10-K 1 d442708d10k.htm FORM 10-K Form 10-K
Table of Contents

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, 2012   

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.

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-1111

   59-2052286

            1-5007

  

TAMPA ELECTRIC COMPANY

(a Florida corporation)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(813) 228-1111

   59-0475140

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.  [  ]

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 29, 2012 was approximately $3.85 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 29, 2012 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Feb. 15, 2013 was 217,255,694. As of Feb. 15, 2013, 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 2013 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.

Cover page of 170

Index to Exhibits begins on page 166


Table of Contents

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

capacity clause

   capacity cost-recovery clause, as established by the FPSC

CCRs

   coal combustion residuals

CERCLA

   Comprehensive Environmental Response, Compensation and Liability Act of 1980

CGESJ

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

CMMA

   Cardno MM&A

CMO

   collateralized mortgage obligation

CNG

   compressed natural gas

CPI-U

   consumer price index - all urban consumers

CO2

   carbon dioxide

CT

   combustion turbine

DECA II

   Distribución Eléctrica Centro Americana, II, S.A.

DOE

   U.S. Department of Energy

ECRC

   environmental cost recovery clause

EEGSA

   Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America

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

GHG

   greenhouse gas(es)

HCIDA

   Hillsborough County Industrial Development Authority

HPP

   Hardee Power Partners

IFRS

   International Financial Reporting Standards

IGCC

   integrated gasification combined-cycle

IOU

   investor owned utility

IRS

   Internal Revenue Service

ISDA

   International Swaps and Derivatives Association

ISO

   independent system operator

ITCs

   investment tax credits

kW

   Kilowatt(s)

kWh

   kilowatt-hour(s)

 

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LIBOR

MAP-21

  

London Interbank Offered Rate

Moving Ahead for Progress in the 21st Century Act

MARN

   Ministry of Environment, Guatemala

MBS

   mortgage-backed securities

MD&A

   Management’s Discussion and Analysis

met

   mettalurgical

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

NERC

   North American Electric Reliability Corporation

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

OATT

   open access transmission tariff

OCI

   other comprehensive income

OTC

   over-the-counter

OTTI

   other than temporary impairment

PBGC

   Pension Benefit Guarantee Corporation

PBO

   postretirement benefit obligation

PCI

   pulverized coal injection

PCIDA

   Polk County Industrial Development Authority

PGA

   purchased gas adjustment

PGS

   Peoples Gas System, the gas division of Tampa Electric Company

PPA

   power purchase agreement

PPSA

   Power Plant Siting Act

PRP

   potentially responsible party

PUHCA 2005

   Public Utility Holding Company Act of 2005

REIT

   real estate investment trust

REMIC

   real estate mortgage investment conduit

RFP

   request for proposal

ROE

   return on common equity

Regulatory ROE

   return on common equity as determined for regulatory purposes

RPS

   renewable portfolio standards

RTO

   regional transmission organization

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

TCAE

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

Tampa Electric

   Tampa Electric, the electric division of Tampa Electric Company

 

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TEC

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

TECO Diversified

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

TECO Coal

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

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.

TEMSA

   Tecnología Marítima, S.A., a provider of dry bulk and coal unloading services located in Guatemala

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

 

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PART I

Item 1.     BUSINESS.

TECO ENERGY

TECO Energy, Inc. (TECO Energy) 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 3,900 employees as of Dec. 31, 2012.

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.

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 subsidiary TECO Diversified, owns TECO Coal.

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 687,000 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 approximately 345,000 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 2012 was almost 1.9 billion therms.

TECO Coal, a Kentucky corporation, 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.

TECO Guatemala, a Florida corporation, owned subsidiaries that participated in two contracted Guatemalan power plants, Alborada and San José. These subsidiaries were sold on Sept. 27, 2012 and Dec. 19, 2012, respectively.

 

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Revenues from Continuing Operations   

 

    

 

    

 

 
(millions)    2012      2011      2010  

Tampa Electric

   $     1,981.3       $     2,020.6       $     2,163.2   

PGS

     398.9         453.5         529.9   

Total regulated businesses

   $ 2,380.2       $ 2,474.1       $ 2,693.1   

TECO Coal

     608.9         733.0         690.0   

Other and Eliminations

     7.5         2.8         (19.6

Total revenues from continuing operations

   $ 2,996.6       $ 3,209.9       $ 3,363.5   

 

 

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

Discontinued Operations/Asset Dispositions

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 the domestic electric and gas utilities.

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 sale of the San José power station and related facilities in Guatemala for a purchase price of $215.0 million.

See Notes 19, 20 and 21 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

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 2,369 employees as of Dec. 31, 2012, of which 906 were represented by the International Brotherhood of Electrical Workers and 167 were represented by the Office and Professional Employees International Union.

In 2012, approximately 48% of Tampa Electric’s total operating revenue was derived from residential sales, 31% from commercial sales, 9% from industrial sales and 12% from other sales, including bulk power sales for resale. Approximately 5% of revenues were attributable to governmental municipalities. The sources of operating revenue and MWH sales for the years indicated were as follows:

 

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Operating Revenue                        
(millions)    2012      2011      2010  

Residential

   $ 958.9       $ 994.7       $ 1,100.0   

Commercial

     612.3         612.6         648.4   

Industrial – Phosphate

     75.7         62.0         84.2   

Industrial – Other

     101.2         99.3         103.7   

Other retail sales of electricity

     184.0         185.2         191.6   

Total retail

     1,932.1         1,953.8         2,127.9   

Sales for resale

     16.2         21.7         41.6   

Other

     33.0         45.1         (6.3

Total operating revenues

   $     1,981.3       $     2,020.6       $     2,163.2   

 

 

Megawatt-hour Sales

                          

(thousands)

     2012         2011         2010   

Residential

     8,395         8,718         9,185   

Commercial

     6,185         6,207         6,221   

Industrial

     2,002         1,804         2,010   

Other retail sales of electricity

     1,827         1,835         1,797   

Total retail

     18,409         18,564         19,213   

Sales for resale

     267         352         516   

Total energy sold

     18,676         18,916         19,729   

 

 

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 operation and maintenance 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 rates and allowed ROE range of 10.25% to 12.25%, with a midpoint of 11.25%, which were established in 2009, are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC or other interested parties.

Tampa Electric’s 2012 results reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE mid-point of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for combustion turbines and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

As a result of increasing pressure on O&M expense, higher depreciation expense from required infrastructure added to serve customers, and an economic recovery that has been slower than expected compared to the assumptions in Tampa Electric’s last base rate proceeding in 2009, on Feb. 4, 2013, Tampa Electric notified the FPSC that it is planning to file a new base rate proceeding in April for new rates effective in early 2014. The actual revenue requirement calculation is not final, but is estimated to be approximately $135 million.

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.

In July 2010, Tampa Electric filed transmission rate and wholesale requirements cases with the FERC. Tampa Electric’s last wholesale requirements rate case was filed in 1991 and the associated service agreements were approved by the FERC in the mid-1990s.

 

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The transmission rate case updated Tampa Electric’s charges under its FERC-approved OATT for the various forms of wholesale transmission service it provides. These rates were last updated in 2003, pursuant to a settlement agreement between the company and its then transmission customers. The wholesale requirements rate proceeding addressed the rates and terms and conditions of Tampa Electric’s existing wholesale customers.

The FERC approved Tampa Electric’s proposed transmission rates as filed with the FERC, which became effective Sept. 14, 2010, subject to refund. The FERC also approved Tampa Electric’s proposed wholesale requirements rates, as filed with the FERC, which became effective March 1, 2011, subject to refund. The proposed and ultimately accepted wholesale requirements and transmission rates did not have a material impact on Tampa Electric’s results.

Settlements were reached with the applicable customers in both cases during 2011 and filed with the FERC during the first quarter of 2012. The FERC accepted these settlements as filed, and the settlements took effect during the latter part of 2012. Refunds with interest were provided to the customers last year for the differences between the settlement rates and the charges that were earlier approved by the FERC to be implemented conditionally.

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.

On Nov. 6, 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. This is considered a routine audit by the FERC staff, though it has been approximately 20 years since Tampa Electric last had a FERC accounting audit.

Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Matters section).

Competition

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

Unlike 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. Over the past three years, gross revenues from wholesale sales, which include fuel that is a pass-through cost, have averaged approximately 1% of Tampa Electric’s total revenue.

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.

Fuel

Approximately 61% of Tampa Electric’s generation of electricity for 2012 was coal-fired, with natural gas representing approximately 39% and oil representing less than 1%. Tampa Electric used its generating units to meet approximately 94% of the total system load requirements, with the remaining 6% 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:

 

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Average cost per MMBTU    2012      2011      2010      2009      2008  

Coal

   $ 3.57       $ 3.46       $ 3.08       $ 3.05       $ 2.91   

Oil

     25.88         21.21         16.43         16.01         20.48   

Gas (Natural)

     5.34         6.20         6.74         8.00         10.61   

Composite

     4.19         4.38         4.46         5.02         5.56   

Average cost per ton of coal burned

         84.59             83.17             74.80             72.98             69.14   

 

 

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 and was placed on long-term standby in September 2009.

Coal. Tampa Electric burned approximately 4.7 million tons of coal and petroleum coke during 2012 and estimates that its combined coal and petroleum coke consumption will be about 4.8 million tons in 2013. During 2012, Tampa Electric purchased approximately 80% of its coal under long-term contracts with four suppliers, and approximately 20% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 71% of its coal and petroleum coke requirements in 2013 under long-term contracts with four suppliers and the remaining 29% 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 2012, approximately 86% of Tampa Electric’s coal supply was deep-mined, approximately 8% 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, 2012, approximately 65% of Tampa Electric’s 1,250,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 70% of its expected gas needs for the April 2013 through October 2013 period. In early March 2013, to meet its generation requirements, Tampa Electric expects to issue RFPs to meet its remaining 2013 gas needs and begin contracting for its 2014 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, based on judicial precedent, if the franchise agreement is not renewed, Tampa Electric would be able to continue to use public rights-of-way within the municipality, 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 September 2040.

Franchise fees payable by Tampa Electric, which totaled $44.3 million at Dec. 31, 2012, 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. Tampa Electric Company, through its Tampa

 

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Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites.

Emission Reductions

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

Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S. Department of Justice and the FDEP, signed a Consent Decree, as settlement of federal and state litigation to dramatically decrease emissions from its power plants. Tampa Electric has notified the parties that all obligations of the Consent Decree have been fulfilled and intends to file documents with the court to terminate the Consent Decree in 2013.

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

As a result of the actions taken under the consent decree, emissions of all pollutant types have been significantly reduced. Since 1998, Tampa Electric has reduced annual SO2, NOx and PM emissions from its facilities by 164,000 tons (94%), 63,000 tons (91%) and 4,500 tons (87%), respectively.

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

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system-wide emissions of CO2 by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO2 to remain near 1990 levels until the addition of the next baseload unit, which is scheduled to be in service in January 2017 (see the Tampa Electric and Capital Expenditures sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO2 emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 25%.

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric division, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2012, TEC has estimated its ultimate financial liability to be approximately $37.5 million (primarily related to PGS), and this amount has been reflected in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices. The amounts represent only the estimated portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on actual estimates obtained from contractors or TEC’s experience with similar work, adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among TEC and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, TEC’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered credit-worthy.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulation, these additional costs would be eligible for recovery through customer rates.

 

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Capital Expenditures

Tampa Electric’s 2012 capital expenditures included approximately $23 million 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 approximately 345,000 customers. The system includes approximately 11,200 miles of mains and 6,600 miles of service lines (see PGS’s Franchises and Other Rights section below).

PGS had 535 employees as of Dec. 31, 2012. A total of 142 employees in six of PGS’s 14 operating divisions are represented by various union organizations.

In 2012, the total throughput for PGS was almost 1.9 billion therms. Of this total throughput, 6% was gas purchased and resold to retail customers by PGS, 82% was third-party supplied gas that was delivered for retail transportation-only customers and 12% was gas sold off-system. Industrial and power generation customers consumed approximately 74% of PGS’s annual therm volume, commercial customers consumed approximately 23%, off-system sales customers consumed 12% 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 32% 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 13 compressed natural gas stations connected to the PGS distribution system.

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

 

      Revenues      Therms  
(millions)    2012      2011      2010      2012      2011      2010  

Residential

   $ 125.4       $ 140.8       $ 159.5         70.8         77.7         90.5   

Commercial

     134.1         138.0         143.8         421.4         409.3         407.9   

Industrial

     84.0         114.8         171.2         461.3         436.0         507.2   

Power generation

     12.4         10.6         9.7         913.5         614.3         582.2   

Other revenues

     34.9         39.9         37.2            

 

 

Total

   $     390.8       $     444.1       $     521.4         1,867.0         1,537.3         1,587.8   

 

 

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.

On May 5, 2009, the FPSC approved a base rate increase of $19.2 million which became effective on Jun. 18, 2009 and

 

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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.

As a result of the unprecedented cold winter weather in 2010, in the second quarter of 2010, PGS projected it would earn above the top of its ROE range of 11.75% in 2010. PGS recorded a $9.2 million pretax total provision related to the 2010 earnings above the top of the range. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement requesting Commission approval that $3.0 million of the provision be refunded to customers in the form of a credit on customers’ bills in 2011, and the remainder be applied to accumulated depreciation reserves. On Jan. 25, 2011 the FPSC approved the stipulation.

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 2012, the FPSC approved rates under PGS’s PGA clause for the period January 2013 through December 2013 for the recovery of the costs of natural gas purchased for its distribution customers.

In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates the programs are cost effective for its ratepayers. 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, 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.

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 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 19,500 transportation-only customers as of Dec. 31, 2012 out of approximately 35,000 eligible customers.

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

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 65 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville division receives gas delivered by the Southern Natural Gas pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline provides delivery through seven gate stations. PGS also has one interconnection with its affiliate SeaCoast Gas Transmission, LLC 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

 

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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 109 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 2041. PGS expects to negotiate 6 franchises in 2013, the majority of which will be renewals of existing agreements. Franchise fees payable by PGS, which totaled $7.9 million at Dec. 31, 2012, 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.

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 the previous discussion in the Environmental Matters section of Tampa Electric – Electric Operations.

Merco Group at Aventura Landings v. Peoples Gas System

In 2004, Merco Group at Aventura Landings I, II and III (Merco) filed suit against PGS in Dade County Circuit Court alleging that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco was seeking damages for costs associated with the removal of such coal tar and from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS denied liability on the grounds that the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, PGS filed a counterclaim against Merco which claimed that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and, in June 2012, prior to receiving a ruling by the Judge, PGS and Merco settled the case, and PGS and Continental Holdings, Inc. agreed to a release for their claims against each other in the case. Both agreements have been approved by the court. The settlement is reflected as a regulatory asset at Dec. 31, 2012 and is expected to be recovered through the regulatory process. The settlement did not impact the results of operations for the year ended Dec. 31, 2012 and is not material to the financial position of TEC or TECO Energy as of Dec. 31, 2012.

Capital Expenditures

During the year-ended Dec. 31, 2012, PGS did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2013 through 2017 period.

 

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TECO COAL

Overview

TECO Coal, with offices located in Corbin, Kentucky, is a wholly owned subsidiary of TECO Energy, Inc. and through its subsidiaries operates 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 44% of TECO Coal’s 2012 coal sales volume. Steam coal accounted for approximately 56% of 2012 coal sales volume.

As of Dec. 31, 2012, TECO Coal owned or leased mineral rights to approximately 310.9 million tons of proven and probable coal reserves. Of the total proven and probable reserves, approximately 78% are low sulfur reserves with high BTU content. Total proven and probable reserves are expected to support current production levels for more than 20 years.

The tons sold for 2012, 2011 and 2010 by market category is set forth in Table 1 below:

Coal Sales By Market Category

(Millions of Tons)

Table 1

 

     Metallurgical, PCI & Stoker    Steam

Year

   Tons    % Volume    Tons    % Volume

2012

   2.75    44%    3.53    56%

2011

   3.71    46%    4.42    54%

2010

   3.48    40%    5.21    60%

Sales of steam coal during 2012, 2011 and 2010 were made primarily to utilities and industrial customers throughout the eastern part of the United States. Sales of metallurgical and PCI coal during those years were made primarily to steel companies and coke plants in North America and Europe.

TECO Coal currently operates 16 underground mines, which employ the room and pillar mining method, and seven surface mines.

In 2012, TECO Coal sold 6.3 million tons of coal. All of this coal was sold to customers other than the TECO Coal affiliate, Tampa Electric.

No significant part of TECO Coal’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, and the business is not highly seasonal.

History

In 1967, Cal-Glo Coal Company was formed. It mined a product containing low sulfur, low ash fusion characteristic and high energy content. Realizing the potential for this product to meet its combustion, quality, and environmental requirements, Tampa Electric purchased Cal-Glo Coal Company in 1974. In 1982, after several years of continued growth and success, TECO Coal Corporation was formed and Cal-Glo Coal Company was renamed as Gatliff Coal Company. Rich Mountain Coal Company was established in 1987, when leases were signed for properties in Campbell County, Tennessee.

In 1988, Gatliff Coal Company began selling coal to the ferro-silicon and silicon markets. Also in that year, properties were acquired in Pike County, Kentucky, and Clintwood Elkhorn Mining Company was formed. Premier Elkhorn Coal Company and Pike-Letcher Land Company were formed in 1991, when additional property was acquired in Pike and Letcher Counties, Kentucky.

In 1997, Bear Branch Coal Company secured key leases for properties located in Perry County and Knott County, Kentucky.

The newest mining company in the TECO Coal family is Perry County Coal Corporation, which was purchased in 2000 and is located in Perry, Knott and Leslie Counties, Kentucky.

 

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Mining Operations

TECO Coal currently has four mining complexes, all operating in Kentucky, with a portion of Clintwood Elkhorn Mining Company operating in Virginia as well. A mining complex is defined as all mines that supply a single wash plant, except in the case of Clintwood Elkhorn Mining Company, which provides production for two active wash plants. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as eleven individual underground or surface mines. TECO Coal uses two distinct extraction techniques: continuous underground mining and dozer and front-end loader surface mining, sometimes accompanied by highwall mining.

The complexes have been developed at locations in close proximity to the TECO Coal preparation plants and rail shipping facilities. Coal is transported from TECO Coal’s mining complexes to customers by means of railroad cars, trucks, barges or vessels, with rail shipments representing approximately 95% of 2012 coal shipments. The following map shows the locations of the four mining complexes and TECO Coal’s offices in Corbin, Kentucky.

 

LOGO

Facilities

Coal mined by the operating companies of TECO Coal is processed and shipped from facilities located at each of the operating companies, with Clintwood Elkhorn Mining Company having two facilities. The equipment at each facility is in good condition and regularly maintained by qualified personnel. Table 2 below is a summary of TECO Coal processing facilities:

Processing Facilities Summary

Table 2

 

 

COMPANY

 

  

 

FACILITY

 

 

 

LOCATION

 

  

 

RAILROAD SERVICE

 

  

 

UTILITY SERVICE

 

         

Gatliff Coal

   Ada Tipple   Himyar, KY    CSXT Railroad    RECC
         

Clintwood Elkhorn

   Clintwood #2 Plant   Biggs, KY    Norfolk Southern    American Electric Power
         

Clintwood Elkhorn

   Clintwood #3 Plant   Hurley, VA    Norfolk Southern    American Electric Power
         

Premier Elkhorn

   Burke Branch Plant   Myra, KY    CSXT Railroad    American Electric Power
         

Perry County Coal

   Davidson Branch Plant   Hazard, KY    CSXT Railroad    American Electric Power

 

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Significant Projects

    Significant projects for 2012 included the following:

Premier Elkhorn Coal

 

   

Premier Elkhorn continued exploration operations in 2012 of the 65 million tons of the metallurgical coal discovered in 2011 in two below drainage seams underlying its current Burke Branch facilities and adjacent properties (See New Frontier Project – Burke Branch Development below). Premier Elkhorn also performed evaluation of the newly discovered reserves and continued permitting for the construction phases of the project for slope and shaft construction. Much of the identified reserves are owned by TECO Coal.

Clintwood Elkhorn Mining

 

   

Completed ventilation construction required to add second unit of production equipment at the Hubble #11 deep mine to increase production of High Volatile A metallurgical coal

 

   

Completed surface construction to access metallurgical reserves that will report to the Clintwood #2 plant when activated

 

   

Completed surface construction of Abners Fork deep mine face up in Virginia, which will produce High Volatile A metallurgical coal when activated

 

   

Granted Surface Mining Control and Reclamation Act of 1977 (SMRCA) permit for extension of Laurel Branch surface mine in Virginia, which produces metallurgical and steam coal. The new permit extends the life of the project by approximately three years

 

   

Core drilling in the Woodman area of northern Pike County, Kentucky resulted in additional metallurgical and steam reserves being proven

 

   

Exploration in Virginia resulted in additional reserves to be mined by surface methods for the metallurgical and steam markets

 

   

In Kentucky, a coarse refuse belt was extended at the Clintwood #2 plant, resulting in cost savings

Mining Complexes

Table 3 below shows annual production for each mining complex for each of the last three years and 2012 coal sales.

 

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MINING COMPLEXES

Table 3

 

                       

Tons Produced

(in Millions)

    

Tons Sold (1)

(in Millions)

    

Year
Established

Or

Acquired

 
Location   

Mine

Type

   Mining
Equipment
   Transportation    2012      2011      2010      2012     

   Gatliff Coal Co.

                       

  Bell County, KY/

  Knox County, KY/

  Campbell County, TN

 

   S    D/L    T      0.0         0.0         0.0         0.0         1974   

  Clintwood Elkhorn Mining

                       

  Pike County, KY/

  Buchanan County, VA

 

   U, S    CM, D/L,

HM, A

   R, R/V      2.0         1.8         2.1         1.9         1988   

  Premier Elkhorn Coal Co.

                       

  Pike County, KY/

  Letcher County, KY/

  Floyd County, KY

 

   U, S    CM, D/L    R, T, R/B,
T/B, R/V
     2.0         2.2         2.6         2.1         1991   

  Perry County Coal Co.

                       

  Perry County, KY/

  Leslie County, KY/

  Knott County, KY

 

   U, S    CM, D/L,

HM

   R, T, R/B,

T/B, R/V

     2.3         3.1         3.1         2.3         2000   
         Totals:      6.3         7.1         7.8         6.3      

 

  (1) Tons sold include both amounts produced by TECO Coal subsidiaries and a limited amount of purchased coal.

S – Surface

CM – Continuous Miner

U – Underground

D/L – Dozers and Front-End Loaders

HM – Highwall Miner

A – Auger

R – Rail

R/B – Rail to Barge

R/V – Rail to Ocean/Lake Vessel

T – Truck

T/B – Truck to Barge

Gatliff Coal

Gatliff Coal Company discontinued surface mine operations in Bell County, Kentucky in late autumn 2009. Poor market conditions and a depletion of the low sulfur content coal that was previously required on its sales contract led to this cessation of mining operations. Gatliff Coal had no production in 2010, 2011 or 2012, leaving a reserve base of 3.4 million recoverable tons of predominantly low sulfur underground mineable coal, which may later be recovered by Gatliff Coal or by neighboring competing coal companies for coal royalty considerations. Rich Mountain Coal Company formerly operated as a contractor for Gatliff Coal’s Tennessee production but is currently in non-producing reclamation status.

Clintwood Elkhorn Mining

Clintwood Elkhorn Mining Company has two coal preparation facilities. One is located near Biggs, Kentucky in Pike County, and is supplied by eight underground mines and no surface mines. The second Clintwood Elkhorn Mining facility is located near Hurley, Virginia and is supplied by one underground mine and two surface mines. Some mines have supplied both locations during the course of the year. Principal products at both locations include High Volatile metallurgical coal and steam coal. Products from both locations are shipped domestically to customers in North America via Norfolk Southern Corporation and vessels via the Great Lakes. International customers receive their products via ocean vessels from Lamberts Point, Virginia. During 2012, a block of

 

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reserves containing 6.9 million tons previously classified as PCI coal, and now metallurgical, was assigned from Premier Elkhorn Coal Company to Clintwood Elkhorn Mining. CMMA completed an audit for new coal Clintwood Elkhorn now controls. CMMA has estimated by audit methodology that there are 8.5 million tons of recoverable tons of demonstrated coal reserves, as of December 31, 2012. Of the new demonstrated reserves, an estimated 7.3 million recoverable tons, or 86%, are of proven (measured) status and 1.2 million tons, or 14%, are of probable (indicated) status. All of the new reserves are leased. By market category, the new demonstrated reserves are: 6.2 million tons of metallurgical coal, 0 tons of PCI coal; and 2.3 million tons of steam coal. In total, Clintwood Elkhorn Mining produced 2.0 million tons of coal in 2012, and currently has a reserve base of 60.8 million recoverable tons.

Premier Elkhorn Coal Company

Located near Myra, in Pike County, Kentucky, Premier Elkhorn Coal Company is supplied by production from four underground mines and three surface mines. Principal products include metallurgical and PCI coal for the steel mills, high-quality steam coal for utilities and specialty stoker products for ferro-silicon and industrial customers. Facilities include a unit train load-out with a 200 car siding capable of loading at 6,000 tons per hour. Products from this location are shipped via CSXT Railroad and trucking contractors to destinations in North America and internationally. During 2012, a block of reserves containing 6.9 million tons previously classified as PCI coal was assigned from Premier Elkhorn Coal Company to Clintwood Elkhorn Mining. CMMA completed a comprehensive audit of the demonstrated coal reserves and non-coal deposits controlled by TECO Coal at the Premier Elkhorn Coal operating subsidiary. CMMA has estimated by audit methodology that TECO Coal controls an estimated 109.6 million recoverable tons of demonstrated coal reserves at Premier Elkhorn as of Dec. 31, 2012. Of the total demonstrated reserves, an estimated 67.7 million recoverable tons, or 62%, are of proven (measured) status and 41.9 million tons, or 38%, are of probable (indicated) status. Also, of the total demonstrated reserves, an estimated 85.6 million recoverable tons, or 78%, are owned and 24.0 million tons, or 22%, are leased. By market category, the Premier Elkhorn demonstrated reserves are 70.9 million tons of metallurgical coal, 18.8 million tons of PCI coal, and 19.9 million tons of steam coal. In total, Premier Elkhorn Coal produced 2.0 million tons of coal in 2012, and currently has a reserve base of 109.6 million recoverable tons.

New Frontier Project-Burke Branch Development

In 2011, CMMA completed an audit of the Glamorgan and Lower Banner coal deposits associated with the New Frontier Project-Burke Branch Development, which is controlled by TECO Coal’s Premier Elkhorn Coal operating subsidiary. The subject property is located in Pike and Letcher Counties in eastern Kentucky, and a substantial portion of the mineral rights for the subject coal deposits is owned by TECO Coal’s subsidiary, Pike-Letcher Land. The remainder of the mineral is leased from other entities under long-term lease agreements.

The CMMA audit reviewed the classification of the TECO Coal tons by proven and probable reserves and non-reserve coal deposit (resource) categories, based on a pro-forma economic review of the demonstrated reserve areas. TECO Coal estimates that it controls 65.0 million recoverable tons of demonstrated coal reserves within the Burke Branch Development, as of Aug. 31, 2011. Of these TECO Coal total demonstrated reserves, an estimated 56.6 million recoverable tons, or 87%, are owned and 8.4 million tons, or 13%, are leased. An additional 23.4 million tons have been estimated by TECO Coal and classified as non-reserve coal deposits (resources). These resource tons have some potential to be reclassified as reserve in the future depending on various factors such as favorable results of additional exploration, property acquisition, investment of capital for project development, improvements in coal markets or mining technology.

TECO Coal has received an amendment to an existing permit to allow surface excavation and development as well as slope access to a portion of these reserves and a revision to an existing permit to allow mining of a portion of the Lower Banner coal seam reserves. An additional amendment has been submitted to modify surface areas required for development of the slopes and shafts.

Perry County Coal Corporation

Located in Perry County, Kentucky, near Hazard, Perry County Coal Corporation is supplied by production from three underground mines and two surface mines. Principal products include PCI, high quality steam coal for utilities, and industrial stoker products. Facilities include a 1,350 ton per hour preparation plant and a unit train load-out. Products from this location are shipped via CSXT Railroad and trucking contractors.

In 2009, Perry County Coal completed a comparable trade of underground reserves, with another mining company, of 16.0 million tons. During 2010, the boundary of reserves for the E4-2 mine area was core drilled to confirm final reserve quantities and qualities and to finalize a comprehensive mining plan. A review of reserves for the E4-2 mine area for Perry County Coal proved an additional 6.9 million tons of reserves which were previously reported as resource coal. In 2010, Perry County Coal leased the First Creek reserve which is contiguous to its existing E4-1 underground mine. This lease will facilitate the mining of approximately 10.0 million tons of additional reserves. Perry County Coal produced 2.3 million tons of coal in 2012, leaving a total reserve base of 137.1 million recoverable tons.

 

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Sales and Marketing

The TECO Coal marketing and sales force includes sales directors, distribution/transportation managers and administrative personnel. Primary customers are steel companies, utilities and industrial plants. TECO Coal sells coal under long-term agreements, which are generally classified as greater than 12 months, and on a spot basis, which is generally classified as 12 months or less.

The terms of these coal sales contracts result from bidding and negotiations with customers. Consequently, these contracts typically vary significantly in price, quantity, quality, length, and may contain terms and conditions that allow for periodic price reviews, price adjustment mechanisms, recovery of governmental impositions as well as provisions for force majeure, suspension, termination, treatment of environmental legislation and assignment.

Current sales are made to both domestic and European markets, and the metallurgical coal from the Burke Branch Development is expected to be marketed to new markets and customers in Europe, South America and Asia.

Distribution

TECO Coal transports coal from its mining complexes to customers by rail, barge, vessel and trucks. The company employs transportation specialists who coordinate the development of acceptable shipping schedules with our customers, transportation providers and mining facilities.

Competition

Primary competitors of TECO Coal are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. To date, TECO Coal has been able to compete for coal sales by mining specialty coals, including coals used for making coke and furnace injection, and high-quality steam coal and by effectively managing production and processing costs.

Employees

As of Dec. 31, 2012, TECO Coal and its subsidiaries employed a total of 811 employees.

Regulations

Mine Safety and Health

The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1969, the 1977 Amendment and the Miner Act of 2006. TECO Coal’s subsidiaries are also subject to various Kentucky, Tennessee and Virginia mining laws which require approval of roof control, ventilation, dust control and other facets of the coal mining business. Federal and state inspectors inspect the mines to ensure compliance with these laws. TECO Coal believes it is in substantial compliance with the standards of the various enforcement agencies. It is unaware of any mining laws or regulations that would materially affect the market price of coal sold by its subsidiaries, although recent mining accidents within the industry could lead to new legislation that could impose additional costs on TECO Coal.

Black Lung Legislation

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must make payment of federal black lung benefits to claimants who are current and former employees, certain survivors of a miner who dies from black lung disease, and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1973. Historically, a small percentage of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. The trust fund is funded by an excise tax on coal production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

In December 2000, the Department of Labor issued new amendments to the regulations implementing the federal black lung laws that, among other things, establish a presumption in favor of a claimant’s treating physician, limit a coal operator’s ability to introduce medical evidence, and redefine Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease. These changes in the regulations, and regulations introduced by the 2010 Patient Protection and Affordability Care Act, will increase the percentage of claims approved and the overall cost of Black Lung to coal operators. TECO Coal, with the help of its consulting actuaries, intends to continue monitoring claims very closely.

 

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Workers’ Compensation

TECO Coal is liable for workers’ compensation benefits for traumatic injury and occupational exposure claims under state workers’ compensation laws. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment.

Environmental Laws

Surface Mining Control and Reclamation Act

Coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $0.135 and $0.315 on every net ton of underground and surface coal mined, respectively, to create a fund for reclaiming land and water adversely affected by past coal mining. Other provisions establish standards for the control of environmental effects and reclamation of surface coal mining and the surface effects of underground coal mining and requirements for federal and state inspections.

Clean Air Act/Clean Water Act

While conducting their mining operations, TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards. In 2012, TECO Coal had expenditures of approximately $3.1 million for environmental protection and reclamation programs. TECO Coal expects to spend approximately $2.8 million on these programs in 2013.

CERCLA (Superfund)

The CERCLA – commonly known as Superfund, affects coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.

Under EPA’s Toxic Release Inventory process, companies are required to report annually listed toxic materials that exceed defined quantities.

Glossary of Selected Mining Terms

Assigned reserves. Coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others.

Bituminous Coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 BTU per pound. It is dense and often has well-defined bands of bright and dull material.

BTU (British Thermal Unit). A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.

Central Appalachia. Coal producing regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

Coal washing. The process of removing impurities, such as ash and sulfur based compounds, from coal.

Compliance coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million BTUs, which is equivalent to 0.72% sulfur per pound of 12,000 BTU coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.

Continuous miner. A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

Continuous mining. One of two major underground mining methods now used in the United States. This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls onto a conveyor for

 

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removal to a shuttle car or larger conveyor belt system.

Deep mine. An underground coal mine.

Dozer and Front-end loader mining. An open-cast method of mining that uses large dozers together with trucks and loaders to remove overburden, which is used to backfill pits after coal removal.

Ferro-silicon. An alloy of iron and silicon used in the production of carbon steel.

Force Majeure. An event that may prevent the company from conducting its mining operations in whole or in part as a result of: Acts of God, wars, riots, fires, explosions, breakdowns or accidents; strikes, lockouts or other labor difficulties; lack or shortages of labor, materials, utilities, energy sources; compliance with governmental rules, regulations or other governmental requirements; or any other like causes.

High Vol Metallurgical coal. Coal that averages approximately 35% volatile matter. Volatile matter refers to a constituent that becomes gaseous when heated to certain temperatures.

Highwall miner. An auger-like apparatus that drives parallel rectangular entries from the surface up to 1,000 feet deep.

Industrial coal. Coal used by industrial steam boilers to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

Long-term contracts. Contracts with terms greater than 12 months.

Low ash fusion. Coal that when burned typically produces ash that has a melting point below 2,450 degrees Fahrenheit.

Low Sulfur coal. Coal that when burned emits 1.6 pounds or less of sulfur dioxide per million BTUs.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality, composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal has a particularly high BTU, but low ash content.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Overburden ratio. The amount of overburden commonly stated in cubic yards that must be removed to excavate one ton of coal.

Pillar. An area of coal left to support the overlying strata in a mine, sometimes left permanently to support surface structures.

Pneumoconiosis. A lung disease caused by long-continued inhalation of mineral or metallic dust.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

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

Proven (Measured) reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings 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.

Pulverized Coal Injection (PCI). A system whereby coal is pulverized and injected into blast furnaces in the production of steel and/or steel products.

Reclamation. The process of restoring land and the environment to their approximate original state following mining activities. The

 

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process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Recoverable reserves. 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 and under current law.

Reserves. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

Resource (non-reserve coal deposit). A coal-bearing body that does not qualify as a commercially viable coal reserve. Resources may be classified as such by either limited property control, geologic limitations, insufficient exploration or other limitations. In the future, it is possible that portions of the resource could be re-classified as reserve if those limitations are removed or mitigated by: improving market conditions, additional property control, favorable results of exploration, advances in technology, etc.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “top.”

Room and pillar mining. In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed and connect them by driving crosscuts, leaving a series of rectangular pillars or columns of coal to help support the mine roof and control the flow of air. As mining advances, a grid-like pattern of entries and pillars is formed. Additional coal may be recovered from the pillars as this panel of coal is retreated.

Spot market. Sales of coal under an agreement for shipments over a period of one year or less.

Steam coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Sulfur content. Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but is typically used to describe coal consisting of 1.0% or less sulfur. A majority of TECO Coal’s Central Appalachian reserves are of low sulfur grades.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.

Tipple. A structure that facilitates the loading of coal into rail cars.

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.

Unassigned reserves. Coal that has not been committed and that would require new mineshafts, mining equipment or plant facilities before operations could begin in the property.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

Unit train. A train of a specified number of cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

Utility coal. Coal used by power plants to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

 

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TECO GUATEMALA

TECO Guatemala, a wholly-owned subsidiary of TECO Energy, had subsidiaries with interests in independent power projects in Guatemala, which were sold during 2012.

TECO Guatemala indirectly owned 100% of CGESJ, the owner of an electric generating station located in Guatemala, which consisted of a single-unit pulverized-coal baseload facility (the San José Power Station). This facility was the first coal-fueled plant in Central America and meets environmental standards set by Guatemala and the World Bank. In 1996, CGESJ signed a U.S. dollar-denominated PPA with EEGSA, the largest private distribution company in Central America, to provide 120 MW of capacity and energy for 15 years beginning in 2000. TEMSA, an indirect wholly-owned subsidiary, provided unloading services to third parties in addition to receiving the coal shipments for CGESJ.

TCAE, an entity 96.06% owned by TPS Guatemala One, Ltd., an indirect subsidiary of TECO Guatemala, and the owner of an oil-fired electric generating facility (the Alborada Power Station), had a U.S. dollar-denominated PPA with EEGSA to provide 78 MW of capacity ending in 2015. EEGSA was responsible for providing the fuel for the power station, with a subsidiary of TECO Guatemala providing assistance in fuel administration.

TECO Guatemala’s plants in Guatemala operated under environmental permits issued by the local environmental authorities. The plants were built in compliance with World Bank Guidelines of 1988 and 1994, at the time of construction of these facilities.

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, 20 and 21 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

While TECO Energy and its subsidiaries will no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala in October 2010 under the Dominican Republic Central America – United States Free Trade Agreement (DR – CAFTA).

 

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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.

 

Name

   Age   

Current Positions and Principal

Occupations During The Last Five Years

John B. Ramil    57   

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    53   

Senior Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc., and General Counsel of Tampa Electric Company, February 2009 to date; Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc. and General Counsel of Tampa Electric Company, July 2007 to February 2009.

Phil L. Barringer    59   

Senior Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., January 30, 2013 to date; Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., January 1, 2013 to January 30, 2013; Vice President-Human Resources of TECO Energy, Inc. and Tampa Electric Company, July 2009 to November 2012; and prior thereto, Vice President-Controller, Operations of TECO Energy, Inc. and Chief Accounting Officer of Tampa Electric Company.

Deirdre A. Brown    52   

Senior Vice President of Corporate Strategy and Technology and Chief Ethics and Compliance Officer, TECO Energy, Inc., January 30, 2013 to date, Vice President; of Corporate Strategy and Technology and Chief Ethics and Compliance Officer, TECO Energy, Inc., January 1, 2013 to January 30, 2013; Vice President-Business Strategy and Compliance and Chief Ethics and Compliance Officer, TECO Energy, Inc., July 2009 to January 1, 2013; Vice President-Regulatory Affairs of Tampa Electric Company and Vice President-Customer Service, Tampa Electric Division of Tampa Electric Company, April 2006 to July 2009.

Sandra W. Callahan    60   

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; Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., October 2009 to February 2011; Vice President-Finance and Accounting and Chief Financial Officer (Treasurer and Chief Accounting Officer), TECO Energy, Inc. and Tampa Electric Company, July 2009 to October 2009; Vice President-Treasury and Risk Management (Treasurer and Chief Accounting Officer), TECO Energy, Inc., January 2007 to July 2009; Vice President-Treasurer and Assistant Secretary, Tampa Electric Company, April 2005 to July 2009.

Gordon L. Gillette    53   

President, Tampa Electric Company, July 2009 to date; Executive Vice President and Chief Financial Officer, TECO Energy, Inc., July 2004 to July 2009; President, TECO Guatemala, October 2004 to July 2009.

Clark Taylor    63   

President of TECO Coal Corporation, April 2011 to date; and prior thereto, Vice President-Controller of 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 May 1, 2013, and until such officer’s successor is elected and qualified.

 

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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 Tampa Electric’s service area and Florida is important to the realization of annual energy sales growth for Tampa Electric and PGS. Any weakening of economic conditions, including the Florida housing markets and general economy, could adversely affect Tampa Electric’s or PGS’s expected performance. Weak economic conditions could affect these companies’ ability to collect payments from customers.

TECO Coal is also affected by general economic conditions effecting primarily the utility and steel industries, both nationally and internationally. TECO Coal sells metallurgical coal internationally, but primarily to European customers and demand in that continent has been reduced due to the European debt crisis and the resulting economic weakness. Continued economic weakness and the resulting lower demand for metallurgical coal in the European market could reduce TECO Coal’s financial results.

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

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

Tampa Electric has announced plans to file a base rate proceeding in 2013 for new rates in 2014. Our financial position could be weaker after 2013 if the FPSC were to not grant the base rate relief requested.

Tampa Electric has notified the FPSC that its actual earned ROE could be as low as 7% in 2014, well below the bottom of the allowed ROE range of 10.25% to 12.25%, without base rate relief effective in 2014. If the FPSC does not grant adequate rate relief our financial position would be weakened in 2014, as Tampa Electric enters the period of peak capital spending on its next generation expansion project (see the Liquidity and Capital Resources – Capital Expenditures section of Managements Discussion & Analysis section).

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.

Potential new regulations on the disposal and/or storage of coal combustion residuals (CCR) could add to Tampa Electric’s operating costs.

In response to a coal ash pond failure in December 2008, the EPA proposed new regulations for the management and disposal of CCRs. These proposed rules include two potential designations of CCRs. One designation would categorize CCRs destined for disposal as hazardous wastes. This designation is the most significant for Tampa Electric because hazardous waste landfills are currently prohibited in Florida by state law. CCRs designated as hazardous waste destined for disposal would have to be shipped out of state as hazardous waste at significantly increased costs. In addition, the hazardous designation could require improvements to Tampa Electric’s current ash management practices and interim storage and handling facilities for CCRs inside its power stations, even though permanent onsite disposal would not be allowed. The other proposed rule would set minimum standards for the final disposal of CCRs under regulations similar to those in place for municipal non-hazardous solid waste. This proposal would not be as disruptive as the former, since it would allow for the continued operation of Tampa Electric’s existing, lined ash ponds. However, this latter proposal would place additional management requirements on these existing disposal units, which would eventually reach the end of their useful life and need to be replaced.

Required changes would include disposing of any CCR as hazardous waste, which would be at a cost significantly higher than current costs, converting to dry handling of coal ash, and elimination of any wet storage impoundments in current use. If the EPA eliminates the use of ponds for by-product storage, Tampa Electric would have to invest in dry handling and

 

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storage, which could increase costs.

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 and state level, none have 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 conventional coal-fired units such as Tampa Electric’s Big Bend units.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new 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 predict whether the FPSC would grant such recovery.

In the case of TECO Coal, the use of coal to generate electricity is considered a significant source of GHG emissions. New regulations, depending on final form, could cause the consumption of coal to decrease or the cost of sales to increase, which could negatively impact TECO Coal’s earnings.

Among other rules, the EPA has proposed a number of new rules, including the Clean Air Interstate Rule/Cross State Air Pollution Rule (CSAPR) and Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) for emissions to the air, and a number of new rules focused on water use and discharges from power generation facilities.

Together 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 these rules are implemented as proposed, 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, require the investment of significant capital for new equipment and increase 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. There remains considerable interest in renewable energy sources by renewable energy suppliers, developers and the utilities in Florida. Previously the FPSC made a recommendation to the Florida Legislature that the RPS be 20% by Jan. 1, 2021. The FPSC recommendation is subject to ratification by the Florida Legislature, but to date the Legislature has not adopted the FPSC’s recommendation. 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, however, if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS. Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers through the ECRC.

Tampa Electric, the state of Florida and the nation as a whole are increasingly dependent on natural gas to generate electricity. 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 Florida and across 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. 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, Tampa Electric and PGS are allowed to pass the cost for the commodity gas and transportation services to customers without profit. Changes in regulations could reduce earnings if they required Tampa Electric or PGS 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.

 

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All of our businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric’s and PGS’s energy sales 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, which has a typically short but significant winter peak period that is dependent on cold weather, is more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can negatively impact results at Tampa Electric and PGS.

Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coal. Severe weather conditions could interrupt or slow coal production or rail transportation and increase operating costs.

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.

As a company with electric service and natural gas operations in peninsular Florida, the company is 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.

Commodity price changes may affect the operating costs and competitive positions of our utility 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, 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 relative to electricity, other forms of energy and other gas suppliers.

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 it products. 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 at domestic utilities. Continued low natural gas prices would keep demand and selling prices low, which would reduce TECO Coal’s profitability, or reduce the value of its reserves.

TECO Coal sells approximately 50% of its production to domestic utilities for use in the generation of power. Since 2011, natural gas prices have dropped significantly, which caused utility coal users to switch to lower cost natural gas to generate electricity. Even with a modest increase in natural gas prices in 2013, it remains more cost effective for users of higher cost Central Appalachian coal, which TECO Coal produces, to burn a higher percentage of natural gas for power generation. Lower cost coals from other producing regions of the U.S. are being utilized by more utilities in lieu of Central Appalachian coals further reducing demand.

 

 

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At the end of 2013, approximately 50% of TECO Coal’s existing profitable steam coal contracts expire. 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’s profitability will be reduced. If these conditions were to persist, the value of TECO Coal’s reserves could be reduced, which could result in a non-cash write off.

Results at our utility companies may be affected by changes in customer energy-usage patterns, the impact of the Florida housing market, and the cost of complying with potential new environmental regulations.

For the past several years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, trends toward smaller single family houses and increased multi-family housing, which we believe have contributed to lower per-customer usage.

The utilities’ forecasts are based on normal weather patterns and historical trends in customer energy-usage patterns. Tampa Electric’s and PGS’s ability to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency of lights and appliances, economic conditions or other factors.

Compliance with proposed GHG emissions reductions, a mandatory RPS or other new regulation could raise Tampa Electric’s cost. While current regulation allows Tampa Electric to recover the cost of new environmental regulation through the ECRC, increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electric’s sales.

Our computer systems and Tampa Electric’s infrastructure may be subject to cyber (primarily electronic or internet-based) attack, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems.

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, or attachments to e-mails or 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 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, or compromise important data or systems.

We rely on some transmission and distribution assets that we do not own or control to deliver wholesale electricity, as well as natural gas. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver electricity and natural gas may be hindered.

We depend on transmission and distribution facilities owned and operated by other utilities and energy companies to deliver the electricity and 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.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities. Likewise, unexpected interruption in upstream natural gas supply or transmission could affect our ability to generate power or deliver natural gas to local distribution customers.

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

There are increasing calls in Congress for “comprehensive tax reform,” which could significantly alter the existing tax code, including a reduction in corporate income tax rates. A reduction in the corporate income tax rate would reduce the value of our existing deferred tax assets and could result in write-offs and higher cash tax payments, which could reduce our ability to retire debt in 2016 and 2017.

The current administration in Washington D.C. has proposed the elimination of the percentage depletion tax deduction for coal mines and other hard minerals and fossil fuels.

 

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If the percentage depletion tax deduction is eliminated for TECO Coal, the effective tax rate for that company would rise from the expected 20% to 25% to the general corporate tax rate of 37%, which would have an adverse effect on TECO Coal’s financial results after 2013.

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

We evaluate our long-lived assets for impairment annually or more frequently if certain triggering events occur. Should the current carrying values of any of these assets not be recoverable, we would incur charges to write down the assets to fair market value.

Problems with operations could cause us to incur substantial costs.

Each of our subsidiaries is subject to various operational risks, including accidents, equipment failures and operations below expected levels of performance or efficiency. Our subsidiaries could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines, coal mining or processing equipment or other equipment or processes that would result in performance below assumed levels of output or efficiency. The occurrence of one or more of these problems could cause us to incur substantial costs, including potential claims for damages that may exceed the scope of our insurance coverage, which could have an adverse impact on our financial condition and results from operations.

Failure to obtain the permits necessary to open new surface mines could reduce earnings from TECO Coal.

Our 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 a backlog of permit applications and very few permits being issued. TECO Coal had three permits on the list of permits subject to enhanced review by the EPA under its memorandum of understanding with the USACE, which was issued in September 2009. In October 2011, the Federal District Court for the District of Columbia set aside the Enhanced Coordination Procedures (ECP) developed by the USACE and the EPA to expedite review of pending surface coal mining permit applications. USACE Districts and the EPA Regions in Appalachia have all ceased using the ECP as of the date of the District Court’s decision. While the court invalidated the ECP, the decision does not affect any statutory or regulatory requirements established under the Clean Water Act, including the USACE’s and the EPA’s Section 404 permitting regulations. 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 reduce the earnings expected from TECO Coal.

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.

On April 1, 2010, the EPA issued new guidance on environmental permitting requirements for Central Appalachian mountaintop removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. At that time, the EPA stated that it would decide whether to modify the guidance after consideration of public comments and the results of the Science Advisory Board (SAB) technical review of the EPA scientific reports. In July 2011, the EPA made this guidance final without modification. 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 July 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 in the manner in which it was done. Following the outcome of these court decisions, pending appeals by the EPA, few, if any, new permits have been issued by 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 Europe. TECO Coal attempts to mitigate this risk through 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

 

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measures will effectively mitigate all international risks, which could have an adverse effect on TECO Coal’s financial conditions.

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

Competition in wholesale power sales is wide spread 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 PGS are unbundled for all non-residential customers. Because PGS earns margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’s results. However, future structural changes that we cannot predict could adversely affect PGS.

From time to time, we are a party to legal proceedings that may result in a material adverse effect on our financial condition.

From time to time, we are a party to, or otherwise involved in, lawsuits, claims, proceedings, investigations and other legal matters that have arisen in the ordinary course of conducting our business. While the outcome of these lawsuits, claims, proceedings, investigations and other legal matters which we are a party to, or otherwise involved in, cannot be predicted with certainty, an adverse outcome could result in a material adverse effect on our financial condition.

Financing Risks

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

We have significant 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 and TEC must meet certain financial tests as defined in the applicable agreements to use their respective credit facilities. Also, TECO Energy, TECO Finance, TEC and other operating companies 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 Management’s Discussion & Analysis for descriptions of these tests and covenants.

As of Dec. 31, 2012, we were in compliance with required financial covenants, but we cannot be assured that we will be in 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 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.

The financial market conditions that were experienced in 2008 and early 2009 impacted access to both the short-and long-term capital markets and the cost of such capital. TECO Finance has debt maturing in 2015 of which it expects to refinance a portion. Future financial market conditions could limit our ability to raise the capital we need and could increase our interest costs, which could reduce earnings.

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 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,

 

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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.

The value of our pension fund assets were negatively impacted by unfavorable market conditions in 2008. As of Jan. 1, 2012, our plan was approximately 84% funded under calculation requirements of the Pension Protection Act. As calculated under the MAP-21 legislation, signed into law in 2012, our funded percentage is expected to be approximately 94% as of the next Pension Protection Act measurement date of Jan. 1, 2013. TECO Energy estimates its required minimum contributions to range from $15 million to $50 million annually over the next five years. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund our plan in the future.

We estimate that pension expense in 2013 will be slightly higher than levels experienced in 2012, primarily due to the lower interest rate environment. Any future declines in the financial markets or a continuation of the low interest rate environment could cause pension expense to increase in future years.

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 longer-term to add generating capacity at the Polk Power Station.

If we are unable to maintain capital expenditures at 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, earnings and credit ratings 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 Standard & Poor’s (S&P) at BBB with a stable outlook, by Moody’s Investor’s Services (Moody’s) at Baa2 with a stable outlook, and by Fitch Ratings (Fitch) at BBB with a stable outlook. The senior unsecured debt of TEC is rated by S&P at BBB+ with a stable outlook, by Moody’s at A3 with a stable outlook and by Fitch at A—with a stable outlook. A downgrade to below investment grade by the rating agencies 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 also may 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, Tampa Electric and PGS are able to purchase electricity and gas without providing collateral. If the ratings of TEC decline to below investment grade, Tampa Electric and PGS could be required to post collateral to support their purchases of electricity and gas.

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 when needed, we may be unable to pay dividends or satisfy our obligations.

 

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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 plants in service, with a December 2012 net winter generating capability of 4,668 MW. Tampa Electric assets include the Big Bend Power Station (1,572 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 in long-term reserve standby.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,279 Mega Volts Amps. The transmission system consists of approximately 1,347 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,301 pole miles of overhead lines and 4,762 trench miles of underground lines. As of Dec. 31, 2012, there were 687,185 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 rights-of-way 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 17,800 miles of pipe, including approximately 11,200 miles of mains and 6,600 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

PGS’s operations are located in 14 operating divisions throughout Florida. 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 295,000 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.

 

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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, 2012, the TECO Coal operating companies had a combined estimated 310.9 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 94.5 million tons of coal.

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 CMMA 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.

 

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RECOVERABLE RESERVES BY QUANTITY (1)

(Millions of tons)

Table 4

 

                                          Assigned (2)    Unassigned (2)

Mining

Complex

   Location    Total    Proven    Probable    Owned    Leased    2013    2012    2013    2012

 

   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 Mining

   Pike County, KY/    60.8    51.6    9.2    3.2    57.6    60.8    44.5    0.0    0.1
     Buchanan County,
VA
                                            

 

   Premier Elkhorn Coal

   Pike County,

KY/Letcher County,
KY/ Floyd County,
KY

   109.6    67.7    41.9    85.6    24.0    58.6    60.9    51.0    75.1

 

   Perry County Coal

   Perry County, KY/    137.1    82.4    54.7    1.5    135.6    131.9    139.0    5.2    2.2
   Leslie County, KY/                           
     Knott County, KY                                             
                                                   

TOTALS

      310.9    204.7    106.2    91.5    219.4    251.8    244.9    59.1    80.3

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 of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.
  (2) Assigned reserves means 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 in the property.

 

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RECOVERABLE RESERVES BY QUALITY (1)

Table 5

 

                                
      Recoverable                     
      Reserves    Sulfur Content         Average BTU      

Mining Complex

 

  

(Millions of tons)

 

  

< 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

   60.8    39.1    21.7    20.3    12,500 - 13,500    HVM, LSU,
PCI

   Premier Elkhorn Coal

   109.6    93.6    16.0    57.9    12,700 - 13,100    HVM, IS,
LSU, PCI,

   Perry County Coal

   137.1    106.7    30.4    83.2    12,500 - 13,100    LSU, PCI, V
                               
                               

   Total

   310.9    242.6    68.3    161.4      

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 steam 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 steam 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 steam 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 steam coal category), a substantial portion of the Perry County coal reserves has been allocated to the PCI category (with the remainder to the steam coal category), and all of the Gatliff Coal reserves has been allocated to the steam coal category.

At TECO Coal’s request, CMMA completed an audit of the methodology used by TECO Coal to conduct such allocation of its coal tonnage estimates. CMMA 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 CMMA 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.

The following table (Table 6) shows the recoverable reserves by market category per mining complex and in total. The total reserve mix is approximately 41% metallurgical, 40% PCI and 19% steam.

 

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RESERVES BY MARKET CATEGORY

Table 6

 

             Met
Reserves
                     PCI
Reserves
                     Steam
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

     46.6         8.5         55.1         0.0         0.0         0.0         5.0         0.7         5.7         60.8   

Premier Elkhorn Coal

     34.5         36.4         70.9         15.8         3.0         18.8         17.4         2.5         19.9         109.6   

Perry County Coal

     0.0         0.0         0.0         62.8         43.9         106.7         19.5         10.9         30.4         137.1   

Totals:

     81.1         44.9         126.0         78.6         46.9         125.5         44.7         14.7         59.4         310.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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 various 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, material 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 or financial condition.

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 10, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

 

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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 the adopted Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this annual report.

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  

2012

           

High

   $ 19.41       $ 18.33       $ 18.64       $ 18.14   

Low

     17.35         16.90         17.26         16.12   

Close

     17.55         18.06         17.74         16.76   

Dividend

   $ 0.220       $ 0.220       $ 0.220       $ 0.220   

2011

           

High

   $ 18.82       $ 19.66       $ 19.38       $ 19.30   

Low

     17.47         18.20         15.82         16.15   

Close

     18.76         18.89         17.13         19.14   

Dividend

   $ 0.205       $ 0.215       $ 0.215       $ 0.215   

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 18, 2013 was 12,243.

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 $228.3 million in 2012, $240.7 million in 2011 and $239.3 million in 2010. See the Restrictions on Dividend Payments and Transfer of Assets section in Note 1 to the Tampa Electric Company Consolidated Financial Statements for a description of restrictions on dividends on its common stock.

 

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

 

     

(a)

Total Number of
Shares (or Units)
Purchased (1)

    

(b)

Average Price
Paid per Share (or
Unit)

    

(c)

Total Number of
Shares (or Units)
Purchased as Part
of Publicly
Announced Plans or
Programs

  

(d)

Maximum Number
(or Approximate
Dollar Value) of
Shares (or Units) that
May Yet Be
Purchased Under the
Plans or Programs

Oct. 1, 2012 – Oct. 31, 2012

     432         $17.83       0.0    0.0

Nov. 1, 2012 – Nov. 30, 2012

     8,758         $16.55       0.0    0.0

Dec. 1, 2012 – Dec. 31, 2012

     9,988         $16.57       0.0    0.0

Total 4th Quarter 2012

     19,178         $16.59       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.

Shareholder Return Performance Graph

The following graph shows the cumulative total shareholder return on our common stock on a yearly basis over the five-year period ended Dec. 31, 2012 and compares this return with that of the S&P 500 Index and the S&P Multi Utility Index. The graph assumes that the value of the investment in our common stock and each index was $100 on Dec. 31, 2007 and that all dividends were reinvested.

 

LOGO

 

 

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Item 6. SELECTED FINANCIAL DATA OF TECO ENERGY, INC.

 

(millions, except per share amounts)                                       
Years ended Dec. 31,    2012     2011      2010      2009      2008  

Revenues (1)

   $     2,996.6      $     3,209.9       $     3,363.5       $     3,302.2       $     3,366.9   

Net income from continuing operations(1)

     246.0        250.8         211.6         182.4         138.1   

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

     (33.3     21.8         27.4         31.5         24.3   

Net income attributable to TECO Energy

     212.7        272.6         239.0         213.9         162.4   

Total assets

     7,356.5        7,322.2         7,278.3         7,219.5         7,147.4   

Long-term debt, including current portion

     2,972.7        3,073.4         3,226.4         3,309.5         3,213.5   

EPS - Basic

             

From continuing operations (1)

   $ 1.14      $ 1.17       $ 0.99       $ 0.85       $ 0.65   

From discontinued operations attributable to TECO Energy (1)

     (0.15     0.10         0.13         0.15         0.12   

Attributable to TECO Energy

   $ 0.99      $ 1.27       $ 1.12       $ 1.00       $ 0.77   

 

 

EPS - Diluted

             

From continuing operations (1)

   $ 1.14      $ 1.17       $ 0.98       $ 0.85       $ 0.65   

From discontinued operations attributable to TECO Energy (1)

     (0.15     0.10         0.13         0.15         0.12   

Attributable to TECO Energy

   $ 0.99      $ 1.27       $ 1.11       $ 1.00       $ 0.77   

 

 

Dividends paid per common share outstanding

   $ 0.880      $ 0.850       $ 0.815       $ 0.800       $ 0.795   
(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19 to the TECO Energy Consolidated Financial Statements.

 

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ITEM 7.

MANAGEMENT’S DISCUSSION & ANALYSIS

OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS

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

TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion & Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.

OVERVIEW

We are an energy-related holding company with regulated electric and gas utility operations in Florida, Tampa Electric and PGS, respectively, and TECO Coal, which owns and operates coal production facilities in the Central Appalachian coal production region.

Our regulated utility companies, Tampa Electric and PGS, operate in the Florida market. Tampa Electric serves more than 687,000 retail customers in a 2,000-square-mile service area in West Central Florida and has electric generating plants with a winter peak generating capacity of 4,668 MW. PGS, Florida’s largest gas distribution utility, serves approximately 345,000 residential, commercial, industrial and electric power generating customers in all major metropolitan areas of the state, with a total natural gas throughput of almost 1.9 billion therms in 2012.

Our unregulated business, TECO Coal, which through its subsidiaries, operates surface and underground mines and related coal processing facilities in eastern Kentucky, southwestern Virginia and Tennessee, producing metallurgical-grade and high-quality steam coals. Sales in 2012 were 6.3 million tons. In 2012 we sold our ownership interest in TECO Guatemala, which through its subsidiaries, owned a coal-fired generating facility and a 96% ownership interest in an oil-fired peaking power generating plant, both in Guatemala.

2012 PERFORMANCE

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

In 2012, our net income and earnings per share attributable to TECO Energy were $212.7 million, or $0.99 per share, compared to $272.6 million, or $1.27 per share, in 2011. Net income and earnings per share from continuing operations were $246.0 million and $1.14 in 2012, compared with $250.8 million and $1.17 in 2011. The 2012 losses in discontinued operations of $33.3 million reflect the results from operations of $18.2 million for the generating plants in Guatemala through the closing of the sales, a $28.6 million loss on assets sold including transaction costs, and a $22.9 million charge associated with foreign tax credit write-off.

In 2012, we focused on managing our utility businesses to earn their allowed ROE despite unfavorable weather patterns and lower per customer usage. Mild winter weather and an unusually rainy summer weather pattern offset by higher than normal degree days in the shoulder month periods, which do not generate significantly higher energy sales, reduced energy sales volumes for both Tampa Electric and PGS in 2012, following 2011 when weather patterns were similarly unfavorable. We benefited from the retirement of parent debt, and lower interest rates on TECO Finance and TEC debt in 2012. Results at TECO Coal reflected improved margins from better selling prices for its specialty coal products, partially offset by higher operating costs and lower volumes driven by the coal market conditions. In September we announced the sale of our ownership interests in the two power plants in Guatemala, and results for that segment were reclassified to discontinued operations.

In 2011, our net income and earnings per share attributable to TECO Energy were $272.6 million, or $1.27 per share, compared to $239.0 million, or $1.12 per share, in 2010.

There were no charges or gains to cause non-GAAP results to differ from net income in 2012 or in 2011.

 

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OUTLOOK

Our outlook for 2013 results reflects our expectations that state and local economies will continue to strengthen and that PGS will earn at or above the middle of its allowed ROE range. Tampa Electric expects to earn below the bottom of its allowed ROE range, and as a result has notified the FPSC that it is planning to file a new base rate proceeding in April for new rates effective in early 2014. Tampa Electric’s actual revenue requirement calculation is not final, but is expected to be approximately $135 million (see the Tampa Electric and Regulation sections). TECO Coal expects to generate positive net income from fewer tons and at lower margins, which reflects the current weak coal markets. The drivers impacting 2013 are summarized below and discussed in further detail in the individual operating company sections.

Tampa Electric expects customer growth in 2013 to continue at a pace similar to 2012, when the average number of customers increased 1.2%. Total retail energy sales growth is expected to average about 0.5% lower than customer growth due to lower average customer usage. Sales to the lower margin industrial-phosphate customers are expected to be lower in 2013 due to increased self-generation following outages of customers’ generating equipment that increased sales to these customers in 2012. PGS expects customer growth consistent with trends in 2012 when the average number of customers increased 1.2%. PGS expects energy sales volumes to be higher than in 2012, assuming normal weather conditions, as mild winter temperatures reduced natural gas volumes sold in 2012. It also expects to benefit from customers converting from petroleum and other fuel sources to natural gas due to the attractive economics.

Due to the current very weak domestic and international coal market conditions, we expect TECO Coal’s net income to be about $12 million at the middle of the cost and sales guidance ranges in 2013. TECO Coal expects to sell between 5.2 and 5.7 million tons in 2013 with 90% of its sales contracted. The average selling price across all products is expected to be more than $86 per ton, which is $10 per ton lower than 2012, while the fully-loaded, all-in cost of production is expected to be in a range between $81 and $85 per ton.

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

Our priorities for the use of cash remain investment in the utility companies and, over time, reduction of parent debt. In 2013, we expect to make additional equity contributions to Tampa Electric and PGS to support their capital structures and financial integrity. Our opportunities to invest capital in Tampa Electric are expected to grow significantly over the next several years as it invests in its next increment of new generating capacity. We anticipate capital spending in 2013 to increase to $520 million, including the investments in generating capacity additions at Tampa Electric and opportunities to grow the PGS system described below (see the Liquidity, Capital Resources section).

Over the next several years, after maintaining Tampa Electric’s and PGS’s capital structure, we expect to repurchase shares to offset dilution from shares issued as compensation, and use additional cash to repurchase shares as market opportunities allow, which in total could be as much as $50 million.

In 2010, we consolidated activities throughout the company involving evaluation of trends, strategies and opportunities affecting our regulated utilities, to sharpen the focus on developing longer-range plans to take advantage of emerging growth opportunities and some fundamental changes in our industry. Over time we expect these initiatives to contribute to earnings growth. Some of the areas that we are currently focused on include:

 

 

We believe that there are opportunities to grow the use of CNG for fleet vehicles. To date, we have had success working with fleet owners to install 13 CNG filling stations with conversions or planned conversions over the next two years of about 700 vehicles of various sizes to CNG. The number of vehicles already converted or committed to conversion is the equivalent volume usage of 24,000 residential customers on an annual basis. Such conversions offer compelling economics to customers, and expand PGS therm sales without significant capital investment by PGS.

 

We are looking closely at Smart Grid applications that have proven technology and offer operating and financial benefits to our overall operations. These include, among other opportunities, transitioning automatic meter reading technology to advanced metering infrastructure, which would include a significant investment in our communications infrastructure but would also result in O&M expense savings.

 

We also recognize that there is a growing demand for natural gas generation in Florida over the next decade. We project that Florida may need between 0.8 and 1.25 billion cubic feet per day (Bcf/day) by as early as 2016. Given our expertise in this area, we continue to evaluate opportunities to partner with transmission and end-use natural gas customers.

At PGS, the business model for system expansion evolved over the past several years to focus on extending the system to serve large commercial and industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future make it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost per MMBTU basis.

 

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    Previously, during periods of robust residential growth, PGS extended its system to serve large residential housing developments and commercial growth followed the residential development. In the current environment where fewer large residential projects are being developed, commercial, and industrial-led expansion allows PGS to continue to provide clean and economical natural gas to areas of the state previously unserved and to be positioned to serve future residential growth.

RESULTS SUMMARY

    The table below compares our GAAP net income to our non-GAAP results. A reconciliation between GAAP net income and non-GAAP results is contained in the Reconciliation of GAAP net income from continuing operations to non-GAAP results tables for 2010. A non-GAAP financial measure is a numerical measure that includes or excludes amounts, or is subject to adjustments that have the effect of including or excluding amounts that are excluded or included from the most directly comparable GAAP measure (see the Non-GAAP Information section).

Results Comparisons

 

  (millions)

     2012         2011         2010        

  Net income attributable to TECO Energy

   $ 212.7       $ 272.6       $ 239.0        

  Net income from continuing operations

   $ 246.0       $ 250.8       $ 211.6      

  Non-GAAP results from continuing operations

   $ 246.0       $ 250.8       $ 244.2        

The table below provides a summary of revenues, earnings per share, net income and shares outstanding for the 2012-2010 period.

Earnings Summary

 

  (millions) Except per-share amounts

     2012        2011         2010        

  Consolidated revenues

   $ 2,996.6      $ 3,209.9       $ 3,363.5        

  Earnings per share – basic

                              

  Earnings per share from continuing operations

   $ 1.14      $ 1.17       $ 0.99      

  Earnings (loss) per share from discontinued operations

     (0.15     0.10         0.13        

  Earnings per share attributable to TECO Energy

   $ 0.99      $ 1.27       $ 1.12        

  Earnings per share – diluted

                              

  Earnings per share from continuing operations

   $ 1.14      $ 1.17       $ 0.98      

  Earnings (loss) per share from discontinued operations

     (0.15     0.10         0.13        

  Earnings per share attributable to TECO Energy

   $ 0.99      $ 1.27       $ 1.11        

  Net income from continuing operations

   $ 246.0      $ 250.8       $ 211.6      

  Net income (loss) from discontinued operations

     (33.3     21.8         27.4        

  Net income attributable to TECO Energy

     212.7        272.6         239.0        

  Charges and (gains)(1)

     —          —           36.5        

  Non-GAAP results

   $ 212.7      $ 272.6       $ 275.5        

  Average common shares outstanding (millions)

          

Basic

     214.3        213.6         212.6      

Diluted

     215.0        215.1         214.8      

  (1)   See the GAAP to non-GAAP reconciliation tables that follow.

          

    The following tables show the specific adjustments made to GAAP net income for each segment to develop our non-GAAP results:

There were no charges or gains in 2012 or 2011 to cause non-GAAP results to differ from net income.

 

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2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results

 

  Net income impact (millions)

    
 
Tampa
Electric
  
  
     PGS        

 

TECO

Coal

  

  

    

 

Parent/

other(1)

  

   

   
 
 
Total
continuing
Operations
  
  
  
    
 
Discontinued
Operations
(1)
  
  
    Total   

  GAAP Net income

  attributable to TECO Energy

     $208.8             $34.1         $53.0         $(84.3)        $211.6                 $27.4                $239.0       

  Restructuring charges

     —               —           —           0.9        0.9                 —                  0.9       

  Loss on the sale of DECA II

  net of taxes

     —               —           —           —          —                   3.9                3.9       
  Charges related to early debt
  retirement
     —               —           —           33.5        33.5                 —                  33.5       
  Recovery of fees related to McAdams
  Power Station sale
     —               —           —           (1.8)        (1.8)                —                  (1.8)       

  Total charges and (gains)

     —               —           —           32.6        32.6                 3.9                36.5       

  Non-GAAP results

     $208.8             $34.1         $53.0         $(51.7)        $244.2                 $31.3                $275.5       

 

  (1) Certain costs previously included in Parent/other have been recast to Discontinued Operations.

NON-GAAP INFORMATION

    From time to time, in this MD&A, we provide non-GAAP results, which present financial results after elimination of the effects of certain identified charges and gains. In 2012 and 2011, there were no charges or gains to cause non-GAAP results to differ from net income. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company’s operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the board of directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.

    The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of results may not be comparable to similarly titled measures used by other companies.

    While none of the particular excluded items are expected to recur, there may be adjustments to previously estimated gains or losses related to the disposition of assets or additional debt extinguishment activities. We recognize that there may be items that could be excluded in the future. Even though charges may occur, we believe the non-GAAP measure is important in addition to GAAP net income for assessing our potential future performance, because excluded items are limited to those that we believe are not indicative of future performance.

OPERATING RESULTS

    This MD&A utilizes TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP, and separate non-GAAP measures to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing and others (see the Critical Accounting Policies and Estimates section).

    The following table shows the segment revenues, net income and earnings per share contributions from continuing operations of our business segments on a GAAP basis (see Note 14 to the TECO Energy Consolidated Financial Statements).

 

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  (millions) Except per share amounts

          2012        2011        2010       

  Segment revenues (1)

                                 

  Regulated companies

   Tampa Electric    $ 1,981.3      $ 2,020.6      $ 2,163.2     
   Peoples Gas      398.9        453.5        529.9     

  Total regulated

        $ 2,380.2      $ 2,474.1      $ 2,693.1       
     TECO Coal    $ 608.9      $ 733.0      $ 690.0       
                                   

  Net income (2)

           

  Regulated companies

   Tampa Electric    $ 193.1      $ 202.7      $ 208.8     
   Peoples Gas      34.1        32.6        34.1     

  Total regulated

          227.2        235.3        242.9       
   TECO Coal      50.2        51.5        53.0     
     Parent/other(4)      (31.4     (36.0     (84.3    

  Net income from continuing operations

        246.0        250.8        211.6     

  Net income (loss) from discontinued

  operations

          (33.3     21.8        27.4       

  Net income attributable to TECO Energy

        $ 212.7      $ 272.6      $ 239.0       

  Earnings per share - basic (2)(3)

           

  Regulated companies

   Tampa Electric    $ 0.90      $ 0.95      $ 0.98     
   Peoples Gas      0.16        0.15        0.16     

  Total regulated

          1.06        1.10        1.14       
   TECO Coal      0.23        0.24        0.25     
     Parent/other(4)      (0.15     (0.17     (0.40    

  Earnings per share from continuing

  operations

        1.14        1.17        0.99     

  Earnings (loss) per share from discontinued

  operations

          (0.15     0.10        0.13       

  Earnings per share attributable to TECO

  Energy

        $ 0.99      $ 1.27      $ 1.12       

  Average shares outstanding – basic

        214.3        213.6        212.6     

(1)  Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.

(2)  Segment net income and earnings per share are reported on a basis that includes internally allocated interest costs to the unregulated companies. Internally allocated interest costs were at a pretax interest rate of 6.00% for 2012, 6.25% for 2011, 6.50% for July through December 2010, and 7.15% for January through June 2010.

(3)  The number of shares used in the earnings-per-share calculations is basic shares.

(4)  From continuing operations

   

    

  

  

   

TAMPA ELECTRIC

Electric Operations Results

    Net income in 2012 was $193.1 million, compared to $202.7 million in 2011.

    Results in 2012 reflected a mild winter weather period and an extremely rainy summer period, and lower per-customer average usage, partially offset by 1.2% growth in the average number of customers, higher O&M expense and lower interest expenses. Net income in 2012 included $2.6 million of AFUDC–equity, which represents allowed equity cost capitalized to construction costs, compared with $1.0 million in the 2011 period.

    Results in 2011 reflected the significant impact on energy sales of extremely mild weather, partially offset by a 0.7% higher average number of customers, and lower non-fuel O&M expense. Net income in 2011 included $1.0 million of AFUDC equity, compared with $1.9 million in the 2010 period.

    In 2012, total degree days in Tampa Electric’s service area were normal, but almost 3% below the prior year, reflecting mild winter weather and an unusually rainy summer weather pattern (the second wettest summer period on record) offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher

 

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energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, voluntary conservation that typically occurs during periods without extreme weather, and changes in customer usage patterns.

    In 2012, total net energy for load was 0.3% higher than in 2011. Milder weather reduced sales to higher-margin residential and smaller commercial customers. Industrial-other sales were higher, reflecting improvements in the Florida economy, and higher energy sales to industrial-phosphate customers due to the transfer of certain load from self-generation to Tampa Electric’s system. The energy sales shown in the summary table below reflect the energy sales based on the timing of billing cycles, which can vary from period to period.

    In 2012, O&M expense, excluding all FPSC-approved cost-recovery clauses, increased $11.8 million reflecting higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense. Compared to the 2011 full-year period, depreciation and amortization expense increased $9.6 million, reflecting additions to facilities to serve customers. Interest expense decreased $7.4 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

    Compared to the cold winter and hot summer in 2010, the mild winter and wet summer in 2011 resulted in pretax base revenues $31 million lower than in 2010 (when revenues were reduced $24 million under a regulatory agreement), despite a 0.7% increase in the average number of customers and improvements in the local economy. In 2011, total retail net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 5.7%, compared to the 2010 period. In 2011, total degree days in Tampa Electric’s service area were 3% above normal, but 10% lower than in 2010. In 2011, although degree days were slightly above normal, periods of cold winter weather were not sustained long enough to generate typical winter heating load and summer season cooling degree days were above normal. In the summer season, rainfall was 14% above normal, which did not affect degree days but did lower energy sales primarily to residential customers.

    In 2011, O&M expense, excluding all FPSC-approved cost-recovery clauses, decreased $23.6 million, driven primarily by lower accruals for performance-based incentive compensation for all employees and other benefit costs, lower power plant maintenance costs, and lower costs to operate and maintain the transmission and distribution system. Compared to 2010, depreciation and amortization expense increased $3.8 million, reflecting the additions to facilities to serve customers.

Base Rates

    Tampa Electric’s 2012 results reflect base rates established in March 2009, when the FPSC awarded $104.0 million higher revenue requirements effective in May 2009 that authorized an ROE mid-point of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for combustion turbines and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

    As a result of increasing pressure on O&M expense, and an economic recovery that has been slower than expected compared to the assumptions in Tampa Electric’s last base rate proceeding initially filed in 2008, on Feb. 4, 2013, Tampa Electric notified the FPSC that it is planning to file a new base rate proceeding in April for new rates effective in early 2014. The actual revenue requirement calculation is not final, but is estimated to be approximately $135 million.

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

 

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Summary of Operating Results

 

  (millions)

       2012          % Change         2011          % Change         2010         

  Revenues

     $ 1,981.3          (1.9)       $ 2,020.6          (6.6)       $ 2,163.2       

O & M expenses

       375.7          7.6         349.2          (13.9)         405.6     

Depreciation and amortization

       237.6          7.0         222.1          2.9         215.9     

Taxes, other than income

       151.3          5.4         143.6          (1.2)         145.3     
                                                             

Non-fuel operating expenses

       764.6          7.0         714.9          (6.8)         766.8       

  Fuel

  Purchased power

      

 

694.7

105.3

 

 

      

 

(5.3)

(16.4)  

 

 

     

 

733.5

125.9

 

 

      

 

(4.4)

(29.9)

 

 

     

 

767.6

179.6

 

 

    

Total fuel & purchased power expense

       800.0          (6.9)         859.4          (9.3)         947.2       

Total operating expenses

       1,564.6          (0.7)         1,574.3          (8.2)         1,714.0       

  Operating income

       416.7          (6.6)         446.3          (0.6)         449.2       

  AFUDC equity

       2.6          160.0            1.0          (47.4)         1.9       

  Net income

     $ 193.1          (4.7)       $ 202.7          (2.9)       $ 208.8       

  Megawatt-Hour Sales (thousands)

                                                         

  Residential

       8,395          (3.7)         8,718          (5.1)         9,185     

  Commercial

       6,185          (0.4)         6,207          (0.2)         6,221     

  Industrial

       2,001          10.9          1,804          (10.2)         2,010     

  Other

       1,828          (0.3)         1,835          2.1         1,797       

  Total retail

       18,409          (0.8)         18,564          (3.4)         19,213     

  Sales for resale

       267          (24.2)           352          (31.8)         516       

  Total energy sold

       18,676          (1.3)         18,916          (4.1)         19,729       

  Retail customers (thousands)-average

       684.2          1.2         675.8          0.7         671.0     

  Retail net energy for load

       19,255          0.3         19,205          (5.7)         20,362     

Operating Revenues

    In 2012, retail MWh sales, as measured on a billing cycle basis shown in the table above, decreased 0.8% despite 1.2% higher average number of customers, an improving local economy and higher sales to the lower margin phosphate-industrial customers. In 2012, total degree days in Tampa Electric’s service area were normal, but almost 3% below 2011, reflecting mild winter weather and an unusually rainy summer weather pattern offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, changes in customer usage patterns and voluntary conservation that typically occurs during periods without extreme weather. In 2012, total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, was 0.3% higher than in 2011.

    In 2011, retail MWh sales, as measured on a billing cycle basis shown in the table above, decreased 3.4%. Compared to the cold winter and hot summer in 2010, the mild winter and wet summer in 2011 resulted in pretax base revenue that was $31 million lower than in 2010 (after revenues were reduced $24 million under a regulatory agreement) despite a 0.7% increase in the average number of customers and improvements in the local economy. In 2011, total retail net energy for load decreased 5.7%, compared to the 2010 period. In 2011, total degree days in Tampa Electric’s service area were 3% above normal, but 10% lower than in 2010. Despite total above normal degree days, the weather patterns described in the Results section above reduced energy sales.

    For the past several years, energy consumption per residential customer declined due to the combined effects of economic conditions, high unemployment, increased multi-family homes and smaller single family homes, improvements in lighting and appliance efficiency, and voluntary conservation efforts.

    Sales for resale, which are a decreasing portion of Tampa Electric’s energy sales, declined 24.2% in 2012 after a 31.8% decline in 2011, primarily due to changes in Tampa Electric’s wholesale rates and reduced demand due to the mild weather.

    Based on billing cycle measurements, electricity sales to the phosphate industry increased 25% in 2012 due to the transfer of certain load from self-generation to Tampa Electric’s system and an outage on a phosphate customer’s self-generating equipment. Sales to these customers decreased 23.2% in 2011, driven by the return

 

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to service of a phosphate customer’s self-generating capacity following an outage in 2010. Base revenues from sales to phosphate customers represented 3.3% of base revenue in 2012, and almost 3% of base revenues in 2011 and 2010. Sales to commercial customers decreased 0.3% in 2012 and 0.2% in 2011, primarily reflecting the mild weather.

Customer and Energy Sales Growth Forecast

The Florida economy continues to slowly recover from the economic downturn, as evidenced by lower levels of unemployment, and slow improvements in the new housing construction market, which was a major driver of growth in the Florida economy for many years (see the Risk Factors section). In general, economists are forecasting a continued improvement in the unemployment rate in 2013, and an acceleration of improvement in the economy in 2014 and beyond. The 2013 forecast used by Tampa Electric reflects a continuation of the customer growth trend that was experienced in 2012. Energy sales are expected to reflect continued lower per customer usage in response to increased energy efficiency, voluntary conservation, and economic conditions. The average number of customers increased 1.2% in 2012 and 0.7% in 2011.

Longer term, assuming continued economic recovery and that growth from population increases and more robust business expansion resumes, Tampa Electric expects average annual customer growth of about 1.3% and weather-normalized average retail energy sales growth about 0.5% lower than customer growth. This energy sales growth projection is lower than in periods prior to the economic downturn, reflecting increased lighting and appliance efficiency, smaller new single family homes, increased percentage of multi-family homes, changes in usage patterns and changes in population trends. These growth projections assume continued modest local area economic growth, normal weather, a recovery in the housing market over time, and a continuation of the current energy market structure.

The economy in Tampa Electric’s service area continued to grow in 2012 after modest growth in 2011 and 2010. The Tampa metropolitan area had the largest gain in jobs of 22 metropolitan areas in Florida, with 21,000 new jobs led primarily by the business services, healthcare and tourism-related businesses. The total nonfarm employment in the Tampa metropolitan area increased 1.8% in 2012 and 1.2% in 2011 after decreasing 1.5% in 2010. The increase in nonfarm employment compared favorably with the state of Florida’s increase of 0.9%. The local Tampa area unemployment rate decreased to 7.6% at year-end 2012 compared to 9.5% at year-end 2011, and 12.0% at year-end 2010. The Tampa area year-end 2012 unemployment rate was below the state of Florida’s 8.0% rate, and the national rate of 7.8%.

Operating Expenses

Total pretax operating expenses decreased 0.6% in 2012 driven primarily by lower fuel and purchased power expenses. Excluding all FPSC approved cost-recovery clause related expenses, which are net income neutral, O&M expense increased 6.6%, or $11.8 million, driven by higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense. O&M expense is expected to increase in 2013 due to increased expenses to operate the system and reliably serve customers and higher employee-related expenses, including pension expense, driven by discount rate assumptions in the current low interest rate environment.

Total pretax operating expenses decreased 8.2% in 2011, driven primarily by lower purchased-power expense and lower other operating expense. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense decreased $23.6 million, driven primarily by lower accruals for performance-based incentive compensation for all employees and other benefit costs, lower power plant maintenance costs, and lower costs to operate and maintain the transmission and distribution system.

Compared to 2011, depreciation and amortization expense increased $9.5 million in 2012, reflecting additions to required infrastructure to serve customers. Depreciation expense is expected to increase at similar levels in 2013. Compared to 2010, depreciation and amortization expense increased $3.8 million in 2011, reflecting the additions to facilities to serve customers.

Fuel Prices and Fuel Cost Recovery

In November 2012, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2013. The rates include the expected cost for natural gas and coal in 2013, and the net over-recovery of fuel, purchased power and capacity clause expenses which were collected in 2012 and 2011.

Total fuel cost decreased in both 2012 and 2011, due to increased natural gas-fired generation as lower costs for natural gas was partially offset by higher costs for coal. Purchased-power expense decreased in 2012 as the cost-per-MWh decreased, due to lower natural gas prices, which is the primary fuel used by other generators in Florida. Purchased power expense decreased in 2011 due to lower volumes purchased at lower prices due to lower natural gas prices, and higher Tampa Electric coal-fired generation. Delivered natural gas prices decreased 14.0% in 2012 as a result of historically low

 

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natural gas prices in the first half of 2012 due to mild winter weather and abundant supplies from on-shore domestic natural gas produced from shale formations, and storage inventories above historic averages. Higher natural gas inventories resulted from lower demand for natural gas caused by mild weather and lower natural gas demand from industrial users due to economic conditions. Delivered coal costs increased 3.2% in 2012. The average coal and natural gas costs were $3.57/MMBTU and $5.34/MMBTU, respectively, in 2012.

Natural gas futures as traded on the NYMEX and various forecasts for natural gas prices indicate that natural gas prices are expected to increase in 2013, compared to the unusually low 2012 levels as fewer new natural gas wells are drilled in on-shore shale gas formations due to the low prices received by the producers, and the expectation for more normal weather and lower levels of gas in storage. Beyond 2013, forecasts are for stable to slightly rising natural gas prices for several years due to increased availability of domestic supplies of natural gas. Delivered coal prices increased 3.2% in 2012 due to normal escalation in fuel and transportation contracts. Tampa Electric’s primary coal supplies are from the Illinois Basin, which have been more stable than the Central Appalachian coal-producing region over the past several years. Excluding normal escalation and transportation costs, Tampa Electric’s coal prices are expected to remain stable in 2013 due to long-term supply contracts.

Energy Supply

Tampa Electric’s generation decreased in 2012 due to the mild weather and lower cost natural gas-fired generation available within Florida, which increased MWh purchased but at a lower cost. Tampa Electric’s generation decreased in 2011 in line with lower energy sales due to mild weather, which also reduced purchased power volumes. Lower natural gas prices also contributed to the decrease in purchased-power expense on a per-MW basis.

Prior to the conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Power Station in 2003, nearly all of Tampa Electric’s generation was from coal. Upon completion of that conversion, the mix shifted with the increased use of natural gas. Coal is expected to continue to represent more than half of Tampa Electric’s fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit One. Longer term, natural gas prices, which declined to exceptionally low levels in early 2012 as a result of increased supply and lower demand due to mild winter temperatures, are expected to remain stable for several years at about the same levels as early 2013, and we expect to maintain the generation mix at about 2012 levels.

Polk Power Station Units 2 – 5 Combined Cycle Conversion

Following the completion of its last increment of new generating capacity additions in 2009, Tampa Electric was in a period of essentially maintenance capital spending for infrastructure to reliably serve its customer base, hurricane storm hardening, investments in its transmission and distribution system to improve reliability and reduce customer outages, for generating unit reliability and information technology systems improvements in 2012 and 2011.

Tampa Electric had previously deferred its next increment of new baseload generating capacity, originally scheduled to be in service in 2013, due to the recession experienced in the Florida and national economies and the Florida housing market slowdown. In 2011, Tampa Electric made the decision to take advantage of generating capacity available in Florida at attractive rates and to purchase power to meet its 2013 through 2016 energy demand and sales growth. In 2011, Tampa Electric announced that, subject to FPSC approval, it planned to convert four CTs in peaking service at the Polk Power Station to combined cycle with an early 2017 in-service date. In 2012, as required under Florida regulations, Tampa Electric issued a request for proposal to determine its lowest cost option to provide generating capacity beginning in early 2017. The bid process showed that the lowest cost option to serve customers, over the long-term, was Tampa Electric’s planned conversion of CTs to combined cycle operation.

In September 2012, Tampa Electric submitted a petition to the FPSC for a Determination of Need for the conversion of these peaking CTs to combined-cycle service. In December 2012, the FPSC conducted a hearing for the need, and at the conclusion the FPSC made a bench decision to approve the Polk Power Station Units 2 – 5 conversion. The capital expenditures for the conversion and the related transmission system improvements to support the additional generating capacity are included in the capital expenditure forecast located in the Capital Expenditures section. Capital spending in 2013 will support environmental permitting activities and engineering and design (see the Capital Expenditures and Regulation sections).

 

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PGS

Operating Results

In 2012, PGS reported net income of $34.1 million, compared with $32.6 million in 2011. Results in 2012 reflected a 1.2% higher average number of customers, but lower sales to residential customers due to mild winter weather more than offset by higher sales to commercial and industrial customers and power generation customers due to improving economic conditions. Volumes for the low-margin transportation service for electric power generators increased due to low natural gas prices, which made it more economical to use natural gas for power generation. Non-fuel O&M expense decreased $2.1 million, compared with 2011, due in part to an insurance recovery of legal expenses associated with environmental-contamination claims. In 2011, O&M expense included $2.5 million related to legal expenses associated with environmental-contamination claims. Interest expense decreased $1.0 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits. Depreciation expense increased $1.4 million reflecting additions to facilities to serve customers.

In 2012, the total throughput for PGS was almost 1.9 billion therms. Industrial and power generation customers consumed approximately 49% of PGS’s annual therm volume, commercial customers used approximately 22%, approximately 12% was sold off system, and the balance was consumed by residential customers.

In 2011, PGS reported net income of $32.6 million compared to $34.1 million in 2010. Results in 2011 reflected a 0.8% higher average number of customers. Increased volumes to commercial and industrial customers reflected improvements in the Florida and national economies and generally higher usage by those customers, while lower volumes sold to residential customers reflected the milder weather in contrast to the cold 2010 winter. Gas transported for power generation customers increased in 2011 due to lower natural gas prices, which made it more economical for some customers to switch to natural gas for power generation. Excluding the impact of the 2010 provision related to potential earnings above the top of the allowed ROE range in 2010 described below, non-fuel O&M expense was higher in 2011, including $2.5 million of expenses related to the defense of environmental contamination claims. Results in 2011 also reflect increased depreciation expense due to routine plant additions.

In 2011, the total throughput for PGS was more than 1.5 billion therms. Industrial and power generation customers consumed approximately 53% of PGS’s annual therm volume, commercial customers used approximately 27%, approximately 15% was sold off system, and the balance was consumed by residential customers.

In 2010, PGS recorded a $9.2 million total pretax ($5.7 million after tax) provision related to the earnings above the top of its allowed ROE range of 9.75% to 11.75% primarily due to unprecedented cold winter weather. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement that called for $3.0 million of the provision to be refunded to customers in the form of a credit on customers’ bills in 2011, and the remainder applied to deficiencies in accumulated depreciation reserves. On Jan. 25, 2011, the FPSC approved the stipulation.

Residential operations were about 32% of total revenues in each of the past three years. New residential construction that includes natural gas and conversions of existing residences to gas has slowed significantly, compared to the pre-2007 period, due to the slower Florida housing market. Like most other natural gas distribution utilities, PGS is adjusting to lower per-customer usage due to improving appliance efficiency. As customers replace existing gas appliances with newer, more efficient models, per-customer usage tends to decline.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also experienced increased interest in the usage of CNG as an alternative fuel for vehicles. Currently, there are 13 CNG fueling stations connected to the PGS system, and additional stations are expected to be added in 2013. Such initiatives add therm sales, at lower margin transportation rates, to the gas system without requiring significant capital investment.

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

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

 

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Summary of Operating Results

 

  (millions)

     2012         % Change         2011         % Change         2010        

  Revenues

     $398.9         (12.0)             $453.5         (14.4)             $529.9      

  Cost of gas sold

     157.6         (25.4)             211.3         (25.8)             284.8      

  Operating expenses

     170.0         (1.3)             172.2         0.2            171.8        

  Operating income

     71.3         1.9            70.0         (4.5)             73.3        

  Net income

     34.1         4.6            32.6         (4.4)             34.1        
                 

  Therms sold – by customer segment

                                                 

Residential

     70.8         (8.9)             77.7         (14.1)             90.5      

Commercial

     421.4         3.0            409.2         0.3            407.9      

Industrial

     461.3         5.8            436.1         (14.0)             507.2      

Power generation

     913.5         48.7            614.3         5.5            582.2        

  Total

     1,867.0         21.4            1,537.3         (3.2)             1,587.8        

  Therms sold – by sales type

                 

System supply

     334.3         (5.4)             353.3         (21.7)             451.0      

Transportation

     1,532.7         29.5            1,184.0         4.2            1,136.8        

  Total

     1,867.0         21.4            1,537.3         (3.2)             1,587.8        

  Customer (thousands) – average

     342.9         1.2            338.8         0.8            336.0      

In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to customers through its “NaturalChoice” program. At year-end 2012, approximately 19,500 out of 35,000 of PGS’s eligible non-residential customers had elected to take service under this program.

PGS Outlook

In 2013, PGS expects continued customer growth at rates in line with those experienced in 2012, reflecting its expectations that the housing markets in some areas of the state that it serves are recovering but others will be slower to recover. Assuming normal weather, therm sales to weather-sensitive customers, especially residential customers, are expected to increase in 2013 compared to 2012 when mild winter weather reduced sales. Excluding all FPSC-approved cost-recovery clause-related expenses, operation and maintenance expense is expected to increase in 2013 primarily due to higher employee-related expenses, which includes pension expense driven by lower discount rates in the current low interest rate environment. Depreciation expense is expected to increase from continued capital investments in facilities to reliably serve customers.

Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system into areas of Florida not previously served by natural gas, such as the lower southwest coast in the Fort Myers and Naples areas and the northeast coast in the Jacksonville area. In 2013, PGS expects capital spending to support moderate residential and commercial customer growth and system expansion to serve large commercial and industrial customers.

Due to the current slow rate of new residential development in Florida, the PGS business model for system expansion has evolved to focus on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost-per-MMBTU basis. In 2012, PGS acquired a block propane system serving hotels and other commercial customers on Marco Island, a tourist area near Naples, Florida, and extended the distribution system to that block system and converted those hotels and commercial customers to natural gas service. Also in 2012, PGS completed a pipeline expansion project to Amelia Island, north of Jacksonville, Florida, to convert a large paperboard manufacturing facility from petroleum to natural gas service under a long-term contract.

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.

 

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Gas is delivered by the FGT through 65 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville Division receives gas delivered by the Southern Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. PGS also receives gas delivered by Gulfstream Natural Gas Pipeline through seven gate stations, and by its affiliate, SeaCoast Gas Transmission, LLC, through a single gate station in northeast Florida.

PGS procures natural gas supplies using baseload 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.

TECO COAL

In 2012, TECO Coal recorded net income of $50.2 million on sales of 6.3 million tons, compared with $51.5 million on sales of 8.1 million tons in 2011. Lower sales volumes in 2012 reflect much weaker coal market conditions than in 2011. Because the 2012 sales were contracted at a time when the markets were much stronger, the 2012 average net per-ton selling price was more than $95 per ton, compared with almost $88 per ton in 2011. The all-in total per-ton cost of sales was more than $85 per ton compared with almost $80 per ton in 2011. The 2012 cost of sales reflects spreading fixed costs over fewer tons, and costs associated with personnel reductions and with idling certain mining operations. TECO Coal’s effective income tax rate was 24% in 2012, compared with 23% in the 2011 full-year period.

In 2011, TECO Coal recorded full-year net income of $51.5 million on sales of 8.1 million tons, compared to $53.0 million on sales of 8.8 million tons in 2010. In 2010, full-year net income included $4.1 million of favorable net benefits from the settlement of state and federal income tax issues recorded in prior years. The 2011 sales mix was more heavily weighted to specialty coals, which included metallurgical, PCI and stoker coals. Compared to 2010, the 2011 average net per-ton selling price rose 15% to almost $88 per ton due to strong metallurgical coal markets and the product mix being more heavily weighted to higher margin products. The all-in total per-ton cost of production rose 15% to almost $80 per ton from generally higher mining costs due to higher royalty payments and severance taxes, which are a function of selling price, productivity impacts associated with increased safety inspection activities, higher surface mining costs due to higher diesel oil prices and longer hauling distances, and higher purchased coal cost. TECO Coal’s 2011 effective income tax rate was 23%, essentially unchanged from 2010, excluding the income tax settlements discussed above.

TECO Coal Outlook

We expect TECO Coal’s net income to decrease significantly in 2013 compared with 2012 from lower contract selling prices and lower sales volumes. TECO Coal has 90% of its expected 2013 sales of between 5.2 and 5.7 million tons contracted. The average expected selling price across all products is expected to be more than $86 per ton in 2013, which reflects all of the planned 2013 steam coal sales committed and priced. In 2013, specialty coal volumes are expected to be about at 2012 levels and expected to represent about 50% of total sales.

The all-in total cost of production is expected to be below 2012 levels in a range between $81 and $85 per ton due to actions taken in 2012 to reduce mining costs, and lower royalty payments and severance taxes, which are a function of selling price. TECO Coal’s effective income tax rate in 2013 is expected to be 25%.

Various federal tax overhaul proposals include provisions to eliminate depletion accounting for mineral extraction companies, which would increase TECO Coal’s effective income tax rate and reduce net income if those proposals are implemented (see the Risk Factors section).

The lower volume projected for 2013 reflects TECO Coal’s response to market conditions by exercising production discipline through a combination of idling sections of mines, reducing shifts, reducing overtime and reducing volumes produced by contract miners. Mild winter weather in 2012, low natural gas prices and world-wide economic conditions caused the selling price for certain types of coal to decline in 2012, and prices for coal in general remain significantly below levels experienced in 2010 and 2011.

In November 2011, TECO Coal announced that it had made a new discovery of an additional 65 million tons of proven and probable metallurgical coal reserves on properties it controls, and an additional estimated 9 million tons of metallurgical coal classified as resource (non-reserve coal deposits) due to seam thickness. There is an additional 14 million tons of coal classified as resource pending further geologic studies (see Item 2 Properties in the TECO Coal section). These metallurgical coal reserves are located below existing reserves and substantially all of these reserves are owned by TECO Coal, which eliminates royalty payments. The coal from these reserves can be transported by conveyor belt to an existing preparation plant, which has adequate capacity, and thus eliminate trucking costs. TECO Coal has received the permit amendments from the state of Kentucky related to surface development activities to access these reserves. TECO Coal performed preliminary surface and infrastructure development in 2012, but does not expect to begin

 

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the work required to bring these reserves into production until there are clear indications that the current weak metallurgical coal market conditions are improving (see the Capital Investments section of Liquidity, Capital Resources). An additional permit amendment was submitted to modify surface areas required for development of the slopes and shafts to access the reserves.

TECO Coal allocates its reserves by market category. As a result of this allocation, 40.7% of the reserves are classified as metallurgical coal, 40.2% as PCI coal and 19.1% as steam coal. See Item 2 Properties in the TECO Coal section for a discussion of this allocation.

Since 2008, the issuance of permits by the USACE under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions has been challenged in the courts by various entities. These challenges have been appealed by various mining companies affected on a number of occasions, but very few permits have been issued over the past several years. TECO Coal had six permits on the list of permits subject to enhanced review by the EPA under its memorandum of understanding with the USACE, which was issued in September 2009, however, three have subsequently been withdrawn. At this time, TECO Coal has all of the permits required to meet its 2013 sales projections. See the Environmental section, the Section 404 of the Clean Water Act and Coal Surface Mine Permits section for a more detailed discussion of surface mining permit activities.

Coal Markets

Prices for metallurgical coal rose in 2010, driven by increased demand from expanding economies in China and India, and recovering demand in the U.S. and Europe. The U.S. steel industry operated at about a 70% utilization rate in 2010, compared to a 40% utilization rate for most of 2009. During 2010, spot prices for various grades of metallurgical coal produced by TECO Coal and others reportedly ranged from $110 to $180 per short ton. TECO Coal produces high quality metallurgical coals but they are not the equivalent quality of hard coking coal produced in Australia, which has become the benchmark for metallurgical coal prices worldwide. In 2010 prices for this benchmark Australian coal ranged from $200 to $285 per metric ton.

In the first half of 2011, prices for certain grades of Australian metallurgical coal peaked at $335 per metric ton as monsoon rains in Australia caused disruptions in supplies from that important provider of metallurgical coal to Asian markets. Subsequent to that peak, coal prices declined as supplies from Australia returned to the market and concerns related to worldwide demand for steel in the weak international economy became more pronounced. In January 2012, prices for the same grade of Australian metallurgical coal were $235 per metric ton, and in January 2013 the price for those same coals was $165 per metric ton. In the U.S., the steel industry continued to operate above a 70% utilization rate in 2012 and demand for metallurgical coal remained stable. However, weaker demand in the international market and increased supply of metallurgical coal for the domestic markets caused prices for most grades of metallurgical coal to decline significantly in 2012.

In 2012 and 2011, demand for coal used by utilities to generate electricity declined due to mild winter weather, the slow economic recovery in the U.S., and low natural gas prices, which made it more economical to generate electricity with natural gas than with coal, and uncertainty regarding the impact of certain proposed EPA regulations’ on utilities’ ability to burn coal in the future. Various industry reports, and estimates by the EPA, indicated that a number of smaller, older coal-fired utility boilers without current environmental controls would be retired in response to the proposed rules. In December 2011, the United States District Court for the District of Columbia stayed the implementation of the EPA’s proposed CSAPR (see the Environmental section). In January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied the EPA’s request for reconsideration of its ruling against CSAPR, significantly reducing the possibility that the rule will be enforced in its current form. Despite the stay of CSAPR in 2011, demand for coal by utilities remains weak.

The significant factors that could influence TECO Coal’s results in 2013 include the cost of production, the pricing on uncontracted tons, and customers taking contracted volumes. Longer-term factors that could influence results include inventories at steam coal users, weather, the ability for utilities to continue to burn coal under new rules proposed by the EPA, the ability to obtain environmental permits for mining operations, general economic conditions, the level of natural gas prices, commodity price changes that impact the cost of production, and changes in environmental regulations (see the Environmental Compliance and Risk Factors sections).

 

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PARENT/OTHER

In 2012, the cost for Parent /other in continuing operations was $31.4 million in 2012, compared with $36.0 million in 2011. Results for 2012 reflect tax items and lower interest expense as a result of the mid-year 2011 debt retirement, and a charge of $0.8 million associated with the early retirement of the remaining $8.8 million of TECO Energy parent debt. The total cost for Parent & other for 2012 was $35.4 million, compared with $36.6 million in the same period in 2011. Total cost for 2012 includes transaction costs and tax items recorded at Parent related to the TECO Guatemala discontinued operations.

The total cost for Parent/other in 2011 was $36.6 million, compared to $98.5 million in 2010. The 2010 non-GAAP cost was $59.9 million, which excluded the charges and gains described below in the 2010 results discussion. Improved results in 2011 reflect $13.3 million lower interest expense as a result of the 2010 and 2011 debt retirements and the absence of negative tax valuation adjustments that affected results in 2010.

The total 2010 non-GAAP cost for Parent/other was $51.7 million, which excluded a $33.5 million charge related to early retirement of TECO Energy debt, the $1.8 million benefit related to the recovery of fees paid for the previously sold McAdams Power station, and $0.9 million of final restructuring costs (see the 2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results table).

The GAAP cost in 2010 included a $1.1 million charge to adjust deferred tax balances related to Medicare Part D subsidies as a result of the Patient Protection and Affordable Care Act enacted early in 2010. Results in 2010 also included a $3.5 million unfavorable tax adjustment that offset the favorable domestic production deduction at Tampa Electric due to TECO Energy’s consolidated NOL position. Results in 2010 also reflected $3.4 million lower interest expense as a result of debt restructuring and retirement.

DISCONTINUED OPERATIONS (TECO GUATEMALA)

On Sept. 28, 2012, TECO Energy announced that its international power subsidiary, TECO Guatemala, entered into agreements to sell all of its equity interests in the Alborada and San José power stations, and related solid fuel handling and port facilities 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 price of $12.5 million. On Dec. 19, 2012, the sale closed on the San José Power Station and related facilities and operations for a price of $215.0 million (see Note 19 to the TECO Energy Consolidated Financial Statements).

The 2012 losses in discontinued operations of $33.3 million reflect the results from operations of $18.2 million for the generating plants in Guatemala through the closing of the sales, a $28.6 million loss on assets sold including transaction costs, and a $22.9 million charge associated with foreign tax credit write offs.

TECO Guatemala reported full-year net income of $22.4 million in 2011, compared to $41.6 million in 2010. In 2010, non-GAAP results were $39.5 million, which excluded the gain on the sale of DECA II described below, and a related tax charge. Results in 2011 reflected the absence of DECA II earnings, which were $13.2 million in 2010, and $5.2 million of lower capacity payments related to the Alborada Power Station contract extension, which became effective September 2010.

In October 2010, a TECO Guatemala subsidiary sold its 30% interest in DECA II to EPM, a multi-utility company based in Medellín Colombia, for a sales price of $181.5 million. DECA II was a holding company in which, prior to the sale, TECO Guatemala Holdings, LLC (TGH), a wholly-owned subsidiary of TECO Guatemala, held a 30% interest. DECA II held an 80.9% ownership interest in EEGSA and affiliated companies. TECO Guatemala recorded a $27.0 million gain on the sale, but the sale transaction resulted in a total net gain of $21.0 million for TECO Energy due to the $6.0 million negative valuation allowance recorded against foreign tax credits (see the 2010 Reconciliation of GAAP net income from continuing operations to non-GAAP results table). TECO Guatemala also recorded a $24.9 million income tax charge related to the unwinding of the tax deferral structure, as the earnings from DECA II were no longer considered indefinitely reinvested.

On Jan. 13, 2009, TGH delivered a Notice of Intent to the Guatemalan government that it intended to file an arbitration claim against the Republic of Guatemala under the Dominican Republic Central America – United States Free Trade Agreement (DR – CAFTA) alleging a violation of fair and equitable treatment of its investment in EEGSA. On Oct. 20, 2010, TGH filed a Notice of Arbitration with the International Centre for Settlement of Investment Disputes to proceed with its arbitration claim. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, TGH has retained its rights under this claim.

The arbitration was prompted by actions of the Guatemalan government in July 2008, which, among other things, unilaterally reset the distribution tariff for EEGSA at levels well below the tariffs in effect at the time that the distribution

 

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tariff was reset. These actions caused a significant reduction in earnings from EEGSA. As discussed above, until Oct. 21, 2010, TGH held a 24% ownership interest in EEGSA through a holding company DECA II when TGH’s interest was sold. In connection with the sale of TGH’s ownership interest in EEGSA, TGH reserved the right to pursue the arbitration claim described above. Hearings on the matter before an international tribunal began in January 2013, but were not completed. The timing of a final decision is unknown at this time.

OTHER ITEMS IMPACTING NET INCOME

Other Income (Expense)

Other income (expense) of $10.8 million in 2012 and of $7.7 million in 2011 included miscellaneous services at the utilities such as lightning surge protection equipment, royalties for coal mined on properties leased by TECO Coal and from the sale of assets no longer in service.

AFUDC equity at Tampa Electric, which is included in Other income (expense), was $2.6 million, $1.0 million, and $1.9 million in 2012, 2011 and 2010, respectively. AFUDC is expected to increase in 2013 due to the construction of a reclaimed water pipeline to ground water usage at the Polk Power Station and spending related to the Polk Unit 2 – 5 conversion project (see the Liquidity, Capital Resources section).

Interest Expense

In 2012 interest expense was $183.5 million compared to $197.4 million in 2011. In 2012 interest expense decreased due to lower debt balances and lower interest rates on debt at TEC as a result of refinancing activities in 2012 (see Financing Activity section). Interest expense also declined due to an FPSC-approved lower interest rate paid on customer deposits at the utilities.

In 2011, total interest expense was $197.4 million compared to $215.5 million in 2010. In 2011, interest expense decreased due to lower debt balances as a result of the early retirement of TECO Energy and TECO Finance debt in December 2010 and the retirement of $63.7 million of TECO Energy and TECO Finance debt at maturity in May 2011.

Interest expense is expected to be lower in 2013, due to refinancing activity completed by TEC in 2012, and lower debt balances.

Income Taxes

The provision for income taxes decreased in 2012, primarily due to lower operating income. The provision for taxes was higher in 2011, primarily due to higher operating income and state income taxes. Income tax expense as a percentage of income from continuing operations before taxes was 35.9% in 2012, 36.3% in 2011 and 34.1% in 2010. We expect our 2013 annual effective tax rate to range between 37.0% and 38.0%.

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

The cash payments for federal income taxes, as required by the federal AMT rules, state income taxes, foreign income taxes and payments (refunds) related to prior years’ audits totaled $7.2 million, $9.4 million and $5.5 million in 2012, 2011 and 2010, respectively.

Due to the NOL carryforward position resulting from the disposition of the generating assets formerly held by TWG Merchant, our merchant power subsidiary, cash tax payments for income taxes are limited to approximately 10% of the AMT rate. We expect future cash tax payments to be limited to a similar level and various state taxes. Due to additional bonus depreciation allowed in the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 and in the American Taxpayer Relief Act of 2012, we currently project to utilize these NOL carryforwards primarily in the 2015 through 2017 period. Beginning with 2017, we also expect to start using more than $211 million of AMT carry-forward to limit future cash tax payments for federal income taxes to the level of AMT. We currently project minimal cash tax payments over the next five years.

The utilization of the NOL and AMT carryforwards are dependent on the generation of sufficient taxable income in future periods.

 

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LIQUIDITY, CAPITAL RESOURCES

The table below sets forth the Dec. 31, 2012 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/Finance and TEC credit facilities.

 

                                                           
Balances as of Dec. 31, 2012  
     (millions)    Consolidated      Tampa Electric
Company
     Unregulated
Companies
     Parent  

Credit facilities

     $  675.0               $  475.0               $  —                   $  200.0     

Drawn amounts/LCs

     1.5               1.5               —                   —       

Available credit facilities

     673.5               473.5               —                   200.0     

Cash and short-term investments

     200.5               45.2               3.8                 151.5     

Total liquidity

     $874.0               $518.7               $3.8                 $351.5     

In 2012, we met our cash needs primarily from internal sources. Cash from operations was $757 million. We paid dividends of $190 million in 2012, and capital expenditures were $505 million. Other sources of cash included $194 million of net proceeds, primarily from the sale of our ownership interest in TECO Guatemala, (see Discontinued Operations). We reduced long-term debt by $101 million, which included the retirement of $34 million of San José project debt with its sale, $9 million of TECO Energy parent debt and the net effect of Tampa Electric’s refinancing activities. There was no short-term debt outstanding at year-end 2012 or 2011.

In 2011, we met our cash needs primarily from internal sources. Cash from operations was $754 million. We paid dividends of $183 million in 2011, and capital expenditures were $454 million. Net long-term debt declined $154 million, which included the retirement of $64 million of TECO Energy parent and TECO Finance debt and Tampa Electric’s purchase in lieu of redemption of $75 million of tax-exempt notes. Short-term debt declined $12 million.

In 2010, we met our cash needs primarily from internal sources. Cash from operations was $664 million. We paid dividends of $175 million in 2010, and capital expenditures were $490 million. Other sources of cash included $183 million of proceeds, primarily the sale of our ownership interest in DECA II for $181 million. Proceeds from the sale of DECA II, along with repatriated cash of $25 million and cash on hand, were used to retire long-term debt. Net long-term debt declined $136 million, representing debt retirement at TECO Energy parent and TECO Finance and a $75 million remarketing by Tampa Electric of tax-exempt notes previously held in lieu of redemption. Short-term debt declined $43 million.

Cash from Operations

In 2012, consolidated cash flow from operations was $757 million. Although the timing of recoveries, particularly fuel and purchased power, under FPSC-approved cost-recovery clauses can have a significant impact on cash from operations in any one year, in 2012 the net impact was only $9 million. We had anticipated a more significant impact as the 2012 FPSC-approved clause rates provided for refunds of previous over-recoveries; however, lower than expected actual fuel prices resulted in a net over-recovered balance at the end of 2012. The 2012 cash from operations reflects pension contributions of $36 million.

We made minimal cash payments for state and federal income taxes in 2012 (see the Income Taxes section). Bonus depreciation, enacted under economic stimulus legislation annually since 2008, has significantly reduced federal taxable income at Tampa Electric and PGS. We file a consolidated tax return, and under our tax sharing agreements, each subsidiary’s tax payment is determined on a standalone basis. Significant NOL carryforwards are available at TECO Energy parent that can be used to offset taxable income in the consolidated return such that cash payments for federal income taxes are limited to approximately 10% of the AMT rate. During the period of bonus depreciation, taxable income has been reduced significantly by the bonus deductions and as a result we have utilized our NOL carryforwards less than expected in recent years. TECO Energy parent cash flows have therefore been less than expected through this period and our projections for the full utilization of the NOL carryforwards has been extended to 2017. Tampa Electric and PGS have realized higher cash flows in recent years as a result of reduced taxes from bonus depreciation, which has supported their capital spending programs. We expect that this trend will substantially continue in 2013 and 2014 as a result of the extension of bonus depreciation in January 2013 and expected technical guidance from the IRS on repair deductions for generation activities, and that TECO Energy parent will realize the cash benefit of the NOL carryforwards primarily in the 2015 through 2017 period.

We expect cash from operations in 2013 to be lower than the 2012 level. We expect lower net income in 2013 and lower net recoveries under various regulatory clauses to reduce cash from operations. In November 2012, the FPSC approved fuel-adjustment and other recovery clause rates that provide for refunds to customers of estimated 2012 net over-recoveries of fuel and purchased power over 12 months beginning Jan. 1, 2013 (see the Regulation section).

 

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Cash from Investing Activities

Our investing activities in 2012 resulted in a net use of cash of $299 million, which reflects capital expenditures totaling $505 million and the net proceeds from the sale of business/assets of $194 million, primarily from the sale of the TECO Guatemala assets.

We expect capital spending for the next several years to be above 2012 levels, primarily due to generating capacity additions at Tampa Electric (see the Capital Expenditures section).

Cash from Financing Activities

Our financing activities in 2012 resulted in a net use of cash of $301 million. Major items included TEC’s refinancing of $608 million of maturing, called or repurchased debt with $550 million of new long-term debt, the retirement of $34 million of San José project debt with its sale and the repayment of $9 million of TECO Energy parent long-term debt (see the Financing Activity section). We paid $190 million in common stock dividends, and we received $4 million from exercises of stock options.

Cash and Liquidity Outlook

In general, we target consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of at least $500 million. At Dec. 31, 2012, our consolidated liquidity was $874 million, consisting of $519 million at TEC, $351 million at TECO Energy parent and $4 million at the other operating companies.

We expect our sources of cash in 2013 to include cash from operations at levels below 2012, due in large part to lower net income from the operating companies and lower net recoveries under various regulatory clauses in 2013 as described above. We plan to use cash generated in 2013 to fund capital spending estimated at $520 million and for dividends to shareholders. In 2013, Tampa Electric has $52 million of tax-exempt notes due for remarketing. There are no long-term debt maturities in 2013.

We expect to continue to make equity contributions to TEC in order to support the capital structure and financial integrity of the utilities. TEC expects to fund its capital needs with a combination of internally generated cash and equity contributions from us, and we anticipate that these contributions will total $50 million to $70 million in 2013 and $180 million to $200 million in 2014. Because of the delayed recognition of TECO Energy parent cash benefits from the utilization of NOL carryforwards (see the Cash from Operations section) we expect to use cash on hand from the sale of our TECO Guatemala assets (see the Discontinued Operations section) to support investment in the utilities in 2013 and 2014.

Over the next several years, after maintaining Tampa Electric’s and PGS’s capital structure, we expect to repurchase shares to offset dilution from shares issued as compensation, and use additional cash to repurchase shares as market opportunities allow, which in total could be as much as $50 million.

Our goal is to reduce leverage at TECO Finance over time as we are able to utilize our NOL carryforwards and as the equity needs of Tampa Electric normalize after the peak capital spending expected over the next several years during the Polk combined cycle conversion project (see the Capital Expenditures section). Our long-term debt maturities for TECO Finance total $191 million in 2015, $250 million in 2016, $300 million in 2017 and $300 million in 2020.

TEC expects to utilize cash from operations and equity contributions from TECO Energy to support its capital spending program, supplemented with incremental long-term debt and utilization of its credit facilities in proportions to maintain a strong capital structure. Our credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). Although we expect the normal utilization of our credit facilities to be low, we estimate that we could fully utilize the total available capacity under our facilities in 2013 and remain within the covenant restrictions.

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

As a result of our significant reduction of parent debt, and reduced business risk, we have improved our debt credit ratings (see Credit Ratings section). In the unlikely event TEC’s ratings were downgraded to below investment grade, counterparties to our derivative instruments could request immediate payment or full collateralization of net liability positions. If the credit risk-related contingent features underlying these derivative instruments were triggered as of Dec. 31, 2012, we could have been required to post additional collateral or settle existing positions with counterparties totaling $14.9 million, which are TEC positions. In addition, credit provisions in long-term gas transportation agreements of Tampa Electric and PGS would give the transportation providers the right to demand collateral, which we estimate to be approximately $65.5 million. None of our credit facilities or financing agreements have ratings downgrade covenants that

 

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would require immediate repayment or collateralization; however, in the event of a downgrade, our interest expense could be higher.

SHORT-TERM BORROWING

Credit Facilities

At Dec. 31, 2012, and 2011, the following credit facilities and related borrowings existed:

 

           Dec. 31, 2012            Dec. 31, 2011  

(millions)

        
 
Credit
Facilities
  
  
    
 
Borrowings
Outstanding
  
  
    
 
 
Letters of
Credit
Outstanding
  
  
  
         
 
Credit
Facilities
  
  
    
 
Borrowings
Outstanding
  
  
    
 
 
Letters of
Credit
Outstanding
  
  
  

Tampa Electric Company:

                                                          
   

5-year facility(1)

     $325.0           $  —               $1.5                  $325.0           $  —                 $0.7       
    1-year accounts
receivable facility
     150.0           —               —                    150.0           —                 —         

TECO Energy/TECO Finance :

                                                          
   

5-year facility(1)(2)

     200.0           —               —                    200.0           —                 —         

Total

         $675.0           $  —               $1.5                  $675.0           $ —                 $0.7       
  (1) This 5-year facility matures Oct. 25, 2016.
  (2) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

These credit facilities, including the one-year accounts receivable facility that was renewed in February 2013, require commitment fees ranging from 12.5 to 25.0 basis points. There were no borrowings outstanding under the credit facilities at

Dec. 31, 2012 or Dec. 31, 2011.

At Dec. 31, 2012, TECO Finance had a $200 million bank credit facility in place guaranteed by TECO Energy with a maturity date in October 2016. TEC had a bank credit facility totaling $325 million, also maturing in October 2016. In addition, TEC had a $150 million accounts receivable securitized borrowing facility that was renewed in February 2013 with a maturity date of February 14, 2014. The TECO Finance and TEC bank credit facilities both include sub-limits for letters of credit of $200 million. At Dec. 31, 2012, the TECO Finance credit facility was undrawn and no letters of credit were outstanding. At Dec. 31, 2012, the TEC credit facilities were undrawn and $1.5 million of letters of credit were outstanding.

The table below sets forth TECO Finance and TEC maximum, minimum, and average credit facility utilization in 2012.

 

2012 Credit Facility Utilization

 

  (millions)   

Maximum

drawn amount

    

Minimum

drawn amount

    

Average

drawn amount

    

Average    

interest rate    

  TECO Finance

   $ 35.0               $  —                   $ 13.9               1.58%

  Tampa Electric Company

   $ 91.0               $ —                   $ 17.8               0.65%

 

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Significant Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2012, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Dec. 31, 2012. Reference is made to the specific agreements and instruments for more details.

 

(millions, unless otherwise indicated)
Instrument    Financial Covenant(1)    Requirement/Restriction   

Calculation

at Dec. 31, 2012

Tampa Electric Company

              

Credit facility(2)

   Debt/capital    Cannot exceed 65%    46.0%
Accounts receivable credit
facility
(2)
   Debt/capital    Cannot exceed 65%    46.0%

6.25% senior notes

  

Debt/capital

Limit on liens(3)

  

Cannot exceed 60%

Cannot exceed $700

  

46.0%

$0 liens outstanding

Insurance agreement relating to
certain pollution bonds
   Limit on liens(3)    Cannot exceed $469 (7.5% of net assets)    $0 liens outstanding

TECO Energy/TECO Finance

              

Credit facility(2)

   Debt/capital    Cannot exceed 65%    56.1%

TECO Finance 6.75% notes

   Restrictions on secured debt(4)    (5)    (5)
  (1) As defined in each applicable instrument.
  (2) See Note 6 to the TECO Energy Consolidated Financial Statements for a description of the credit facilities.
  (3) If the limitation on liens is exceeded the company is required to provide ratable security to the holders of these notes.
  (4) These restrictions would not apply to first mortgage bonds of Tampa Electric if any were outstanding.
  (5) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by Principal Property or Capital Stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes. At Dec. 31, 2012, neither TECO Energy nor TECO Finance had secured debt outstanding.

Credit Ratings of Senior Unsecured Debt at Dec. 31, 2012

 

     Standard & Poor’s (S&P)    Moody’s    Fitch

Tampa Electric Company

   BBB+                    A3    A-

TECO Energy/TECO Finance

   BBB                      Baa2    BBB

On May 4, 2012, Moody’s upgraded the credit ratings of TEC, TECO Energy and TECO Finance to A3, Baa2 and Baa2, respectively, all with stable outlooks.

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

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

 

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Summary of Contractual Obligations

The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations, which are discussed in a subsequent table.

Contractual Cash Obligations at Dec. 31, 2012

 

(millions)

     Payments Due by Period   
       Total         2013         2014         2015        
 
2016-
2017
 
  
     After 2017   

Long-term debt (1)

                             

Recourse

     $2,975.5         $—           $83.3         $274.5         $633.4         $1,984.3   

Operating leases/rentals (2)

     111.1         19.6         19.1         18.2         28.9         25.3   

Net purchase obligations/commitments (3)

     190.9         94.6         30.0         26.4         34.1         5.8   

Interest payment obligations

     1,773.2         160.3         157.7         146.0         251.0         1058.2   

Pension plans (4)

     175.8         15.1         30.2         39.2         91.3         —     

Total contractual obligations

     $5,226.5         $289.6         $320.3         $504.3         $1,038.7         $3,073.6   
  (1) Includes debt at TECO Finance and TEC (see Note 7 to the TECO Energy Consolidated Financial Statements for a list of long-term debt and the respective due dates).
  (2) The table above excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually (see the Regulation section). One of these agreements, in accordance with EITF 01-08 “Determining Whether an Arrangement Contains a Lease,” has been determined to contain a lease (see Note 12 to the TECO Energy Consolidated Financial Statements).
  (3) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2012, these commitments include Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.
  (4) The total includes the estimated minimum required contributions to the qualified pension plan as of the measurement date. Future contributions are included but they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the TECO Energy Consolidated Financial Statements).

Summary of Contingent Obligations

The following table summarizes the letters of credit and guarantees outstanding that are not included in the Contractual Cash Obligations table above and not otherwise included in our Consolidated Financial Statements.

Contingent Obligations at Dec. 31, 2012

 

  (millions)

                  Commitment Expiration   
            Total (2)      2013         2014         2015        

 

2016 -

2017

  

  

    
 
After
2017(1)
  
  

  Letters of credit

        $ 1.5      $ 0.8       $ —         $ —         $ —         $ 0.7   

  Guarantees

  

Fuel purchase/energy

management (2)

     105.3        —           10.0         —           —           95.3   
     Other      10.2        —           4.8         —           —           5.4   

  Total contingent obligations

        $ 117.0      $ 0.8       $ 14.8       $ —         $ —         $ 101.4   
   (1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2017.
   (2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements.

 

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Table of Contents

CAPITAL INVESTMENTS

Capital Investments

 

              Forecast  
(millions)    Actual 2012      2013      2014      2015-2017      2013 -2017
Total
 

Tampa Electric(1)

                                            

Transmission

     $31               $30         $35             $70                 $135         

Distribution

     103               105         115             325                 545         

Generation

     153               165         170             395                 730         

New generation and transmission

     5               50         210             345                 605         

Other

     28               30         35             95                 160         

Other environmental

     23               40         75             25                 140         

Tampa Electric total

     343               420         640             1,255                 2,315         

Net cash effect of AFUDC, accruals and

retentions(1)

     19                       —             —                 —         

Tampa Electric net

     362               420         640             1,255                 2,315         

Peoples Gas

     98               80         100             310                 490         

Unregulated companies

     45               20         35             120                 175         

Total

     $505