cost-recovery clause, as established by the FPSC

GAAP

 

generally accepted accounting principles

GCBF

 

gas cost billing factor

GHG

 

greenhouse gas(es)

HAFTA

 

Highway and Transportation Funding Act

HCIDA

 

Hillsborough County Industrial Development Authority

HPP

 

Hardee Power Partners

IASB

 

International Accounting Standards Board

ICSID

 

International Centre for the Settlement of Investment Disputes

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)

KWH

 

kilowatt-hour(s)

LIBOR

 

London Interbank Offered Rate

3


Term

 

Meaning

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

Met

 

metallurgical

MMA

 

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

MMBTU

 

one million British Thermal Units

MRV

 

market-related value

MSHA

 

Mine Safety and Health Administration

MW

 

megawatt(s)

MWH

 

megawatt-hour(s)

NAESB

 

North American Energy Standards Board

NAV

 

net asset value

NMGC

 

New Mexico Gas Company, Inc.

NMGI

 

New Mexico Gas Intermediate, Inc.

NMPRC

 

New Mexico Public Regulation Commission

NOL

 

net operating loss

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

OPEB

 

other postretirement benefits

OTC

 

over-the-counter

PBGC

 

Pension Benefit Guarantee Corporation

PBO

 

postretirement benefit obligation

PCI

 

pulverized coal injection

PCIDA

 

Polk County Industrial Development Authority

PGA

 

purchased gas adjustment

PGAC

 

purchased gas adjustment clause

PGS

 

Peoples Gas System, the gas division of Tampa Electric Company

PM

 

particulate matter

PPA

 

power purchase agreement

PPSA

 

Power Plant Siting Act

PRP

 

potentially responsible party

PUHCA 2005

 

Public Utility Holding Company Act of 2005

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

RPS

ROW

 

renewable portfolio standards

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

SPA

 

stock purchase agreement

STIF

 

short-term investment fund

Tampa Electric

 

Tampa Electric, the electric division of Tampa Electric Company

TCAE

 

Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station

TEC

 

Tampa Electric Company, the principal subsidiary of TECO Energy, Inc.

TECO Coal

 

TECO Coal LLC, and its subsidiaries, a coal producing subsidiary of TECO Diversified

TECO Diversified

 

TECO Diversified, Inc., a subsidiary of TECO Energy, Inc. and parent of TECO Coal Corporation

TECO Energy

 

TECO Energy, Inc.

TECO Finance

 

TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.

TECO Guatemala

 

TECO Guatemala, Inc., a subsidiary of TECO Energy, Inc., parent company of formerly owned generating and transmission assets in Guatemala.

TGH

 

TECO Guatemala Holdings, LLC

4


Term

 

Meaning

TRC

 

TEC Receivables Company

USACE

 

U.S. Army Corps of Engineers

VIE

 

variable interest entity

WRERA

 

The Worker, Retiree and Employer Recovery Act of 2008

 

 

 

5


PART I

 

 

Item 1. BUSINESS.

TECO ENERGY

TECO Energy, Inc. was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company. TECO Energy and its subsidiaries had approximately 4,400 employees as of Dec. 31, 2014.

TECO Energy’s Corporate Governance Guidelines, the charter of each committee of the Board of Directors, and the code of ethics applicable to all directors, officers and employees, the Code of Ethics and Business Conduct, are available on the Investors section of TECO Energy’s website, www.tecoenergy.com, or in print free of charge to any investor who requests the information. TECO Energy also makes its SEC (www.sec.gov) filings available free of charge on the Investors section of TECO Energy’s website 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 the company 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.

TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiaries, NMGI and TECO Diversified, owns NMGC and TECO Coal, respectively.

Unless otherwise indicated by the context, “TECO Energy” or the “company” means the holding company, TECO Energy, Inc. and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries. TECO Energy’s business segments and revenues for those segments, for the years indicated, are identified below.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provides retail electric service to more than 706,000 customers in West Central Florida with a net winter system generating capacity of 4,668 MW. PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With almost 354,000 customers, PGS has operations in Florida’s major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2014 was almost 1.5 billion therms.

NMGC, a Delaware corporation and wholly owned subsidiary of NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico. With approximately 513,000 customers, NMGC serves approximately 60% of the state’s population in 23 of New Mexico’s 33 counties. NMGC’s largest concentration of customers (approximately 357,000) is in the region known as the Central Rio Grande Corridor, which includes the communities of Albuquerque, Belen, Rio Rancho and Santa Fe. NMGC’s results are included as of the acquisition date (see Note 21 to the TECO Energy Consolidated Financial Statements for additional information).

TECO Coal, a Kentucky LLC and wholly owned subsidiary of TECO Diversified, has 10 subsidiaries located in Eastern Kentucky, Tennessee and Virginia. These entities own mineral rights, own or operate surface and underground mines and own interests in coal processing and loading facilities. On Oct. 17, 2014, TECO Diversified entered into an agreement to sell all of its ownership interest in TECO Coal. On Feb. 5, 2015, the agreement was amended to reduce the selling price and extend the closing date to Mar. 13, 2015.

Revenues from Continuing Operations

 

(millions)

 

2014

 

 

2013

 

 

2012

 

Tampa Electric

 

$

2,021.0

 

 

$

1,950.5

 

 

$

1,981.3

 

PGS

 

 

399.6

 

 

 

393.5

 

 

 

398.9

 

NMGC

 

 

137.5

 

 

 

0.0

 

 

 

0.0

 

Total regulated businesses

 

 

2,558.1

 

 

 

2,344.0

 

 

 

2,380.2

 

Other

 

 

8.3

 

 

 

11.1

 

 

 

7.5

 

Total revenues from continuing operations

 

$

2,566.4

 

 

$

2,355.1

 

 

$

2,387.7

 

For additional financial information regarding TECO Energy’s significant business segments including geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements.

6


Discontinued Operations/Asset Dispositions

TECO Guatemala, a Florida corporation, owned subsidiaries that participated in two contracted Guatemalan power plants, Alborada and San José. TECO Energy, Inc. completed the sale of its generating and transmission assets in Guatemala during 2012 as part of a business strategy to focus on its domestic electric and gas utilities.

On Oct. 17, 2014, TECO Diversified entered into an agreement to sell all of its ownership interest in TECO Coal.  On Feb. 5, 2015, the agreement was amended to extend the closing date to Mar. 13, 2015 and to establish a purchase price of $80 million plus any cash on hand as of the closing, subject to customary post-closing adjustments, plus contingent payments of up to $60 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices.

See Notes 19, 20 and 23 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

Acquisition of NMGI

On Sept. 2, 2014, the company completed the acquisition contemplated by the SPA dated May 25, 2013 by and among the company, NMGI and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI, which was incorporated in the State of Delaware in 2008, is the parent company of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments.

See Note 21 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding the acquisition.

TAMPA ELECTRIC – Electric Operations

TEC was incorporated in Florida in 1899 and was reincorporated in 1949. TEC is a public utility operating within the State of Florida. Its 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, with an estimated population of over one million. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has three electric generating stations in or near Tampa, one electric generating station in southwestern Polk County, Florida and one electric generating station in long-term reserve standby located near Sebring, a city in Highlands County in South Central Florida.

Tampa Electric had 2,370 employees as of Dec. 31, 2014, of which 877 were represented by the International Brotherhood of Electrical Workers and 169 were represented by the Office and Professional Employees International Union. In January 2015, 290 Tampa Electric employees were transferred to TECO Energy’s centralized service company subsidiary, TECO Services, Inc.

In 2014, Tampa Electric’s total operating revenue was derived approximately 50% from residential sales, 30% from commercial sales, 8% from industrial sales and 12% from other sales, including bulk power sales for resale. Approximately 4% of revenues were attributable to governmental municipalities. The sources of operating revenue and MWH sales for the years indicated were as follows:

Operating Revenue

 

(millions)

 

2014

 

 

2013

 

 

2012

 

Residential

 

$

1,007.6

 

 

$

936.8

 

 

$

958.9

 

Commercial

 

 

602.0

 

 

 

581.2

 

 

 

612.3

 

Industrial – Phosphate

 

 

59.9

 

 

 

71.9

 

 

 

75.7

 

Industrial – Other

 

 

104.6

 

 

 

100.4

 

 

 

101.2

 

Other retail sales of electricity

 

 

181.9

 

 

 

177.4

 

 

 

184.0

 

Total retail

 

 

1,956.0

 

 

 

1,867.7

 

 

 

1,932.1

 

Sales for resale

 

 

13.0

 

 

 

8.5

 

 

 

16.2

 

Other

 

 

52.0

 

 

 

74.3

 

 

 

33.0

 

Total operating revenues

 

$

2,021.0

 

 

$

1,950.5

 

 

$

1,981.3

 

7


Megawatt- hour Sales

 

(thousands)

 

2014

 

 

2013

 

 

2012

 

Residential

 

 

8,656

 

 

 

8,470

 

 

 

8,395

 

Commercial

 

 

6,142

 

 

 

6,090

 

 

 

6,185

 

Industrial

 

 

1,901

 

 

 

2,026

 

 

 

2,002

 

Other retail sales of electricity

 

 

1,827

 

 

 

1,832

 

 

 

1,827

 

Total retail

 

 

18,526

 

 

 

18,418

 

 

 

18,409

 

Sales for resale

 

 

259

 

 

 

222

 

 

 

267

 

Total energy sold

 

 

18,785

 

 

 

18,640

 

 

 

18,676

 

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, issuances 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 cost to provide service, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include O&M expenses, depreciation and taxes, as well as 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 the individual 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  2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 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 Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that an expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement 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 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 rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. 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 retroactive to Jan. 1, 2013. Effective Nov. 1, 2013, Tampa Electric ceased accruing $8.0 million annually to the FERC-authorized and FPSC-approved self-insured storm damage reserve.

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.

8


Non-power goods and services transactions between Tampa Electric and its affiliates 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. Given TECO Energy’s acquisition of NMGC on Sept. 2, 2014, Tampa Electric and TECO Energy jointly requested a waiver from FERC on Oct. 1, 2014 in order for Tampa Electric to continue to supply a de-minimis level of non-power goods and services to its affiliates as of Jan. 1, 2015. On Oct. 1, TECO Energy separately notified FERC that it would no longer qualify to be considered a single-state holding company under the Public Utility Holding Company Act of 2005 as of Jan. 1, 2015, and thus it had formed a centralized service company, TECO Services, Inc., which would provide other non-power goods and services to Tampa Electric and its affiliates.  On Dec. 31, 2014, FERC granted Tampa Electric’s requested waiver without conditions, effective as of Jan. 1, 2015.

In 2012, Tampa Electric received notification from the FERC that its accounting practices and financial reporting processes would be audited, along with its compliance with the FERC’s records retention requirements. No material issues were identified as a result of the audit, and the audit was concluded during 2014, with the identification of four non-material items.  Tampa Electric updated certain accounting processes and refunded de-minimis amounts to its transmission customers during 2014 as a result of this audit.

On June 30, 2014, the company filed its required triennial market-power analysis, demonstrating that the company does not have wholesale market power using FERC’s two analytical screens. This compliance filing was made in support of the company’s continued ability to effect wholesale market-based rate transactions everywhere, except within Tampa Electric’s balancing-authority area. FERC is expected to respond to Tampa Electric’s triennial filing during the first half of 2015.

Tampa Electric 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

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. Distributed generation could also be a source of competition in the future, but has not been a significant factor to date (see the Environmental Compliance section of the MD&A). Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.

Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other investor-owned, municipal and other utilities, as well as co-generators and other unregulated power generators with uncontracted excess capacity. 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 of 75 MW or more. The PPSA requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.

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.

9


Fuel

Approximately 62% of Tampa Electric’s generation of electricity for 2014 was coal-fired, with natural gas representing approximately 38%. Tampa Electric used its generating units to meet approximately 95% of the total system load requirements, with the remaining 5% coming from purchased power. Tampa Electric’s average delivered fuel cost per MMBTU and average delivered cost per ton of coal burned have been as follows:

 

Average cost per MMBTU

 

2014

 

 

2013

 

 

2012

 

 

2011

 

 

2010

 

Coal

 

$

3.48

 

 

$

3.36

 

 

$

3.57

 

 

$

3.46

 

 

$

3.08

 

Oil

 

 

0.0

 

 

 

30.01

 

 

 

25.88

 

 

 

21.21

 

 

 

16.43

 

Gas (Natural)

 

 

5.68

 

 

 

5.23

 

 

 

5.34

 

 

 

6.20

 

 

 

6.74

 

Composite

 

 

4.16

 

 

 

4.00

 

 

 

4.19

 

 

 

4.38

 

 

 

4.46

 

Average cost per ton of coal burned

 

$

83.70

 

 

$

77.79

 

 

$

84.59

 

 

$

83.17

 

 

$

74.80

 

Tampa Electric’s generating stations burn fuels as follows: Bayside Station burns natural gas; Big Bend Station, which has SO2 scrubber capabilities and NOx reduction systems, burns a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas at CT4; Polk Power Station burns a blend of low-sulfur coal and petroleum coke (which is gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil; and Phillips Station, which burned residual fuel oil, was placed on long-term standby in September 2009.

Coal. Tampa Electric burned approximately 5.0 million tons of coal and petroleum coke during 2014 and estimates that its combined coal and petroleum coke consumption will be about 5.2 million tons in 2015. During 2014, Tampa Electric purchased approximately 76% of its coal under long-term contracts with five suppliers, and approximately 24% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 73% of its coal and petroleum coke requirements in 2015 under long-term contracts with five suppliers and the remaining 27% in the spot market.

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 2014, approximately 84% of Tampa Electric’s coal supply was deep-mined, approximately 7% was surface-mined and the remaining was petroleum coke. 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.

Natural Gas. As of Dec. 31, 2014, approximately 90% of Tampa Electric’s 1,500,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 80% of its expected gas needs for the April 2015 through October 2015 period. In early March 2015, to meet its generation requirements, Tampa Electric expects to issue RFPs to meet its remaining 2015 gas needs and begin contracting for its 2016 gas needs. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

Oil. Tampa Electric has agreements in place to purchase low sulfur No. 2 fuel oil for its Big Bend and Polk Power stations. All of these agreements have prices that are based on spot indices.

Franchises and Other Rights

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 as 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 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 through August 2043.

10


Franchise fees payable by Tampa Electric, which totaled $44.9 million at Dec. 31, 2014, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

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, and material Clean Water Act implications and impacts by federal and state legislative initiatives. 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.

Capital Expenditures

Tampa Electric’s 2014 capital expenditures included approximately $66 million related to environmental compliance and improvement programs, primarily for upgrades to scrubbers and modifications to coal combustion by-product storage areas at the Big Bend Power Station. See the Liquidity, Capital Expenditures section of MD&A for information on estimated future capital expenditures related to environmental compliance.

PEOPLES GAS SYSTEM – Gas Operations

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

Gas is delivered to the PGS 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 almost 354,000 customers. The system includes approximately 11,740 miles of mains and 6,800 miles of service lines (see PGS’s Franchises and Other Rights section below).

PGS had 542 employees as of Dec. 31, 2014. A total of 141 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations. In January 2015, 14 PGS employees were transferred to TECO Services, Inc.

In 2014, the total throughput for PGS was approximately 1.5 billion therms. Of this total throughput, 7% was gas purchased and resold to retail customers by PGS, 87% was third-party supplied gas that was delivered for retail transportation-only customers and 6% was gas sold off-system. Industrial and power generation customers consumed approximately 60% of PGS’s annual therm volume, commercial customers consumed approximately 30%, off-system sales customers consumed 5% and the remaining balance was consumed by residential customers.

While the residential market represents only a small percentage of total therm volume, residential operations comprised about 37% of total revenues. Approximately 5% of revenues are attributed to governmental municipalities.

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 31 compressed natural gas filling stations connected to the PGS distribution system.

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

 

 

 

Revenues

 

 

Therms

 

(millions)

 

2014

 

 

2013

 

 

2012

 

 

2014

 

 

2013

 

 

2012

 

Residential

 

$

144.1

 

 

$

128.1

 

 

$

125.4

 

 

 

80.8

 

 

 

74.4

 

 

 

70.8

 

Commercial

 

 

139.1

 

 

 

133.4

 

 

 

134.1

 

 

 

460.5

 

 

 

438.1

 

 

 

421.4

 

Industrial

 

 

13.1

 

 

 

13.4

 

 

 

10.3

 

 

 

274.3

 

 

 

272.0

 

 

 

237.3

 

Off-system sales

 

 

39.4

 

 

 

56.7

 

 

 

73.7

 

 

 

84.0

 

 

 

143.1

 

 

 

224.0

 

Power generation

 

 

6.8

 

 

 

9.9

 

 

 

12.4

 

 

 

643.5

 

 

 

744.4

 

 

 

913.5

 

Other revenues

 

 

48.5

 

 

 

42.2

 

 

 

34.9

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

391.0

 

 

$

383.7

 

 

$

390.8

 

 

 

1,543.1

 

 

 

1,672.0

 

 

 

1,867.0

 

11


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 such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, 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. For a description of recent proceeding activity, see the Regulation-PGS Rates section of MD&A.

PGS’s results reflect base rates established in May 2009, when the FPSC approved a base rate increase of $19.2 million which became effective on June 18, 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.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the PGA clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers 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 2014, the FPSC approved PGS’s 2015 PGA cap factor for the period January 2015 through December 2015.

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. 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 earn a return, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. PGS projects to have all cast iron and bare steel removed from its system within 8 years. Lastly, the FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.

In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system. 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 has a “NaturalChoice” program, offering unbundled transportation service to all non-residential customers, as well as 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. 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 21,900 transportation-only customers as of Dec. 31, 2014 out of approximately 36,000 eligible customers.

12


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.

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.

Gas is delivered by FGT through 69 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville division receives gas delivered by a pipeline company through two gate stations located northwest of Jacksonville. Another pipeline company provides delivery through six gate stations. PGS also has one interconnection with its affiliate pipeline company in Clay County, Florida.

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 and swing-supply contracts 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.

Neither PGS nor any of the interconnected interstate pipelines have storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS’s industrial customers are in the categories that are first curtailed in such situations. PGS’s tariff and transportation agreements with these customers give PGS the right to divert these customers’ gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.

Franchises and Other Rights

PGS holds franchise and other rights with 113 municipalities 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 specify the negotiated terms and conditions governing PGS’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 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 with the incorporated municipalities within its service area have various expiration dates ranging from the present through 2044. PGS expects to negotiate sixteen franchises in 2015. Franchise fees payable by PGS, which totaled $8.7 million at Dec. 31, 2014, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.

Utility operations in areas 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 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.

13


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 manufactured gas plant sites. See Note 12 to the TECO Energy Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

Capital Expenditures

During the year ended Dec. 31, 2014, PGS did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2015 through 2019 period.

NEW MEXICO GAS COMPANY

NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in the state of New Mexico. NMGC had approximately 700 employees as of Dec. 31, 2014.

NMGC operates a natural gas distribution system that serves approximately 513,000 customers. The system includes approximately 1,600 miles of transmission pipeline, 10,200 miles of mains and 521,400 service lines (see NMGC’s Franchises and Other Rights section below). NMGC’s system interconnects with five interstate pipelines.

For the last four months of 2014 (since the acquisition by TECO Energy), the total throughput for NMGC was over 275 million therms. Of this total throughput, 53% was gas purchased and resold to retail customers by NMGC, 41% was third-party supplied gas that was delivered for retail transportation-only customers and 6% was gas sold or transported off‑system. Industrial and power generation customers consumed approximately 27% of NMGC’s 2014 annual therm volume, commercial customers consumed approximately 31%, off-system transportation customers consumed 6% and the remaining balance was consumed by residential customers.

Natural gas has historically been used primarily for residential heating purposes in New Mexico.  The residential market represents approximately 37% of total annual therm volume and 72% of NMGC’s total annual revenues. Approximately 4% of annual revenues are attributed to facilities of governmental entities, including the federal government, the State of New Mexico, school districts and municipalities.

Revenues and therms for NMGC for the four months ended Dec. 31, 2014 were as follows:

 

 

 

Revenues

 

 

Therms

 

(millions)

 

2014

 

 

2014

 

Residential

 

$

99.9

 

 

 

108.2

 

Commercial

 

 

27.1

 

 

 

37.4

 

Industrial

 

 

0.9

 

 

 

1.6

 

On system transportation

 

 

7.1

 

 

 

111.6

 

Off system transportation

 

 

0.3

 

 

 

16.5

 

Other revenues

 

 

2.2

 

 

 

 

 

Total

 

$

137.5

 

 

 

275.3

 

No significant part of NMGC’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 NMGC. NMGC’s business is seasonal with much higher volumes and revenues experienced during colder winter months.

Regulation

The operations of NMGC are regulated by the NMPRC. The NMPRC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the NMPRC seeks to set rates at a level that provides an opportunity for a utility such as NMGC to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

The basic costs of providing natural gas service, other than the costs of purchased gas, gas storage services 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 NMGC's weighted cost of capital, primarily includes its cost for long-term debt and an allowed ROE. Base rates are determined in NMPRC revenue requirements proceedings which occur at irregular intervals at the initiative of NMGC, the NMPRC or other parties. For a description of recent proceeding activity, see the Regulation-NMGC Rates section of MD&A.

14


In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately $34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on Jan. 31, 2012, revising, among other things, base rates for all service provided on or after Feb. 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately $21.5 million on a normalized annual basis. The monthly residential customer access fee increased from $9.59 to $11.50, with the remaining rate increase reflected in changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017 and customers will receive a $2 to $4 million credit per year until the next rate case as reported in Note 21 to the TECO Energy, Inc. Consolidated Financial Statements.

NMGC recovers the costs it pays for gas supply and interstate transportation for system supply through the PGAC.  This charge is designed to recover the costs incurred by NMGC 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.  On a monthly basis, NMGC estimates its cost of gas for the next month (taking into consideration the expected cost of gas to be purchased for the next month, expected demand and any prior month under-recovery or over-recovery of NMGC’s cost of gas) and sets the GCBF rate to be used in the next month to recover those estimated costs.  For any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in revenue collected through the PGAC.  NMGC also has regulatory authority to include a simple interest charge or credit based upon the month-end balance of the PGAC under-recovery or over-recovery of NMGC’s cost of gas.  NMGC’s annual PGAC period runs from Sept. 1 to Aug. 31.  The NMPRC requires that NMGC file a reconciliation of the PGAC period costs and recoveries, annually in December.  Additionally, NMGC must file a PGAC Continuation Filing with the NMPRC every four years.  The purpose of the PGAC Continuation Filing is to establish that the continued use of the PGAC is reasonable and necessary.  In January 2013, the NMPRC approved the PGAC Continuation Filing allowing for continued use of the PGAC for another four years.

In addition to its base rates and PGAC, NMGC’s residential customers and customers utilizing NMGC’s small and medium volume general services also pay a per-therm charge for energy conservation. The conservation charge is intended to permit NMGC to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are approved and monitored by the NMPRC. The NMPRC requires natural gas utilities to offer transportation-only service to all customer classes.

In addition to economic regulation, NMGC is subject to the NMPRC's safety jurisdiction, pursuant to which the NMPRC regulates the construction, operation and maintenance of NMGC's distribution system. In general, the NMPRC 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, Code of Federal Regulations.

NMGC 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 Matters section).

Competition

Although NMGC 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. NMGC has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

Pursuant to New Mexico statutes and NMPRC rules and regulations, NMGC is required to provide transportation-only services for all customer classes. NMGC receives its base rates for distribution gas delivery services regardless of whether a customer decides to opt for transportation-only service or continue on NMGC’s gas commodity sales service. During the four months ended Dec. 31, 2014, NMGC had approximately 4,000 transportation-only end-use customers and approximately 509,000 gas commodity sales service customers.  Transportation-only throughput represented 46.5% of total system throughput and 5.4% of total revenue for the four months ended Dec. 31, 2014.

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 transmission and distribution providers and thereby bypassing NMGC transmission and distribution facilities. In response to this competition, NMGC has developed various programs, including the provision of transportation-only services at discounted rates.

15


Gas Supplies

NMGC’s service territory is situated between two large natural gas production basins (the San Juan Basin to the northwest of the Company’s service territory and the Permian Basin to the southeast of NMGC’s service territory).  Natural gas is transported from these production basins on major interstate pipelines to NMGC’s intrastate transmission system and then to customers using its distribution system.  The San Juan Basin typically supplies 85% of NMGC’s gas supply, with the Permian Basin supplying the remaining balance.

NMGC’s transmission and distribution system interconnects with five interstate pipelines owned by various pipeline companies.  NMGC has firm pipeline capacity contracts with these pipeline companies.  To enhance gas supply and transportation availability, NMGC has an ownership interest in the Blanco Hub, one of the central supply and marketing points in the San Juan Basin.  The Blanco Hub interconnects with NMGC's transmission system as well as major nearby gathering systems and interstate pipelines.  To provide for system balancing and peak day supply requirements, NMGC contracts for 3.2 billion cubic feet (Bcf) of underground gas storage capacity and gas storage services in an underground facility in west Texas.  This storage facility is connected to two major interstate pipelines that, in turn, connect to NMGC’s transmission and distribution system.

Gas is purchased from various suppliers at market pools and processing plant tailgates from marketers and producers. NMGC has negotiated standard terms and conditions for the purchase of natural gas under the NAESB and the Gas Industry Standards Board forms of agreement.  NMGC purchases gas for resale to its jurisdictional gas sales customers in accordance with an annual gas supply plan filed with the NMPRC.

Gas price spikes, which can occur in high demand winter months, have the potential to significantly increase customer bills.  To provide a degree of price protection, NMGC utilizes a hedging plan for a portion of the winter gas supply.  The gas hedging activity is discussed in more detail in Note 16 of the TECO Energy, Inc. Consolidated Financial Statements.  

Franchises and Other Rights

Many of NMGC’s transmission and distribution facilities are located on lands that require the grant of rights-of-way or franchises (collectively, ROW) from non-tribal governmental entities, Native American tribes and pueblos, or private landowners. In some cases, renewed ROWs must be submitted to the Federal Bureau of Indian Affairs (BIA) for approval.  For the four months ended Dec. 31, 2014, NMGC incurred expenditures for ROW renewals on Native American tribal and pueblo lands that amounted to $7.9 million.

In 2011, the New Mexico legislature passed legislation confirming the validity and enforceability of agreements with public utilities that provide access to public rights of way, including expired agreements that have continued to be honored by both the public utility and the local government according to their terms, regardless of the expiration date of the agreements. Accordingly, some of NMGC’s expired ROWs remain in effect by acquiescence, though NMGC expects to enter into negotiations over those expired ROWs and renew them.  Based on current renewal experience with ROWs on Native American tribal and pueblo lands, NMGC believes that it is likely those ROWs will be renewed at prices that are significantly higher than historical levels.  NMGC does not have condemnation rights on Native American tribal and pueblo lands, and, if it is unsuccessful in renewing some or all of these expiring or expired ROWs, it could be obligated to remove its facilities from, or abandon its facilities on, the property covered by the ROWs and seek alternative locations for its transmission or distribution facilities. With respect to land held by non-tribal governmental entities and privately-held land, however, NMGC may have condemnation rights and, thus, in the case where ROWs cannot be renewed by negotiation, NMGC would likely exercise such rights rather than remove or abandon facilities and find alternative locations for such facilities.  Historically, ROW costs have been recovered in rates charged to customers, and NMGC will continue to seek to recover ROW costs in future rates charged to customers.

Environmental Matters

NMGC’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.

NMGC has no former MGP sites or material environmental liabilities. NMGC does not own any facilities or sites where investigation, remediation, or monitoring of environmental conditions is ongoing or anticipated to be required. NMGC is unaware of any soil or groundwater contamination for which it might be responsible under federal, state, or local laws or regulations. NMGC is a conditionally exempt small quantity generator with less than 100 kilograms of hazardous waste per month. Wastes are routinely characterized to determine whether or not they are subject to applicable hazardous waste regulations.

NMGC currently maintains two Title V (major source) air permits, for the Star Lake and Espejo Compressor Stations, as the federal EPA Region 6 currently does not issue minor source permits for Title V purposes to facilities on Native American or Pueblo

16


lands. The remainder of its compressor stations are classified as minor sources. A minor source is one which has potential uncontrolled emissions less than 100 tons per year per regulated pollutant.

See Environmental Compliance section of the MD&A for additional information.

Capital Expenditures

During the four months ended Dec. 31, 2014, NMGC did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2015 through 2019 period.

TECO COAL

TECO Coal, a wholly owned subsidiary of TECO Energy, Inc., has subsidiaries operating surface and underground mines as well as coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia.

TECO Coal owns no operating assets but holds all of the common stock of Gatliff Coal Company, Rich Mountain Coal Company, Clintwood Elkhorn Mining Company, Pike-Letcher Land Company, Premier Elkhorn Coal Company, Perry County Coal Corporation and Bear Branch Coal Company. TECO Coal owns, controls and operates, by lease or mineral rights, surface and underground mines and coal processing and loading facilities. TECO Coal produces, processes and sells bituminous, predominately low sulfur coal of metallurgical, PCI, steam and industrial grades.

TECO Coal is a supplier of metallurgical and PCI coal for use in the steel-making process and a supplier of thermal coal to electric utilities and manufacturing industries. TECO Coal also exports metallurgical and PCI coals internationally, primarily to European markets.

Metallurgical, PCI and industrial stoker coals accounted for approximately 60% of TECO Coal’s 2014 coal sales volume. Thermal coal accounted for approximately 40% of 2014 coal sales volume.

On Oct. 17, 2014, TECO Diversified entered into an agreement to sell all of its ownership interest in TECO Coal.  On Feb. 5, 2015, the agreement was amended to extend the closing date to Mar. 13, 2015 and to establish a purchase price of $80 million plus any cash on hand as of the closing, subject to customary post-closing adjustments, plus contingent payments of up to $60 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. As a result, TECO Coal is accounted for as an asset held for sale and discontinued operation.

In 2014, discontinued operations resulted in a loss of $82.0 million comprised of the full-year operating results discussed below and $76.4 million of after-tax impairment charges and tax valuation allowances. TECO Coal’s 2014 loss from operations was $5.6 million on sales of 5.5 million tons, compared with net income of $9.0 million on 5.8 million tons sold in 2013.  The 2014 results reflect selling prices and costs associated with reductions in personnel and steps taken in advance of closing the sale of the company.

See Notes 14, 19, 20 and 23 to the TECO Energy, Inc. Consolidated Financial Statements for more information.

TECO GUATEMALA

TECO Guatemala, a wholly owned subsidiary of TECO Energy, had subsidiaries with interests in independent power projects in Guatemala. On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations, related facilities and operations in Guatemala for a total purchase price of $227.5 million in cash. The sale of the Alborada Power Station closed on the same date for a selling price of $12.5 million. On Dec. 19, 2012, the closing occurred on the (i) San José power station and related facilities in Guatemala for a purchase price of $213.5 million and (ii) the remaining TECO Guatemala operations company for a purchase price of $1.5 million.

See Notes 19 and 20 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, TECO Guatemala Holdings, a wholly owned subsidiary of TECO Energy, has retained its rights under an arbitration claim against the Republic of Guatemala under the DR-CAFTA.  See Note 12 to the TECO Energy, Inc. Consolidated Financial Statements for more information.

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EXECUTIVE OFFICERS OF THE REGISTRANT

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

 

 

  

 

  

Current Positions and Principal

Name

  

Age

  

Occupations During The Last Five Years

 

 

 

John B. Ramil

  

59

  

President and Chief Executive Officer, TECO Energy, Inc., and Chief Executive Officer, Tampa Electric Company, August 2010 to date; President and Chief Operating Officer, TECO Energy, Inc., July 2004 to August 2010.

 

 

 

Charles A. Attal, III

  

55

  

Senior Vice President-General Counsel, Chief Legal Officer and Chief  Ethics and Compliance Officer, TECO Energy, Inc. and General Counsel and Chief Ethics and Compliance Officer, Tampa Electric Company, June 2014 to date; and  Senior Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc. and General Counsel of Tampa Electric Company, February 2009 to June 2014.

 

 

 

Phil L. Barringer

  

61

  

Senior Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., Jan. 30, 2013 to date; Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., Jan. 1, 2013 to Jan. 30, 2013; Chief Human Resources Officer and Procurement Officer, Tampa Electric Company, January 2013 to date; Vice President-Human Resources of TECO Energy, Inc. and Tampa Electric Company, July 2009 to December 2012; and President, TECO Guatemala, July 2009 to date (operating companies sold December 2012).

 

 

 

Sandra W. Callahan

  

62

  

Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., February 2011 to date, and Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), Tampa Electric Company, October 2009 to date; and Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., October 2009 to February 2011.

 

 

 

Gordon L. Gillette

  

55

  

President, Tampa Electric Company, July 2009 to date.

 

 

 

Ryan A. Shell

 

49

 

President, New Mexico Gas Company, Inc., Dec. 31, 2014 to date; Vice President of Finance and Shared Services, New Mexico Gas Company, Inc., September 2014 to Dec. 31, 2014; Vice President of Finance and Treasurer, New Mexico Gas Company, Inc., February 2013 to September 2014; and Vice President, Controller and Treasurer, New Mexico Gas Company, Inc., January 2009 to February 2013.

 

 

 

 

 

Clark Taylor

 

65

 

President, TECO Coal Corporation, April 2011 to date; and prior thereto, Vice President-Controller, TECO Coal Corporation.

There is no family relationship between any of the persons named above or between executive officers and any director of the company. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on Apr. 29, 2015, and until such officer’s successor is elected and qualified.

 

 

Item 1A. RISK FACTORS.

General Business and Operational Risks

General economic conditions may adversely affect our businesses.

Our businesses are affected by general economic conditions. In particular, growth in the regulated utilities’ service areas in Florida and New Mexico is important to the realization of annual energy sales growth for Tampa Electric, PGS and NMGC. Any weakening of economic conditions could adversely affect our utilities’ expected performance and their ability to collect payments from customers.

Our electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition.

Our electric and gas utilities operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC in Florida and the NMPRC in New Mexico, 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 our utilities’ financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

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If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, the earnings could be subject to review by the FPSC which could result in refunds to customers, which could reduce earnings and cash flow.

Various factors relating to the integration of NMGC could adversely affect our business and operations.

Based on the completion of the permanent financing for the NMGC acquisition, we currently expect NMGC to be accretive to earnings for the full-year 2015 period. However, the anticipated accretion to earnings from NMGC during this integration period is based on estimates of synergies from the transaction and growth in the New Mexico economy, which are dependent on local and global economic conditions and other factors, which may materially change, including:

·

our estimate of NMGC’s expected operating performance after the completion of the transaction may vary significantly from actual results;

·

Over time, we will be making significant capital investments to convert several NMGC computer systems to the systems that we use in Florida.  These conversions may not be accomplished on time or on budget, which would increase costs for NMGC.  In addition, the time required to convert these systems will cause NMGC to operate the existing systems past the end of their normal lives, which could reduce reliability.

·

the potential loss of key employees of TECO Energy or NMGC who may be uncertain about their future roles in the TECO Energy / NMGC organization.

Negative impacts from these factors could have an adverse effect on the anticipated benefits of the transaction or our business, financial condition, results of operations or stock price.

We have incurred and will continue to incur significant integration costs in connection with the NMGC acquisition.

We incurred significant transaction costs in connection with the execution and consummation of the NMGC acquisition as well as the related financing transactions. In addition, we are in the process of integrating NMGC into TECO Energy following the closing of the NMGC acquisition on Sept. 2, 2014. Although we anticipate achieving synergies in connection with the NMGC acquisition, we also expect to incur costs to achieve these synergies. In 2014, we incurred transaction and integration costs in connection with the NMGC acquisition of $16.6 million. We anticipate that we will incur additional non-recurring charges in connection with this integration, including charges associated with integrating processes and systems. At this time, we cannot identify the timing, nature and amount of all such additional charges. We have identified some, but not all, of the actions necessary to achieve our anticipated synergies. Accordingly, the synergies expected from the acquisition of NMGC may not be achievable in our anticipated amount or timeframe or at all.

Changes in the environmental laws and regulations affecting our businesses could increase our costs or curtail our activities.

Our 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 us or require us to curtail some of our businesses’ activities.

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

In response to a coal ash pond failure in December 2008 at another utility, the EPA proposed new regulations for the management and disposal of CCRs. A preliminary draft of the final rule was issued in December 2014, which designated CCRs as non-hazardous wastes. The designation of CCRs as non-hazardous waste in the preliminary draft of the final rule allows for the continued operation of ash impoundments on Tampa Electric’s facilities; however, this designation may impose additional administrative and compliance requirements, which could increase costs.

It is expected that the rules, once made final, will be subjected to litigation, which could have a material impact on both the content and the timing of the implementation of the rules.  Accordingly, the outcome of this rule-making process and its impact on our businesses cannot be determined at this time. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, we cannot be assured that any increased costs associated with complying with those regulations will be eligible for such treatment.

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

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions. While GHG emission regulations have been proposed, both at the federal level and in various states, none has been passed at this time and, therefore, costs to reduce GHGs are unknown. Presently there is no viable technology to remove CO2 post-combustion from

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conventional coal-fired units such as Tampa Electric’s Big Bend units. New rules requiring post-combustion CO2 removal could require significant investment in what is essentially experimental technology, costly conversion to natural gas fuel, or a premature shut-down of the units, which would result in non-cash write-offs.

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 we cannot be assured that the FPSC would grant such recovery.

In a June 25, 2013, memorandum, President Obama directed the EPA to issue new emissions standards for future power plants as well as modified, reconstructed or existing power plants to reduce GHG emissions. The new standards, which were released in the fall of 2013, essentially mandate that no new coal fired power plants will be constructed in the U.S. On June 2, 2014, the EPA released a comprehensive proposed rule which it calls the “Clean Power Plan,” aiming to cut GHG emissions from existing power plants by 30% from their 2005 levels by 2030, with an interim goal for the period from 2020 through 2029. Under the proposed rule, each state would have to reduce CO2 emissions on a state-wide basis by an amount specified by the EPA. The EPA determined the target amount for each state based on its view of each state’s options, including: making power plant efficiency upgrades; shifting from coal to natural gas generation; investing in zero- and low-emitting power sources, such as renewable and nuclear energy; and implementing customer energy efficiency programs. Because the 30% reduction target is an average across all states, some states have higher or lower target emission reduction goals under the proposed rule than the average. Based on current emissions, Florida has a reduction goal of 38%, which is higher than the national average. Under the proposed rules, states will have flexibility in designing programs to meet their emission reduction targets, including the four approaches noted above or any other measures they choose to adopt, for example, carbon tax and cap-and-trade. The EPA is scheduled to finalize the rule by June 1, 2015, and states will have until June 30, 2016, to submit plans to achieve their target emission reductions (subject to extension and EPA approval of the states’ plans). It is unclear whether Florida’s proposed implementation plan will take into consideration emission reductions achieved prior to 2005 or if that baseline year will be changed in the comment process. The 2005 baseline year does not take into consideration the significant reductions in greenhouse gas emissions we achieved prior to 2005 (a reduction of approximately five million tons since 1998). If the 2005 baseline year remains unchanged (which due to our previous reductions in greenhouse gas emissions was our lowest emitting year), it may be more difficult for us to achieve the proposed reductions than other utilities in a cost-effective manner, especially when compared to utilities in other states that have lower emission reduction targets under the proposed rules. It is expected that the rules will be subjected to litigation, which could have a material impact on both the content and the timing of the implementation of the rules.  Accordingly, the outcome of this rule-making process and its impact on our businesses cannot be determined at this time; however, it could result in increased operating costs, or decreased operations at Tampa Electric’s coal-fired plants. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, we cannot be assured that any increased costs associated with complying with those regulations will be eligible for such treatment.

Among other rules, the EPA has proposed or finalized a number of new rules, including the CAIR/CSAPR and Hazardous Air Pollutants (“HAPS”) Maximum Achievable Control Technology (“MACT”) for emissions into the air, and a number of new rules focused on water use and discharges from power generation facilities.

These air focused rules impose stringent reductions in several pollutants from electric utility steam generators, primarily coal-fired, but including oil-fired as well. If the CSAPR rule is implemented as planned, the EPA has estimated that the implementation of CSAPR would require significant investment in pollution-control equipment for units not already equipped or could result in the retirement of primarily smaller, older coal-fired power stations that do not currently have state-of-the-art air pollution-control equipment already installed. The retirement of these units or switching to other fuels for compliance with this rule is likely to reduce overall demand for coal, which could reduce sales and financial results at TECO Coal.

The EPA’s proposed water focused rules could limit the supply of water available to our power generating facilities, which would require us to invest significant capital in new equipment and would increase our operating costs.

A mandatory RPS could add to Tampa Electric’s costs and adversely affect its operating results.

In past sessions of the Florida Legislature, an RPS was debated but ultimately not enacted; however, an RPS standard could be enacted in the future. In addition, there is the potential that legislation could be proposed in the U.S. Congress to introduce an RPS at the federal level. It remains unclear if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS, and Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers through the ECRC.

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The nation is increasingly dependent on natural gas to generate electricity and as an alternative to higher cost petroleum fuels. There may not be adequate infrastructure to deliver adequate quantities of natural gas to meet the expected future demand, and the expected higher demand for natural gas may lead to increasing costs for the commodity.

In the United States, utilities are increasingly relying on natural gas for new electric generating plants in response to GHG emissions concerns and attractive natural gas prices. Industrial customers and vehicle fleets are converting to natural gas based on attractive economics and lower emissions. Currently, there is an adequate supply and infrastructure to meet demand for natural gas in Florida and nationally. However, if future supplies are inadequate or if significant new investment is required to install the pipelines necessary to transport the gas, the cost of natural gas could rise.

Currently, our electric and gas utilities are allowed to pass the cost for the commodity gas and transportation services to customers without profit. Changes in commodity gas cost recovery regulations could reduce earnings if they required Tampa Electric, PGS or NMGC to bear a portion of the increased cost. In addition, increased costs to customers could result in lower sales.

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

All of our businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by our electric and gas utilities are particularly sensitive to variations in weather conditions. Those companies 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 and NMGC, which typically have short but significant winter peak periods that are dependent on cold weather, are more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. NMGC typically earns all of its net income in the first and fourth quarters, due to winter weather. Mild winter weather can negatively impact results at Tampa Electric, PGS and NMGC.

The state of Florida is exposed to extreme weather, including hurricanes, which can cause damage to our facilities and affect our ability to serve customers. There is the potential for gas customer service interruptions and system reliability problems during periods of extreme cold weather in New Mexico.

As a company with electric service and natural gas operations in peninsular Florida, we are exposed to extreme weather events, such as hurricanes. Extreme weather conditions can be destructive, causing outages and property damage that require the company to incur additional expenses. Extensive customer outages could reduce revenue collections. If warmer temperatures lead to changes in extreme weather events (increased frequency, duration and severity), these expenses could be greater.

While the company has storm preparation and recovery plans in place, and Tampa Electric and PGS have historically been granted regulatory approval to recover or defer the majority of significant storm costs incurred, extreme weather still poses risks to our operations and storm cost-recovery petitions may not always be granted or may not be granted in a timely manner. If costs associated with future severe weather events cannot be recovered in a timely manner, or in an amount sufficient to cover actual costs, our financial condition and operating results could be adversely affected.

In the past, in New Mexico supplies of natural gas from natural gas wells have been disrupted and interstate pipelines were unable to reliably deliver gas during periods of extreme cold weather, which caused retail customer service interruptions; and these types of disruptions could occur in the future.  NMGC is evaluating significant capital investments to ensure reliable supplies of natural gas for its customers if such interruptions occur again.  Future service interruptions could lead to customer lawsuits or cause NMGC to make additional capital investments, which could raise costs to customers.

NMGC operates high-pressure natural gas transmission pipelines, which involve risks that may result in accidents or otherwise affect our operations.

There are a variety of hazards and operating risks inherent in operating high-pressure natural gas transmission pipelines, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by floods, fires and other natural disasters that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, known as High Consequence Areas (HCAs) the level of damage resulting from these risks could be greater. We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we might maintain may not fully cover the damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material adverse effect on our business, earnings, financial condition and cash flows.

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NMGC’s high-pressure transmission pipeline operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.

Our pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the DOT. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.

PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand pipeline integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. Pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have a material adverse effect on our operations, earnings, financial condition and cash flows.

Commodity price changes may affect the operating costs and competitive positions of our businesses.

All of our businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. 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 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 and NMGC, 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 and NMGC relative to electricity, other forms of energy and other gas suppliers.

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

For the past several years, at Tampa Electric, and electric utilities across the country, weather-normalized electricity consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, trends toward smaller single family houses and increased multi-family housing.

Forecasts by our companies are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of our utilities 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.

Our computer systems and the infrastructure of our utility companies may be 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 our business and financial results and condition.

There have been an increasing number of cyber-attacks 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.

We have 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, we cannot be assured that a cyber-attack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject us to additional regulation, litigation or damage to our reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of our utility companies are designed and operated in such a manner 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 any damage. These types of events, either impacting our facilities or the industry in general, could also cause us to incur additional security- and insurance-related costs, and could have adverse effects on our business and financial results and condition.

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We rely on some natural gas transmission assets that we do not own or control to deliver natural gas. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver natural gas and supply natural gas to our electric generating stations may be hindered.

We depend on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas we sell to the wholesale and retail markets, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual and service obligations may be hindered.

Potential competitive changes may adversely affect our regulated electric and gas businesses.

There is competition in wholesale power sales across the country. 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 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 several years. Gas services provided by our gas utilities are unbundled for all non-residential customers. Because our gas utilities earn margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted their results. However, future structural changes that we cannot predict could adversely affect PGS and NMGC.

Increased customer use of distributed generation could adversely affect our regulated electric utility business.

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. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s proposed “Clean Power Plan” rule, if enacted as proposed, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule. See “Federal or state regulation of GHG emissions depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.”

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

There is proposed legislation to potentially be debated in the 2015 Florida legislative session, and there is a potential for an amendment to the Florida constitution to be on the ballot in 2016 that would promote increased use of solar energy to generate electricity.

Proposed action by the Florida legislature in 2015 and a potential amendment to the Florida constitution in 2016 would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and to 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 make investments in facilities to serve customers during periods that solar energy is not available that would not be profitable.

The value of our existing deferred tax benefits are determined by existing tax laws, and could be negatively impacted by changes in these laws.

“Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of our existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and would reduce future cash flow at the parent company.

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Impairment testing of certain long-lived assets could result in impairment charges.

We assess long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, we may be required to record non-cash impairment charges that could have a material adverse impact on our financial condition and results from operations. In connection with the NMGC acquisition, we recorded additional goodwill and long-lived assets that could become impaired.

Financing Risks

We have substantial indebtedness, which could adversely affect our financial condition and financial flexibility.

We have substantial indebtedness, which has resulted in fixed charges we are obligated to pay. The level of our indebtedness and restrictive covenants contained in our debt obligations could limit our ability to obtain additional financing.

TECO Energy, TECO Finance, TEC, NMGC and NMGI must meet certain financial covenants as defined in the applicable agreements to borrow under their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. See the Credit Facilities section and Significant Financial Covenants table in the Liquidity, Capital Resources sections of the Management’s Discussion & Analysis for descriptions of these covenants.

Although we were in compliance with all required financial covenants as of Dec. 31, 2014, we cannot assure compliance with these financial covenants in the future. Our failure to comply with any of these covenants or to meet our 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. We may not have sufficient working capital or liquidity to satisfy our debt obligations in the event of an acceleration of all or a portion of our outstanding obligations.

We also incur obligations in connection with the operations of our subsidiaries and affiliates that do not appear on our balance sheet. These obligations take the form of guarantees, letters of credit and contractual commitments, as described under the Liquidity, Capital Resources sections of the Management’s Discussion & Analysis.

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

TECO Finance and TEC have debt maturing in 2015 and subsequent years which they may need to refinance. Future financial market conditions could limit our ability to raise the capital we need and could increase our interest costs, which could reduce earnings. If we are not able to issue new debt, or we issue debt at interest rates higher than we expect, our financial results or condition could be adversely affected.

We enter into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable.

We enter into derivative transactions with counterparties, most of which are financial institutions, to hedge our exposure to commodity price and interest rate changes. Although we believe we have appropriate credit policies in place to manage the non-performance risk associated with these transactions, turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which we have an in-the-money position, we could be unable to collect from such counterparty.

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

Under calculation requirements of the Pension Protection Act, as of the Jan. 1, 2015 measurement date, our pension plan was essentially fully funded. Under MAP 21, we are not required to make additional cash contributions over the next five years; however we may make additional cash contributions from time to time.  Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund our pension plan in the future, and could cause pension expense to increase.

Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.

We are forecasting capital expenditures at Tampa Electric 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, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. We are forecasting capital expenditures at PGS to support customer growth, system reliability,

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conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe. Forecasted capital expenditures at NMGC are expected to support customer and system reliability and expansion.

If our capital expenditures exceed the forecasted levels, we may need to draw on credit facilities or access the capital markets on unfavorable terms. We cannot be sure that we will be able to obtain additional financing, in which case our financial position could be adversely affected.

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

Our senior unsecured debt is rated as investment grade by S&P at BBB, by Moody’s Investor’s Services (Moody’s) at Baa1, and by Fitch Ratings (Fitch) at BBB. The senior unsecured debt of TEC is rated by S&P at BBB+, by Moody’s at A2 and by Fitch at A-. The senior unsecured debt of NMGC is rated by S&P at BBB+. A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P and Fitch, and a three notch downgrade by Moody’s, may affect our ability to borrow, may change requirements for future collateral or margin postings, and may increase our financing costs, which may decrease our earnings. We may also experience greater interest expense than we may have otherwise if, in future periods, we replace maturing debt with new debt bearing higher interest rates due to any such downgrades. In addition, downgrades could adversely affect our relationships with customers and counterparties.

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

We are a holding company with no business operations of our own and depend on cash flow from our subsidiaries to meet our obligations.

We are a holding company with no business operations of our own or material assets other than the stock of our subsidiaries. Accordingly, all of our operations are conducted by our subsidiaries. As a holding company, we require dividends and other payments from our subsidiaries to meet our cash requirements. If our subsidiaries are unable to pay us dividends or make other cash payments to us, we may be unable to pay dividends or satisfy our obligations.

 

 

 

25


TECO COAL

During the period of ownership prior to the completion of the sale of TECO Coal, we retain the risks of ownership of that business.

Any failure of the pending sale of TECO Coal would likely alter certain aspects of our current business plans and could adversely affect our business and the value of TECO Coal.

On Oct. 17, 2014, TECO Diversified entered into an agreement to sell all of its ownership interest in TECO Coal to Cambrian Coal Corp., and on Feb. 5, 2015 amended that agreement.  The sale is subject to certain closing conditions, including the purchaser’s obtaining suitable financing. In accordance with the terms of the amended securities purchase agreement, we expect to realize approximately $80 million in initial gross proceeds from the sale, plus contingent payments of up to $60 million over the next five years depending on specified coal benchmark prices. There can be no assurances that we will realize any additional proceeds from these potential contingent payments. If certain closing conditions are not met by March 13, 2015 , either party may choose not to proceed with the sale.

In anticipation of the pending sale transaction, we have presented the financial results of TECO Coal in this annual report as discontinued operations and included charges totaling $76.4 million after-tax to write-down the carrying value of TECO Coal to the estimated fair value of the business as of Dec. 31, 2014. In the event that the TECO Coal sale transaction is not consummated on the terms contemplated by the sale agreement or at all, our financial results could be adversely affected.

The coal markets continued to weaken in 2014 and it is likely that TECO Coal’s operations will result in a loss in 2015. If the pending sale of TECO Coal is not consummated, TECO Coal’s expected 2015 losses would have an adverse effect on TECO Energy’s consolidated financial results and potentially our stock price. In addition, if the pending sale is not consummated, the value of TECO Coal’s assets might be further impaired, and we may not be able to realize the proceeds expected from the current transaction in a subsequent sale transaction.

Below are additional risks associated with TECO Coal, which could impact our results in the event the sale is not completed.

Competition among coal producers in Central Appalachia and other producing regions, and low natural gas prices, may adversely affect TECO Coal’s ability to sell steam coal. Low-cost natural gas has allowed utility steam coal users to switch from coal to natural gas to produce electricity, which has reduced the current market price and demand for TECO Coal’s steam coal from domestic utilities. If we continue to own TECO Coal, continued or further declines in natural gas prices and increased competition from lower cost producing areas would keep demand and selling prices low, which would reduce TECO Coal’s financial results, and could further reduce the value of its reserves.

TECO Coal has historically sold a significant portion of its production to domestic utilities for use in the generation of power. For over three years, natural gas prices have been dramatically lower than in previous periods due to the growth of hydraulic fracturing in the production of natural gas from shale formations. These low natural gas prices have caused utility coal users to switch to lower cost natural gas to generate electricity. Lower cost coals from other producing regions of the U.S., such as the Powder River Basin and the Illinois Basin are being utilized by more utilities in lieu of higher cost Central Appalachian coals, further reducing demand for TECO Coal’s production.

In the current coal markets, prices for Central Appalachian steam coal are not profitable. Without an increase in the cost of natural gas and an increase in the use of coal for power generation, or a general improvement in coal market conditions, TECO Coal could sign coal sales contracts at lower than earnings break even or cash cost of production prices or production could be reduced, either of which would cause its financial results to be reduced. If these conditions were to persist or decline further, the value of TECO Coal’s reserves could be further reduced, which could result in an additional non-cash impairment charge.

Failure to obtain the permits necessary to open new surface mines, or challenges to the validity of existing permits, could adversely affect TECO Coal’s financial results.

Our surface coal mining operations are dependent on permits from the USACE to open new surface mines necessary to maintain or increase production. Since 2008, new permits issued by the USACE under Section 404 of the Clean Water Act for new surface coal mining operations have been challenged in court by various environmental groups, resulting in very few usable permits being issued. Failure to obtain the necessary permits to open new surface mines, which are required to maintain and expand production, could reduce production, cause higher mining costs or require purchasing coal at prices above our cost of production to fulfill contract requirements, which would adversely affect TECO Coal’s financial results.

Challenges to existing permits that disrupt mining operations could result in higher costs if operations are forced to move to other mining sites or if coal is purchased from third parties, which would adversely affect TECO Coal’s financial results.

26


In 2010, the EPA issued new guidelines related to water quality for Central Appalachian coal surface mining operations that would be conditions of new surface mine permits, which would add significant cost to operations or curtail our surface mining activities and preparation plant operations.

In 2010, the EPA issued new guidance on environmental permitting requirements for Central Appalachian mountaintop removal and other surface mining projects. This guidance, which was made final by the EPA in 2011, limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis.  Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. In 2012, the United States District Court for the District of Columbia ruled that the EPA had exceeded its statutory authority in establishing the water quality guidance discussed above. Following the outcome of this court decision, pending appeals by the EPA, few, if any, new usable permits have been issued by the USACE. Over time, if new permits are not issued, TECO Coal could incur higher production costs or reduced production from surface mining operations.

TECO Coal’s sales to international customers are subject to risks that could result in losses or increased costs.

TECO Coal is exposed to financial risk through its sales to international customers, primarily in Asia. TECO Coal attempts to mitigate this risk through the use of third parties to broker the sales, dollar-denominated contracts, passage of title upon loading in the U.S. port, customer responsibility for the international freight, letters of credit posted by customers for purchase price of the commodity and the transportation to the U.S. port, and the utilization of local agents where appropriate. TECO Coal cannot be assured that these measures will effectively mitigate all international risks, which could have an adverse effect on TECO Coal’s financial conditions.

In 2015, TECO Coal expects to continue to sell metallurgical coal to customers in Asia. Prices for metallurgical coal sales to Asia are subject to being reset each quarter based on levels of supply and demand in the region. Over the past three years, the quarterly prices have been lower due to increased supply from Australia and other suppliers and weakening demand for metallurgical coal from China. In the first quarter of 2015, prices are currently below levels that make sales to these markets profitable. If these quarterly prices persist, TECO Coal’s production and financial results could be adversely affected.

The U.S. federal government has proposed the elimination of the percentage depletion tax deduction for the mining of coal, and other hard minerals and fossil fuels which could result in an increase to our tax rate.

If the percentage depletion tax deduction is eliminated for TECO Coal, its effective tax rate would rise from the historical range of 20% to 25% to the general corporate tax rate of 37%, which would reduce financial results at TECO Coal.

 

 

Item 1B. UNRESOLVED STAFF COMMENTS.

None.

Item 2. PROPERTIES.

TECO Energy 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 2014 net winter generating capability of 4,703 MW. Tampa Electric assets include the Big Bend Power Station (1,607 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).

The Big Bend coal-fired units went into service from 1970 to 1985, and the CT was installed in 2009. The Polk IGCC unit began commercial operation in 1996. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004 and Units 3 through 6 were completed in 2009. In 2009, Tampa Electric placed the Phillips Power Station on long-term reserve standby. In July of 2012, Tampa Electric placed the City of Tampa Partnership Station on long-term reserve standby.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,333 Mega Volts Amps. The transmission system consists of approximately 1,302 pole miles (including underground and double-circuit) of high voltage transmission lines, and

27


the distribution system consists of 6,215 pole miles of overhead lines and 4,944 trench miles of underground lines. As of Dec. 31, 2014, there were 739,304 meters in service. All of this property is located in Florida.

All plants and important fixed assets are held in fee except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature 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.

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

PEOPLES GAS SYSTEM

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 18,540 miles of pipe, including approximately 11,740 miles of mains and 6,800 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.

NEW MEXICO GAS COMPANY

NMGC’S distribution system extends throughout the areas it serves in New Mexico and consists of approximately 11,800 miles of pipe, including approximately 1,600 miles of transmission pipeline and 10,200 miles of distribution lines. Mains and service lines are maintained under ROW, franchises or permits.

NMGC’s operations are located in six operating areas throughout New Mexico. While most of the operations and administrative facilities are owned, a small number are leased.

TECO COAL

Property Control

Operations of TECO Coal and its subsidiaries are conducted on both owned and leased properties totaling approximately 294,000 acres in Kentucky, Tennessee and Virginia. TECO Coal’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. As is typical in the coal mining industry, TECO Coal generally has not obtained title insurance in connection with its acquisitions of coal reserves and/or related surface properties. In many cases, the seller or lessor will grant the purchasing or leasing entity a warranty of property title. When leasing coal reserves and/or related surface properties where mining has previously occurred, TECO Coal may opt not to perform a separate title confirmation due to the previous mining activities on such a property. In cases involving less significant properties and consistent with industry practices, title and boundaries to less significant properties are now verified during lease or purchase negotiations.  

In situations where property is controlled by lease, the lease terms are generally sufficient to allow the reserves for the associated operation to be mined within the initial lease term. The terms of many of these leases extend until the exhaustion of the mineable and merchantable coal from the leased property. If, however, extensions of the original lease term become necessary, provisions have generally been made within the original lease to extend the lease term upon continued payment of minimum royalties.

Coal Reserves

As of Dec. 31, 2014, the TECO Coal operating companies had a combined estimated 290.0 million tons of proven and probable recoverable reserves. All of the reserves consist of high quality bituminous coal. Reserves are the portion of the proven and probable tonnage that meet TECO Coal’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels. Additionally, other controlled areas presently identified as resource total 69.3 million tons of coal.

28


Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

Proven (Measured) Reserves - Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, working or drill holes: grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Probable (Indicated) Reserves - Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but for which the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Drill hole spacing for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). In this method of classification, “proven” reserves are considered to be those lying within one-quarter mile (1,320 feet) of a valid point of measurement and “probable” reserves are those lying between one-quarter mile and three-quarters mile (3,960 feet) from such an observation point.

Reserve estimates are prepared by TECO Coal’s staff of geologists. There are two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coal’s other geologists and coordinate third-party reviews of reserve estimates by qualified mining consultants. Annually, a third-party reserve audit is performed by Cardno, Inc. on TECO Coal’s newly identified reserves. The results of that audit are reflected in the numbers within this report.

The following table (Table 4) shows recoverable reserves by quantity and the method of property control as well as the Assigned and Unassigned reserves per mining complex.

RECOVERABLE RESERVES BY QUANTITY (1)

(Millions of tons)

Table 4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assigned (2)

 

 

Unassigned (2)

 

Mining Complex

 

Location

 

Total

 

 

Proven

 

 

Probable

 

 

Owned

 

 

Leased

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

Gatliff

Coal

 

Bell County, KY/ Knox County, KY/ Campbell County, TN

 

 

3.4

 

 

 

3.0

 

 

 

0.4

 

 

 

1.2

 

 

 

2.2

 

 

 

0.5

 

 

 

0.5

 

 

 

2.9

 

 

 

2.9

 

Clintwood Elkhorn

 

Pike County, KY/

 

 

53.4

 

 

 

44.6

 

 

 

8.8

 

 

 

0.0

 

 

 

53.4

 

 

 

53.4

 

 

 

55.2

 

 

 

0.0

 

 

 

0.0

 

Mining 

 

Buchanan County, VA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Premier

Elkhorn

Coal

 

Pike County, KY/Letcher County, KY/ Floyd County, KY

 

 

99.4

 

 

 

58.9

 

 

 

40.5

 

 

 

81.5

 

 

 

17.9

 

 

 

48.4

 

 

 

52.9

 

 

 

51.0

 

 

 

51.0

 

Perry

 

Perry County, KY/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

County 

 

Leslie County, KY/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal

 

Knott County, KY

 

 

133.8

 

 

 

85.6

 

 

 

48.2

 

 

 

1.3

 

 

 

132.5

 

 

 

128.6

 

 

 

130.5

 

 

 

5.2

 

 

 

5.2

 

Totals:

 

 

 

 

290.0

 

 

 

192.1

 

 

 

97.9

 

 

 

84.0

 

 

 

206.0

 

 

 

230.9

 

 

 

239.1

 

 

 

59.1

 

 

 

59.1

 

Notes:

(1)

Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. Reserve information reflects a moisture factor of 6.5%, which represents the average moisture present in TECO Coal’s delivered coal.

(2)

Assigned reserves mean coal which has been committed by TECO Coal to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by TECO Coal to others. Unassigned reserves represent coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin on the property.

29


RECOVERABLE RESERVES BY QUALITY (1)

(Millions of tons)

Table 5

 

 

 

 

Recoverable

 

 

 

Sulfur Content

 

 

 

 

 

 

 

Average BTU

 

 

Mining Complex

 

Reserves

 

 

< 1% (2)

 

 

>1% (2)

 

 

Compliance Tons (3)

 

 

As received

 

 

Coal Type (4)

Gatliff Coal

 

 

3.4

 

 

 

3.2

 

 

 

0.2

 

 

 

0.0

 

 

 

12,000-13,100

 

 

LSU

Clintwood Elkhorn Mining

 

 

53.4

 

 

 

35.1

 

 

 

18.3

 

 

 

13.8

 

 

 

12,500-13,500

 

 

HVM, LSU, PCI

Premier Elkhorn Coal

 

 

 

99.4

 

 

 

84.0

 

 

 

15.4

 

 

 

56.6

 

 

 

12,700-13,100

 

 

HVM, IS, LSU,  PCI

Perry County Coal

 

 

133.8

 

 

 

104.3

 

 

 

29.5

 

 

 

81.1

 

 

 

12,500-13,100

 

 

LSU, PCI, V

   Totals:

 

 

290.0

 

 

 

226.6

 

 

 

63.4

 

 

 

151.5

 

 

 

 

 

 

 

Notes:

(1)

Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.

(2)

<1% or >1% refers to sulfur content as a percentage in coal by weight.

(3)

Compliance coal is any coal that emits less than 1.2 pounds of sulfur dioxide per million BTU when burned. Compliance coal meets sulfur emission standards imposed by Title IV of the Clean Air Act.

(4)

Reserve holdings include metallurgical, PCI and thermal coal reserves. Although metallurgical and PCI coal reserves receive the highest selling price in the current market when marketed to steel-making customers, they can also be marketed as an ultra-high BTU, low-sulfur utility coal for electricity generation.

HVM – High Vol Metallurgical

PCI – Pulverized Coal Injection

LSU – Low Sulfur Utility

V – Various

IS – Industrial Stoker

Market Allocation of Reserves

The table below shows the allocation of TECO Coal reserves by market category (metallurgical, PCI, and thermal coal), which was prepared by TECO Coal at its four operating subsidiaries. As shown below, a substantial portion of the Clintwood Elkhorn Mining coal reserves has been allocated to the metallurgical category (with the remainder to the thermal coal category), a substantial portion of the Premier Elkhorn Coal reserves has been allocated to the PCI and metallurgical categories (with the remainder to the thermal coal category), a substantial portion of the Perry County coal reserves has been allocated to the PCI category (with the remainder to the thermal coal category), and all of the Gatliff Coal reserves has been allocated to the thermal coal category.

At TECO Coal’s request, Cardno, Inc. completed an audit of the methodology used by TECO Coal to conduct such allocation of its coal tonnage estimates. Cardno, Inc. reviewed information provided by TECO Coal and TECO Coal’s methodology of processing, which included examination by certified professional geologists of all supplied coal deposit maps and supporting coal quality data using industry accepted standards. The audit performed by Cardno, Inc. concluded that TECO Coal’s methodology of allocating its demonstrated reserves by market category is reasonably and responsibly prepared in accordance with industry accepted standards and in general conformance with SEC Industry Guide 7.

Market conditions may not always permit sales of coal into the particular market as identified; however, the objective of this reserve allocation is to recognize the market potential for planning and investment purposes.

30


The following table (Table 6) shows the recoverable reserves by market category per mining complex and in total. The total reserve mix is defined by percentage as 40% metallurgical, 40% PCI, (for a combined 80% specialty coals) and 20% thermal coal.

RESERVES BY MARKET CATEGORY

Table 6

 

Mining Complex

 

Met

Reserves

 

 

PCI

Reserves

 

 

Thermal

Reserves

 

 

Grand

Totals

 

 

Proven

 

 

Probable

 

 

Total

 

 

Proven

 

 

Probable

 

 

Total

 

 

Proven

 

 

Probable

 

 

Total

 

 

 

Gatliff Coal

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

2.8

 

 

 

0.6

 

 

 

3.4

 

 

 

3.4

Clintwood Elkhorn Mining

 

 

39.8

 

 

 

8.1

 

 

 

47.9

 

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

5.5

 

 

 

5.5

 

 

 

53.4

Premier Elkhorn Coal

 

 

33.4

 

 

 

36.0

 

 

 

69.4

 

 

 

10.8

 

 

 

2.0

 

 

 

12.8

 

 

 

14.7

 

 

 

2.5

 

 

 

17.2

 

 

 

99.4

Perry County Coal

 

 

0.0

 

 

 

0.0

 

 

 

0.0

 

 

 

66.0

 

 

 

38.5

 

 

 

104.5

 

 

 

19.6

 

 

 

9.7

 

 

 

29.3

 

 

 

133.8

Totals:

 

 

73.2

 

 

 

44.1

 

 

 

117.3

 

 

 

76.8

 

 

 

40.5

 

 

 

117.3

 

 

 

37.1

 

 

 

18.3

 

 

 

55.4

 

 

 

290.0

% of Totals:

 

 

 

 

 

 

 

 

 

 

40.0

%

 

 

 

 

 

 

 

 

 

 

40.0

%

 

 

 

 

 

 

 

 

 

 

20.0

%

 

 

 

Reserve Estimation Procedure

TECO Coal’s reserves are based on over 3,800 data points, including drill holes, prospect measurements and mine measurements. Reserve estimates also include information obtained from on-going exploration drilling and in-mine channel sampling programs. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. Additionally, the information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves.

This data may include elevation, thickness, and where samples are available, the quality of the coal from individual drill holes and channel samples. The information is assembled by geologists and engineers at TECO Coal, and is computer modeled from which preliminary reserve estimations are generated. The information derived from the geological database is then combined with data on ownership or control of the mineral and surface interests to determine the extent of the reserves in a given area. Determinations of reserves are made after in-house geologists have reviewed the computer generated models and enhanced the grid models to better reflect regional trends.

During TECO Coal’s reserve evaluation and mine planning, TECO Coal takes into account factors such as restrictions under railroads, roads, buildings, power lines, or other structures. Depending on these factors, coal recovery may be limited or, in some instances, entirely prohibited. Current engineering practices are used to determine potential subsidence zones. The footprint of the relevant structure, as well as a safety angle-of-draw, is considered when mining near or under such facilities. Also, as part of TECO Coal’s reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by in-house engineers, geologists and finance associates.

Item 3. LEGAL PROCEEDINGS.

From time to time, TECO Energy and its subsidiaries are 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 the company’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 Notes 12 and 9, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

31


Item 4. MINE SAFETY DISCLOSURES.

TECO Coal is subject to regulation by the MSHA under the Federal Mine Safety and Health Act of 1977 (the Mine Act). Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this annual report.

 

 

 

32


PART II

 

 

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

The following table shows the high and low sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.

 

 

 

1st Quarter

 

 

2nd Quarter

 

 

3rd Quarter

 

 

4th Quarter

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

 

$

17.31

 

 

$

18.53

 

 

$

18.48

 

 

$

21.29

 

Low

 

 

16.12

 

 

 

16.90

 

 

 

16.91

 

 

 

17.35

 

Close

 

 

17.15

 

 

 

18.48

 

 

 

17.38

 

 

 

20.49

 

Dividend

 

$

0.22

 

 

$

0.22

 

 

$

0.22

 

 

$

0.22

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

 

$

17.87

 

 

$

19.22

 

 

$

17.99

 

 

$

17.75

 

Low

 

 

16.71

 

 

 

16.40

 

 

 

16.15

 

 

 

16.40

 

Close

 

 

17.82

 

 

 

17.19

 

 

 

16.54

 

 

 

17.24

 

Dividend

 

$

0.22

 

 

$

0.22

 

 

$

0.22

 

 

$

0.22

 

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 13, 2015 was 10,844.

Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends to its common shareholders are dividends and other distributions from its operating companies.

See Liquidity, Capital Resources – Covenants in Financing Agreements section of MD&A, and Notes 6, 7 and 12 to the TECO Energy Consolidated Financial Statements for additional information regarding significant financial covenants.

All of TEC’s common stock is owned by TECO Energy and, therefore, there is no market for the stock. TEC pays dividends on its common stock substantially equal to its net income. Such dividends totaled $262.6 million in 2014, $222.1 million in 2013 and $228.3 million in 2012.

Set forth below is a table showing shares of TECO Energy common stock deemed repurchased by the issuer.

 

 

 

Total Number of

Shares (or Units)

Purchased (1)

 

 

Average Price

Paid per Share

(or Unit)

 

 

Total Number of

Shares (or Units)

Purchased as Part

of Publicly

Announced Plans or

Programs

 

 

Maximum Number

(or Approximate

Dollar Value) of

Shares (or Units) that

May Yet Be

Purchased Under the

Plans or Programs

 

Oct. 1, 2014 – Oct. 31, 2014

 

 

994

 

 

$

18.85

 

 

 

0.0

 

 

 

0.0

 

Nov. 1, 2014 – Nov. 30, 2014

 

 

6,075

 

 

$

19.82

 

 

 

0.0

 

 

 

0.0

 

Dec. 1, 2014 – Dec. 31, 2014

 

 

695

 

 

$

20.33

 

 

 

0.0

 

 

 

0.0

 

Total 4th Quarter 2014

 

 

7,764

 

 

$

19.74

 

 

 

0.0

 

 

 

0.0

 

(1)

These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.

33


Shareholder Return Performance Graph

The following graph shows the cumulative total shareholder return on TECO Energy’s common stock on a yearly basis over the five-year period ended Dec. 31, 2014, and compares this return with that of the S&P 500 Index, the S&P Multi Utility Index and the Dow Jones U.S. Coal Index. The graph assumes that the value of the investment in TECO Energy’s common stock and each index was $100 on Dec. 31, 2009 and that all dividends were reinvested.

 

 

Item 6. SELECTED FINANCIAL DATA OF TECO ENERGY

 

(millions, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended Dec. 31,

 

2014

 

 

2013

 

 

2012

 

 

2011

 

 

2010

 

Revenues (1)

 

$

2,566.4

 

 

$

2,355.1

 

 

$

2,387.7

 

 

$

2,476.9

 

 

$

2,673.5

 

Net income from continuing operations (1)

 

 

206.4

 

 

 

188.7

 

 

 

197.0

 

 

 

200.6

 

 

 

159.9

 

Net income from discontinued operations attributable to TECO Energy (1)

 

 

(76.0

)

 

 

9.0

 

 

 

15.7

 

 

 

72.0

 

 

 

79.1

 

Net income attributable to TECO Energy

 

 

130.4

 

 

 

197.7

 

 

 

212.7

 

 

 

272.6

 

 

 

239.0

 

Total assets

 

 

8,726.2

 

 

 

7,448.0

 

 

 

7,334.9

 

 

 

7,307.2

 

 

 

7,270.9

 

Long-term debt, including current portion

 

 

3,628.5

 

 

 

2,921.1

 

 

 

2,972.7

 

 

 

3,073.4

 

 

 

3,226.4

 

EPS – Basic

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

From continuing operations (1)

 

$

0.92

 

 

$

0.88

 

 

$

0.92

 

 

$

0.93

 

 

$

0.75

 

From discontinued operations attributable to TECO Energy (1)

 

 

(0.34

)

 

 

0.04

 

 

 

0.07

 

 

 

0.34

 

 

 

0.37

 

Attributable to TECO Energy

 

$

0.58

 

 

$

0.92

 

 

$

0.99

 

 

$

1.27

 

 

$

1.12

 

EPS – Diluted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

From continuing operations (1)

 

$

0.92

 

 

$

0.88

 

 

$

0.92

 

 

$

0.93

 

 

$

0.74