10-Q 1 d726288d10q.htm FORM 10-Q Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

 

 

 

Commission

File No.

  

Exact name of each registrant as specified in

its charter, state of incorporation, address of

principal executive offices, telephone number

  

I.R.S. Employer

Identification Number

1-8180    TECO ENERGY, INC.    59-2052286
   (a Florida corporation)   
   TECO Plaza   
   702 N. Franklin Street   
   Tampa, Florida 33602   
   (813) 228-1111   
1-5007    TAMPA ELECTRIC COMPANY    59-0475140
   (a Florida corporation)   
   TECO Plaza   
   702 N. Franklin Street   
   Tampa, Florida 33602   
   (813) 228-1111   

 

 

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 website, 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 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 Exchange Act).    YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of July 28, 2014 was 233,407,893 . As of July 28, 2014, 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.

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

This combined Form 10-Q 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. Each registrant makes representations only as to information relating to itself and its subsidiaries.

Page 2 of 69

Index to Exhibits appears on page 70

 

 

 


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DEFINITIONS

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

 

Term

 

Meaning

ABS   asset-backed security
ADR   American depository receipt
AFUDC   allowance for funds used during construction
AFUDC - debt   debt component of allowance for funds used during construction
AFUDC - equity   equity component of allowance for funds used during construction
AMT   alternative minimum tax
AOCI   accumulated other comprehensive income
APBO   accumulated postretirement benefit obligation
ARO   asset retirement obligation
BACT   Best Available Control Technology
BTU   British Thermal Unit
CAA   Federal Clean Air Act
CAIR   Clean Air Interstate Rule
capacity clause   capacity cost-recovery clause, as established by the FPSC
CERCLA   Comprehensive Environmental Response, Compensation and Liability Act of 1980
CCRs   coal combustion residuals
CES   Continental Energy Systems
CGESJ   Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMMA   Cardno Marshall Miller & Associates
CMBS   commercial mortgage-backed securities
CMO   collateralized mortgage obligation
CNG   compressed natural gas
CPI   consumer price index
CSAPR   Cross State Air Pollution Rule
CO2   carbon dioxide
CT   combustion turbine
DECA II   Distribución Eléctrica Centro Americana, II, S.A.
DOE   U.S. Department of Energy
DR-CAFTA   Dominican Republic Central America – United States Free Trade Agreement
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

 

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ICSID   International Centre for the Settlement of Investment Disputes
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)
LDS   local distribution companies
LIBOR   London Interbank Offered Rate
MAP-21   Moving Ahead for Progress in the 21st Century Act
MBS   mortgage-backed securities
MD&A   Management’s Discussion and Analysis
Met   metallurgical
MMA   The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU   one million British Thermal Units
MRV   market-related value
MSHA   Mine Safety and Health Administration
MW   megawatt(s)
MWH   megawatt-hour(s)
NAESB   North American Energy Standards Board
NAV   net asset value
NERC   North American Electric Reliability Corporation
NMGC   New Mexico Gas Company, Inc., the principal subsidiary of NMGI
NMGI   New Mexico Gas Intermediate, Inc.
NMPRC   New Mexico Public Regulation Commission
NOL   net operating loss
Note        Note      to consolidated financial statements
NOx   nitrogen oxide
NPNS   normal purchase normal sale
NYMEX   New York Mercantile Exchange
O&M expenses   operations and maintenance expenses
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
PM   particulate matter
PPA   power purchase agreement
PPSA   Power Plant Siting Act
PRP   potentially responsible party
PUHCA 2005   Public Utility Holding Company Act of 2005
REIT   real estate investment trust
REMIC   real estate mortgage investment conduit
RFP   request for proposal

 

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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
Tampa Electric   Tampa Electric, the electric division of Tampa Electric Company
TCAE   Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
TEC   Tampa Electric Company, the principal subsidiary of TECO Energy, Inc.
TECO 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
TGH   TECO Guatemala Holdings, LLC
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. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of June 30, 2014 and Dec. 31, 2013, and the results of their operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three month and six month periods ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 12 through 30 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page
No.
 

Consolidated Condensed Balance Sheets, June 30, 2014 and Dec. 31, 2013

     6-7   

Consolidated Condensed Statements of Income for the three month and six month periods ended June 30, 2014

     8-9   

Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended
June 30, 2014

     10   

Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2014 and 2013

     11   

Notes to Consolidated Condensed Financial Statements

     12-30   

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

 

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

Assets

(millions)

   Jun 30,
2014
    Dec 31,
2013
 

Current assets

    

Cash and cash equivalents

   $ 167.0      $ 185.2   

Receivables, less allowance for uncollectibles of $3.8 and $4.7 at June 30, 2014 and Dec. 31, 2013, respectively

     323.8        287.2   

Inventories, at average cost

    

Fuel

     137.4        118.7   

Materials and supplies

     83.4        85.9   

Derivative assets

     8.2        9.7   

Regulatory assets

     33.7        34.3   

Deferred income taxes

     87.7        100.3   

Prepayments and other current assets

     47.5        34.9   

Income tax receivables

     0.8        1.5   
  

 

 

   

 

 

 

Total current assets

     889.5        857.7   
  

 

 

   

 

 

 

Property, plant and equipment

    

Utility plant in service

    

Electric

     6,941.7        6,934.0   

Gas

     1,324.4        1,308.3   

Construction work in progress

     494.9        386.7   

Other property

     441.5        448.3   
  

 

 

   

 

 

 

Property, plant and equipment, at original costs

     9,202.5        9,077.3   

Accumulated depreciation

     (2,878.4     (2,907.2
  

 

 

   

 

 

 

Total property, plant and equipment, net

     6,324.1        6,170.1   
  

 

 

   

 

 

 

Other assets

    

Regulatory assets

     283.9        293.1   

Derivative assets

     0.5        0.3   

Deferred charges and other assets

     122.8        126.8   
  

 

 

   

 

 

 

Total other assets

     407.2        420.2   
  

 

 

   

 

 

 

Total assets

   $ 7,620.8      $ 7,448.0   
  

 

 

   

 

 

 

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

 

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

 

Liabilities and Capital

(millions)

   Jun 30,
2014
    Dec 31,
2013
 

Current liabilities

    

Long-term debt due within one year

   $ 274.5      $ 83.3   

Notes payable

     0.0        84.0   

Accounts payable

     232.3        261.7   

Customer deposits

     167.5        164.5   

Regulatory liabilities

     65.7        85.8   

Derivative liabilities

     0.2        0.1   

Interest accrued

     34.4        31.9   

Taxes accrued

     68.2        34.6   

Other

     18.4        19.5   
  

 

 

   

 

 

 

Total current liabilities

     861.2        765.4   
  

 

 

   

 

 

 

Other liabilities

    

Deferred income taxes

     497.4        444.0   

Investment tax credits

     9.2        9.4   

Regulatory liabilities

     621.4        631.4   

Derivative liabilities

     0.1        0.2   

Deferred credits and other liabilities

     422.0        426.1   

Long-term debt, less amount due within one year

     2,863.1        2,837.8   
  

 

 

   

 

 

 

Total other liabilities

     4,413.2        4,348.9   
  

 

 

   

 

 

 

Commitments and contingencies (see Note 10)

    

Capital

    

Common equity (400.0 million shares authorized; par value $1; 217.8 million and 217.3 million shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively)

     217.8        217.3   

Additional paid in capital

     1,587.8        1,581.3   

Retained earnings

     560.9        548.3   

Accumulated other comprehensive loss

     (20.1     (13.2
  

 

 

   

 

 

 

Total capital

     2,346.4        2,333.7   
  

 

 

   

 

 

 

Total liabilities and capital

   $ 7,620.8      $ 7,448.0   
  

 

 

   

 

 

 

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

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

         Three months ended Jun 30,  

(millions, except per share amounts)

       2014     2013  

Revenues

      

Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.8 in 2014 and $26.7 in 2013)

   $ 603.6      $ 604.0   

Unregulated

     122.7        131.9   
    

 

 

   

 

 

 

Total revenues

     726.3        735.9   
    

 

 

   

 

 

 

Expenses

      

Regulated operations and maintenance

      

Fuel

       169.7        174.5   

Purchased power

       19.9        20.5   

Cost of natural gas sold

       29.1        40.7   

Other

       126.8        129.6   

Operation and maintenance other expense

      

Mining related costs

       103.5        110.2   

Other

       4.8        3.4   

Depreciation and amortization

       84.2        83.9   

Taxes, other than income

       55.1        53.6   
    

 

 

   

 

 

 

Total expenses

       593.1        616.4   
    

 

 

   

 

 

 

Income from continuing operations

       133.2        119.5   
    

 

 

   

 

 

 

Other income

      

Allowance for other funds used during construction

     2.0        1.4   

Other income

       (0.2     1.6   
    

 

 

   

 

 

 

Total other income

       1.8        3.0   
    

 

 

   

 

 

 

Interest charges

      

Interest expense

       42.9        43.5   

Allowance for borrowed funds used during construction

     (0.7     (0.8
    

 

 

   

 

 

 

Total interest charges

       42.2        42.7   
    

 

 

   

 

 

 

Income from continuing operations before provision for income taxes

     92.8        79.8   

Provision for income taxes

       34.4        28.2   
    

 

 

   

 

 

 

Net income from continuing operations

       58.4        51.6   
    

 

 

   

 

 

 

Discontinued operations

      

Loss from discontinued operations

       0.0        (0.2

Provision for income taxes

       0.0        0.0   
    

 

 

   

 

 

 

Loss from discontinued operations, net

     0.0        (0.2
    

 

 

   

 

 

 

Net income

     $ 58.4      $ 51.4   
    

 

 

   

 

 

 

Average common shares outstanding

 

– Basic

     215.4        215.0   
 

– Diluted

     215.9        215.5   
    

 

 

   

 

 

 

Earnings per share from continuing operations

 

– Basic

   $ 0.27      $ 0.24   
 

– Diluted

   $ 0.27      $ 0.24   
    

 

 

   

 

 

 

Earnings per share from discontinued operations

 

– Basic

   $ 0.00      $ 0.00   
 

– Diluted

   $ 0.00      $ 0.00   
    

 

 

   

 

 

 

Earnings per share

 

– Basic

   $ 0.27      $ 0.24   
 

– Diluted

   $ 0.27      $ 0.24   
    

 

 

   

 

 

 

Dividends paid per common share outstanding

     $ 0.22      $ 0.22   

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

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

         Six months ended Jun 30,  

(millions, except per share amounts)

       2014     2013  

Revenues

      

Regulated electric and gas (includes franchise fees and gross receipts taxes of $55.0 in 2014 and $52.1 in 2013)

   $ 1,179.3      $ 1,143.1   

Unregulated

       231.1        253.9   
    

 

 

   

 

 

 

Total revenues

       1,410.4        1,397.0   
    

 

 

   

 

 

 

Expenses

      

Regulated operations and maintenance

      

Fuel

       319.3        314.5   

Purchased power

       38.1        35.1   

Cost of natural gas sold

       76.2        90.2   

Other

       247.4        250.4   

Operation and maintenance other expense

      

Mining related costs

       194.7        205.7   

Other

       7.9        4.7   

Depreciation and amortization

       169.1        165.9   

Taxes, other than income

       111.4        106.9   
    

 

 

   

 

 

 

Total expenses

       1,164.1        1,173.4   
    

 

 

   

 

 

 

Income from continuing operations

       246.3        223.6   
    

 

 

   

 

 

 

Other income

      

Allowance for other funds used during construction

       4.4        2.5   

Other income

       (0.9     3.2   
    

 

 

   

 

 

 

Total other income

       3.5        5.7   
    

 

 

   

 

 

 

Interest charges

      

Interest expense

       85.4        86.5   

Allowance for borrowed funds used during construction

     (2.1     (1.4
    

 

 

   

 

 

 

Total interest charges

       83.3        85.1   
    

 

 

   

 

 

 

Income from continuing operations before provision for income taxes

     166.5        144.2   

Provision for income taxes

       61.1        51.4   
    

 

 

   

 

 

 

Net income from continuing operations

       105.4        92.8   
    

 

 

   

 

 

 

Discontinued operations

      

Income from discontinued operations

       5.0        0.2   

Provision for income taxes

       1.9        0.1   
    

 

 

   

 

 

 

Income from discontinued operations, net

     3.1        0.1   
    

 

 

   

 

 

 

Net income

     $ 108.5      $ 92.9   
    

 

 

   

 

 

 

Average common shares outstanding

 

– Basic

     215.3        214.8   
 

– Diluted

     215.8        215.3   
    

 

 

   

 

 

 

Earnings per share from continuing operations

 

– Basic

   $ 0.49      $ 0.43   
 

– Diluted

   $ 0.49      $ 0.43   
    

 

 

   

 

 

 

Earnings per share from discontinued operations

 

– Basic

   $ 0.01      $ 0.00   
 

– Diluted

   $ 0.01      $ 0.00   
    

 

 

   

 

 

 

Earnings per share

 

– Basic

   $ 0.50      $ 0.43   
 

– Diluted

   $ 0.50      $ 0.43   
    

 

 

   

 

 

 

Dividends paid per common share outstanding

     $ 0.44      $ 0.44   

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

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

     Three months ended Jun 30,     Six months ended Jun 30,  

(millions)

   2014      2013     2014     2013  

Net income

   $ 58.4       $ 51.4      $ 108.5      $ 92.9   
  

 

 

    

 

 

   

 

 

   

 

 

 

Other comprehensive income, net of tax

         

Net unrealized gains (losses) on cash flow hedges

     0.1         (0.1     0.3        0.3   

Amortization of unrecognized benefit costs

     0.5         0.7        1.0        1.4   

Increase in unrecognized postemployment costs

     0.0         0.0        (8.2     0.0   
  

 

 

    

 

 

   

 

 

   

 

 

 

Other comprehensive income (loss), net of tax

     0.6         0.6        (6.9     1.7   
  

 

 

    

 

 

   

 

 

   

 

 

 

Comprehensive income

   $ 59.0       $ 52.0      $ 101.6      $ 94.6   
  

 

 

    

 

 

   

 

 

   

 

 

 

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

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Six months ended Jun 30,  

(millions)

   2014     2013  

Cash flows from operating activities

    

Net income

   $ 108.5      $ 92.9   

Adjustments to reconcile net income to net cash from operating activities:

    

Depreciation and amortization

     169.1        165.9   

Deferred income taxes

     62.0        52.1   

Investment tax credits

     (0.2     (0.2

Allowance for other funds used during construction

     (4.4     (2.5

Non-cash stock compensation

     7.1        6.9   

Gain on sales of business/assets, pretax

     (0.1     (0.2

Deferred recovery clauses

     (14.4     (5.9

Receivables, less allowance for uncollectibles

     (36.6     (38.5

Inventories

     (16.2     (19.7

Prepayments and other current assets

     (2.1     (4.3

Taxes accrued

     34.3        28.1   

Interest accrued

     2.5        2.0   

Accounts payable

     (36.0     13.0   

Other

     (12.5     (1.8
  

 

 

   

 

 

 

Cash flows from operating activities

     261.0        287.8  
  

 

 

   

 

 

 

Cash flows from investing activities

    

Capital expenditures

     (320.3     (249.6

Allowance for other funds used during construction

     4.4        2.5   

Net proceeds from sales of business/assets

     0.3        0.3   
  

 

 

   

 

 

 

Cash flows used in investing activities

     (315.6     (246.8 )
  

 

 

   

 

 

 

Cash flows from financing activities

    

Dividends

     (95.9     (95.6

Proceeds from the sale of common stock

     3.0        7.4   

Proceeds from long-term debt issuance

     296.6        0.0   

Repayment of long-term debt/Purchase in lieu of redemption

     (83.3     0.0   

Net decrease in short-term debt

     (84.0     0.0   
  

 

 

   

 

 

 

Cash flows from (used) in financing activities

     36.4        (88.2 )
  

 

 

   

 

 

 

Net decrease in cash and cash equivalents

     (18.2     (47.2 )

Cash and cash equivalents at beginning of the period

     185.2        200.5  
  

 

 

   

 

 

 

Cash and cash equivalents at end of the period

   $ 167.0      $ 153.3  
  

 

 

   

 

 

 

Supplemental disclosure of non-cash activities

    

Capital expenditures accrued-excluded above

   $ 8.6      $ (3.1

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

 

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three months and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements, however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TECO Coal incurs most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

Cash Flows Related to Derivatives and Hedging Activities

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

 

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2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for the company beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for the company beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC under PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations 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 sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC.

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year.

 

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Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

 

Regulatory Assets and Liabilities

             

(millions)

   Jun 30, 2014      Dec 31, 2013  

Regulatory assets:

     

Regulatory tax asset (1)

   $ 68.1       $ 67.4   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     1.8         6.1   

Postretirement benefit asset

     177.6         182.7   

Deferred bond refinancing costs (2)

     7.6         8.0   

Environmental remediation

     52.0         51.4   

Competitive rate adjustment

     2.8         4.1   

Other

     7.7         7.7   
  

 

 

    

 

 

 

Total other regulatory assets

     249.5         260.0   
  

 

 

    

 

 

 

Total regulatory assets

     317.6         327.4   

Less: Current portion

     33.7         34.3   
  

 

 

    

 

 

 

Long-term regulatory assets

   $ 283.9       $ 293.1   
  

 

 

    

 

 

 

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 5.6       $ 9.8   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     34.8         54.5   

Transmission and delivery storm reserve

     56.1         56.1   

Deferred gain on property sales (3)

     1.4         2.0   

Provision for stipulation and other

     0.8         0.8   

Accumulated reserve - cost of removal

     588.4         594.0   
  

 

 

    

 

 

 

Total other regulatory liabilities

     681.5         707.4   
  

 

 

    

 

 

 

Total regulatory liabilities

     687.1         717.2   

Less: Current portion

     65.7         85.8   
  

 

 

    

 

 

 

Long-term regulatory liabilities

   $ 621.4       $ 631.4   
  

 

 

    

 

 

 

 

(1) Primarily related to plant life and derivative positions.
(2) Amortized over the term of the related debt instruments.
(3) Amortized over a 5-year period with various ending dates.

All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:

 

Regulatory Assets

   Jun 30,      Dec 31,  

(millions)

   2014      2013  

Clause recoverable (1)

   $ 4.6       $ 10.2   

Components of rate base (2)

     180.7         185.6   

Regulatory tax assets (3)

     68.1         67.4   

Capital structure and other (3)

     64.2         64.2   
  

 

 

    

 

 

 

Total

   $ 317.6       $ 327.4   
  

 

 

    

 

 

 

 

(1) To be recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

 

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4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for years 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2010 and forward.

The effective tax rate increased to 36.71% for the six months ended June 30, 2014 from 35.64% for the same period in 2013.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company.

 

Pension Expense

                        
(millions)    Pension Benefits     Other Postretirement Benefits  

Three months ended Jun 30,

   2014     2013     2014     2013  

Components of net periodic benefit expense

        

Service cost

   $ 4.2      $ 4.3      $ 0.6      $ 0.5   

Interest cost on projected benefit obligations

     8.2        7.2        2.6        2.4   

Expected return on assets

     (10.4     (9.5     0.0        0.0   

Amortization of:

        

Prior service (benefit) cost

     (0.1     (0.1     (0.1     (0.1

Actuarial loss

     3.5        5.3        0.1        0.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net pension expense recognized in the

        

TECO Energy Consolidated Condensed Statements of Income

   $ 5.4      $ 7.2      $ 3.2      $ 3.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Six months ended Jun 30,

                        

Components of net periodic benefit expense

        

Service cost

   $ 8.3      $ 9.1      $ 1.2      $ 1.2   

Interest cost on projected benefit obligations

     16.4        14.4        5.2        4.7   

Expected return on assets

     (20.7     (19.2     0.0        0.0   

Amortization of:

        

Prior service (benefit) cost

     (0.2     (0.2     (0.1     (0.2

Actuarial loss

     6.7        10.3        0.1        0.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net pension expense recognized in the

        

TECO Energy Consolidated Condensed Statements of Income

   $ 10.5      $ 14.4      $ 6.4      $ 6.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

For the 2014 plan year, TECO Energy is using an assumed long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan for the six months ended June 30, 2014.

For the three and six months ended June 30, 2014, TECO Energy and its subsidiaries reclassed $0.7 million and $1.3 million pretax, respectively, of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

 

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6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

 

Credit Facilities

                                         
     Jun 30, 2014      Dec 31, 2013  

(millions)

   Credit
Facilities
     Borrowings
Outstanding (1)
     Letters
of Credit
Outstanding
     Credit
Facilities
     Borrowings
Outstanding (1)
     Letters
of Credit
Outstanding
 

Tampa Electric Company:

                 

5-year facility (2)

   $ 325.0       $ 0.0       $ 0.7       $ 325.0       $ 6.0       $ 0.7   

1-year accounts receivable facility

     150.0         0.0         0.0         150.0         78.0         0.0   

TECO Energy/TECO Finance:

                 

5-year facility (2)(3)

     200.0         0.0         0.0         200.0         0.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 675.0       $ 0.0       $ 0.7      $ 675.0       $ 84.0       $ 0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Dec. 17, 2018.
(3) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

 

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7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, total long-term debt had a carrying amount of $3,137.6 million and an estimated fair market value of $3,469.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

 

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8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and six months ended June 30, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

 

Other Comprehensive Income

                                    
     Three months ended Jun 30,     Six months ended Jun 30,  

(millions)

   Gross     Tax     Net     Gross     Tax     Net  

2014

            

Unrealized gain on cash flow hedges

   $ 0.1      $ 0.0      $ 0.1      $ 0.0      $ 0.0      $ 0.0   

Reclassification from AOCI to net income (1)

     0.1        (0.1     0.0        0.5        (0.2     0.3   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gain on cash flow hedges

     0.2        (0.1     0.1        0.5        (0.2     0.3   

Amortization of unrecognized benefit costs (2)

     0.8        (0.3     0.5        1.6        (0.6     1.0   

Increase in unrecognized postemployment costs(3)

     0.0        0.0        0.0        (12.9     4.7        (8.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss)

   $ 1.0      ($ 0.4   $ 0.6      ($ 10.8   $ 3.9      ($ 6.9
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2013

            

Unrealized loss on cash flow hedges

   ($ 0.7   $ 0.3      ($ 0.4   ($ 0.4   $ 0.2      ($ 0.2

Reclassification from AOCI to net income (1)

     0.5        (0.2     0.3        0.8        (0.3     0.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(Loss) Gain on cash flow hedges

     (0.2     0.1        (0.1     0.4        (0.1     0.3   

Amortization of unrecognized benefit costs (2)

     1.1        (0.4     0.7        2.2        (0.8     1.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income

   $ 0.9      ($ 0.3   $ 0.6      $ 2.6      ($ 0.9   $ 1.7   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Mining related costs.
(2) Related to postretirement and postemployment benefits. See Note 5 for additional information.
(3) Amount reflects an out-of-period adjustment to TECO Coal’s unfunded black lung liability.

 

Accumulated Other Comprehensive Loss

            

(millions)

   Jun 30, 2014     Dec 31, 2013  

Unrecognized pension loss and prior service credit (1)

   ($ 19.7   ($ 20.5

Unrecognized other benefit loss, prior service cost and transition obligation (2)

     7.1        15.1   

Net unrealized losses from cash flow hedges (3)

     (7.5     (7.8
  

 

 

   

 

 

 

Total accumulated other comprehensive loss

   ($ 20.1   ($ 13.2
  

 

 

   

 

 

 

 

(1) Net of tax benefit of $12.1 million and $12.6 million as of June 30, 2014 and Dec. 31, 2013, respectively.
(2) Net of tax expense of $4.4 million and $9.1 million as of June 30, 2014 and Dec. 31, 2013, respectively.
(3) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

 

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9. Earnings Per Share

 

     For the three months ended Jun 30,     For the six months ended Jun 30,  

(millions, except per share amounts)

   2014     2013     2014     2013  

Basic earnings per share

        

Net income from continuing operations

   $ 58.4      $ 51.6      $ 105.4      $ 92.8   

Amount allocated to nonvested participating shareholders

     (0.2     (0.2     (0.4     (0.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before discontinued operations available to common shareholders - Basic

   $ 58.2      $ 51.4      $ 105.0      $ 92.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) from discontinued operations, net

   $ 0.0      ($ 0.2   $ 3.1      $ 0.1   

Amount allocated to nonvested participating shareholders

     0.0        0.0        0.0        0.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) from discontinued operations available to common shareholders - Basic

   $ 0.0      ($ 0.2   $ 3.1      $ 0.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 58.4      $ 51.4      $ 108.5      $ 92.9   

Amount allocated to nonvested participating shareholders

     (0.2     (0.2     (0.4     (0.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income available to common shareholders - Basic

   $ 58.2      $ 51.2      $ 108.1      $ 92.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Average common shares outstanding - Basic

     215.4        215.0        215.3        214.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share from continuing operations available to common shareholders - Basic

   $ 0.27      $ 0.24      $ 0.49      $ 0.43   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share from discontinued operations available to common shareholders - Basic

   $ 0.00      $ 0.00      $ 0.01      $ 0.00   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share available to common shareholders - Basic

   $ 0.27      $ 0.24      $ 0.50      $ 0.43   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted earnings per share

        

Net income from continuing operations

   $ 58.4      $ 51.6      $ 105.4      $ 92.8   

Amount allocated to nonvested participating shareholders

     (0.2     (0.2     (0.4     (0.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before discontinued operations available to common shareholders - Diluted

   $ 58.2      $ 51.4      $ 105.0      $ 92.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) from discontinued operations, net

   $ 0.0      ($ 0.2   $ 3.1      $ 0.1   

Amount allocated to nonvested participating shareholders

     0.0        0.0        0.0        0.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) from discontinued operations available to common shareholders - Diluted

   $ 0.0      ($ 0.2   $ 3.1      $ 0.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 58.4      $ 51.4      $ 108.5      $ 92.9   

Amount allocated to nonvested participating shareholders

     (0.2     (0.2     (0.4     (0.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income available to common shareholders - Diluted

   $ 58.2      $ 51.2      $ 108.1      $ 92.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Unadjusted average common shares outstanding - Diluted

     215.4        215.0        215.3        214.8   

Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net

     0.5        0.5        0.5        0.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Average common shares outstanding - Diluted

     215.9        215.5        215.8        215.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share from continuing operations available to common shareholders - Diluted

   $ 0.27      $ 0.24      $ 0.49      $ 0.43   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share from discontinued operations available to common shareholders - Diluted

   $ 0.00      $ 0.00      $ 0.01      $ 0.00   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share available to common shareholders - Diluted

   $ 0.27      $ 0.24      $ 0.50      $ 0.43   
  

 

 

   

 

 

   

 

 

   

 

 

 

Anti-dilutive shares

     0.0        0.0        0.0        0.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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10. Commitments and Contingencies

Legal Contingencies

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 loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

The company believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, Inc., against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. Pursuant to ICSID’s rules and procedures, each party had 120 days after the date of the Award to file an application for its annulment.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Guatemala also requested that the enforcement of the Award be stayed while the annulment proceeding is pending. Under the applicable rules, the enforcement of the Award is provisionally stayed until the ad hoc committee that will be deciding Guatemala’s application is constituted and makes a decision regarding whether the stay should continue through the rest of the annulment proceeding.

Also on April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, they are expected to take approximately two years to conclude. Pending the outcome of annulment proceedings, results in the second quarter of 2014 do not reflect any benefit of this decision.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. 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 estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

 

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Table of Contents

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of June 30, 2014 is as follows:

 

Guarantees - TECO Energy

                                  

(millions)

Guarantees for the Benefit of:

   2014      2015-2018      After(1)
2018
     Total      Liabilities Recognized
at Jun 30, 2014
 

TECO Coal

              

Fuel purchase related (2)

   $ 0.0       $ 0.7       $ 4.0       $ 4.7       $ 0.6   

Other subsidiaries

              

Fuel purchase/energy management (2)

     0.0         0.0         92.9         92.9         0.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.7       $ 96.9       $ 97.6       $ 0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Letters of Credit - Tampa Electric Company

                                  

(millions)

Letters of Credit for the Benefit of:

   2014      2015-2018      After(1)
2018
     Total      Liabilities Recognized
at Jun 30, 2014
 

Tampa Electric Company(2)

   $ 0.0       $ 0.0       $ 0.7       $ 0.7       $ 0.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.0       $ 0.7       $ 0.7       $ 0.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at June 30, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, 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 June 30, 2014, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.

 

21


Table of Contents

Segment Information (1)

                                

(millions)

Three months ended Jun 30,

   Tampa
Electric
     Peoples
Gas
     TECO
Coal
    Other &
Eliminations
    TECO
Energy
 

2014

            

Revenues - external

   $ 512.5       $ 90.7       $ 120.6      $ 2.5      $ 726.3   

Sales to affiliates

     0.2         0.4         0.0        (0.6     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total revenues

     512.7         91.1         120.6        1.9        726.3   

Depreciation and amortization

     61.7         13.4         8.7        0.4        84.2   

Total interest charges(1)

     23.3         3.4         1.5        14.0        42.2   

Internally allocated interest (1)

     0.0         0.0         1.5        (1.5     0.0   

Provision (benefit) for income taxes

     37.1         4.8         (0.7     (6.8     34.4   

Net income (loss) from continuing operations

     62.2         7.5         0.8        (12.1     58.4   

Income from discontinued operations, net

     0.0         0.0         0.0        0.0        0.0   

Net income (loss)

   $ 62.2       $ 7.5       $ 0.8      ($ 12.1   $ 58.4   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

2013

            

Revenues - external

   $ 502.6       $ 101.3       $ 128.4      $ 3.6      $ 735.9   

Sales to affiliates

     0.3         0.5         0.0        (0.8     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total revenues

     502.9         101.8         128.4        2.8        735.9   

Depreciation and amortization

     60.8         13.2         9.5        0.4        83.9   

Total interest charges(1)

     23.3         3.3         1.7        14.4        42.7   

Internally allocated interest (1)

     0.0         0.0         1.7        (1.7     0.0   

Provision (benefit) for income taxes

     31.5         5.0         (0.9     (7.4     28.2   

Net income (loss) from continuing operations

     50.6         7.9         0.7        (7.6     51.6   

Income from discontinued operations, net

     0.0         0.0         0.0        (0.2     (0.2

Net income (loss)

   $ 50.6       $ 7.9       $ 0.7      ($ 7.8   $ 51.4   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

(millions)

Six months ended Jun 30,

   Tampa
Electric
     Peoples
Gas
     TECO
Coal
    Other &
Eliminations
    TECO
Energy
 

2014

            

Revenues - external

   $ 965.4       $ 213.1       $ 226.7      $ 5.2      $ 1,410.4   

Sales to affiliates

     0.5         0.6         0.0        (1.1     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total revenues

     965.9         213.7         226.7        4.1        1,410.4   

Depreciation and amortization

     123.8         26.7         17.7        0.9        169.1   

Total interest charges(1)

     45.3         6.8         3.0        28.2        83.3   

Internally allocated interest (1)

     0.0         0.0         3.0        (3.0     0.0   

Provision (benefit) for income taxes

     63.7         14.0         (2.9     (13.7     61.1   

Net income (loss) from continuing operations

     107.4         22.1         (0.8     (23.3     105.4   

Income from discontinued operations, net

     0.0         0.0         0.0        3.1        3.1   

Net income (loss)

   $ 107.4       $ 22.1       $ (0.8   $ (20.2   $ 108.5   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

2013

            

Revenues - external

   $ 920.4       $ 223.2       $ 246.3      $ 7.1      $ 1,397.0   

Sales to affiliates

     0.5         0.5         0.0        (1.0     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total revenues

     920.9         223.7         246.3        6.1        1,397.0   

Depreciation and amortization

     119.8         26.2         19.2        0.7        165.9   

Total interest charges(1)

     46.7         6.7         3.4        28.3        85.1   

Internally allocated interest (1)

     0.0         0.0         3.3        (3.3     0.0   

Provision (benefit) for income taxes

     51.3         13.7         (1.0     (12.6     51.4   

Net income (loss) from continuing operations

     82.4         21.7         3.7        (15.0     92.8   

Income from discontinued operations, net

     0.0         0.0         0.0        0.1        0.1   

Net income (loss)

   $ 82.4       $ 21.7       $ 3.7      $ (14.9   $ 92.9   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

At Jun 30, 2014

            

Total assets

   $ 6,311.9       $ 1,034.1       $ 333.3      ($ 58.5   $ 7,620.8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

At Dec 31, 2013

            

Total assets

   $ 6,126.9       $ 1,021.2       $ 316.3      ($ 16.4   $ 7,448.0   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2013 through June 2014 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

 

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Table of Contents

12. Accounting for Derivative Instruments and Hedging Activities

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

 

    to limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS,

 

    to limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates, and

 

    to limit the exposure to price fluctuations for physical purchases of fuel at TECO Coal.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at June 30, 2014 and Dec. 31, 2013:

 

Total Derivatives(1)

             

(millions)

   Jun 30,
2014
     Dec 31,
2013
 

Current assets

   $ 8.2       $ 9.7   

Long-term assets

     0.5         0.3   
  

 

 

    

 

 

 

Total assets

   $ 8.7       $ 10.0   
  

 

 

    

 

 

 

Current liabilities

   $ 0.2       $ 0.1   

Long-term liabilities

     0.1         0.2   
  

 

 

    

 

 

 

Total liabilities

   $ 0.3       $ 0.3   
  

 

 

    

 

 

 

 

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties.

 

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Table of Contents
Offsetting of Derivative Assets and Liabilities              

(millions)

                  
     Gross Amounts
of Recognized
Assets
(Liabilities)
    Gross
Amounts offset
on the Balance
Sheet
    Net Amounts of
Assets (Liabilities)
Presented on the
Balance Sheet
 

Jun 30, 2014

                  

Description

      

Derivative assets

   $ 9.9      $ (1.2   $ 8.7   

Derivative liabilities

   $ (1.5   $ 1.2      $ (0.3

Dec 31, 2013

                  

Description

      

Derivative assets

   $ 10.5      $ (0.5   $ 10.0   

Derivative liabilities

   $ (0.8   $ 0.5      $ (0.3

The following table presents the derivative hedges of diesel fuel contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

 

Diesel Fuel Derivatives

             

(millions)

   Jun 30,
2014
     Dec 31,
2013
 

Current assets

   $ 0.1       $ 0.2   

Long-term assets

     0.0         0.0   
  

 

 

    

 

 

 

Total assets

   $ 0.1       $ 0.2   
  

 

 

    

 

 

 

Current liabilities

   $ 0.0       $ 0.1   

Long-term liabilities

     0.0         0.0   
  

 

 

    

 

 

 

Total liabilities

   $ 0.0       $ 0.1   
  

 

 

    

 

 

 

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

 

Natural Gas Derivatives

             

(millions)

   Jun 30,
2014
     Dec 31,
2013
 

Current assets

   $ 8.1       $ 9.5   

Long-term assets

     0.5         0.3   
  

 

 

    

 

 

 

Total assets

   $ 8.6       $ 9.8   
  

 

 

    

 

 

 

Current liabilities

   $ 0.2       $ 0.0   

Long-term liabilities

     0.1         0.2   
  

 

 

    

 

 

 

Total liabilities

   $ 0.3       $ 0.2   
  

 

 

    

 

 

 

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at June 30, 2014 is a net loss of $7.5 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

 

24


Table of Contents

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2014 and Dec. 31, 2013:

 

Derivatives Designated as Hedging Instruments

                       
     Asset Derivatives      Liability Derivatives  

(millions)

Jun 30, 2014

   Balance Sheet
Location
   Fair
Value
     Balance Sheet
Location
   Fair
Value
 

Commodity Contracts:

           

Diesel fuel derivatives:

           

Current

   Derivative assets    $ 0.1       Derivative liabilities    $ 0.0   

Long-term

   Derivative assets      0.0       Derivative liabilities      0.0   

Natural gas derivatives:

           

Current

   Derivative assets      8.1       Derivative liabilities      0.2   

Long-term

   Derivative assets      0.5       Derivative liabilities      0.1   
     

 

 

       

 

 

 

Total derivatives designated as hedging instruments

      $ 8.7          $ 0.3   
     

 

 

       

 

 

 

 

     Asset Derivatives      Liability Derivatives  

(millions)

Dec 31, 2013

   Balance Sheet
Location
   Fair
Value
     Balance Sheet
Location
   Fair
Value
 

Commodity Contracts:

           

Diesel fuel derivatives:

           

Current

   Derivative assets    $ 0.2       Derivative liabilities    $ 0.1   

Long-term

   Derivative assets      0.0       Derivative liabilities      0.0   

Natural gas derivatives:

           

Current

   Derivative assets      9.5       Derivative liabilities      0.0   

Long-term

   Derivative assets      0.3       Derivative liabilities      0.2   
     

 

 

       

 

 

 

Total derivatives designated as hedging instruments

      $ 10.0          $ 0.3   
     

 

 

       

 

 

 

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

 

Energy Related Derivatives

             
     Asset Derivatives      Liability Derivatives  

(millions)

Jun 30, 2014

   Balance Sheet
Location (1)
   Fair
Value
     Balance Sheet
Location (1)
   Fair
Value
 

Commodity Contracts:

           

Natural gas derivatives:

           

Current

   Regulatory liabilities    $ 8.1       Regulatory assets    $ 0.2   

Long-term

   Regulatory liabilities      0.5       Regulatory assets      0.1   
     

 

 

       

 

 

 

Total

      $ 8.6          $ 0.3   
     

 

 

       

 

 

 

(millions)

Dec 31, 2013

   Balance Sheet
Location (1)
   Fair
Value
     Balance Sheet
Location (1)
   Fair
Value
 

Commodity Contracts:

           

Natural gas derivatives:

           

Current

   Regulatory liabilities    $ 9.5       Regulatory assets    $ 0.0   

Long-term

   Regulatory liabilities      0.3       Regulatory assets      0.2   
     

 

 

       

 

 

 

Total

      $ 9.8          $ 0.2   
     

 

 

       

 

 

 

 

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

 

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Table of Contents

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

The following table presents the effect of hedging instruments on OCI and income for the three and six months ended June 30:

 

For the three months ended Jun 30:

 

(millions)

   Amount of
Gain/(Loss) on
Derivatives
Recognized in
OCI
    Location of Gain/(Loss)
Reclassified From AOCI
Into Income
     Amount of
Gain/(Loss)
Reclassified
From AOCI
Into Income
 

Derivatives in Cash Flow Hedging Relationships

     Effective Portion (1)           Effective Portion (1)   

2014

       

Interest rate contracts

   $ 0.0        Interest expense       $ 0.0   

Commodity contracts:

       

Diesel fuel derivatives

     0.1        Mining related costs         0.0   
  

 

 

      

 

 

 

Total

   $ 0.1         $ 0.0   
  

 

 

      

 

 

 

2013

       

Interest rate contracts

   $ 0.0        Interest expense       ($ 0.2

Commodity contracts:

       

Diesel fuel derivatives

     (0.4     Mining related costs         (0.1
  

 

 

      

 

 

 

Total

   ($ 0.4      ($ 0.3
  

 

 

      

 

 

 

For the six months ended Jun 30:

 

(millions)

   Amount of
Gain/(Loss) on
Derivatives
Recognized in
OCI
    Location of Gain/(Loss)
Reclassified From AOCI
Into Income
     Amount of
Gain/(Loss)
Reclassified
From AOCI
Into Income
 

Derivatives in Cash Flow Hedging Relationships

     Effective Portion (1)           Effective Portion  (1) 

2014

       

Interest rate contracts

   $ 0.0        Interest expense       ($ 0.2

Commodity contracts:

       

Diesel fuel derivatives

     0.0        Mining related costs         (0.1
  

 

 

      

 

 

 

Total

   $ 0.0         ($ 0.3
  

 

 

      

 

 

 

2013

       

Interest rate contracts

   $ 0.0        Interest expense       ($ 0.4

Commodity contracts:

       

Diesel fuel derivatives

     (0.2     Mining related costs         (0.1
  

 

 

      

 

 

 

Total

   ($ 0.2      ($ 0.5
  

 

 

      

 

 

 

 

(1) Changes in OCI and AOCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and six months ended June 30, 2014 and 2013, all hedges were effective.

 

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The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the six months ended June 30:

 

(millions)

   Fair Value
Asset/
(Liability)
    Amount of
Gain/(Loss)
Recognized
in OCI (1)
    Amount of
Gain/(Loss)
Reclassified From
AOCI Into Income
 

2014

      

Interest rate swaps

   $ 0.0      $ 0.0      ($ 0.2

Diesel fuel derivatives

     0.1        0.0        (0.1
  

 

 

   

 

 

   

 

 

 

Total

   $ 0.1      $ 0.0      ($ 0.3
  

 

 

   

 

 

   

 

 

 

2013

      

Interest rate swaps

   $ 0.0      $ 0.0      ($ 0.4

Diesel fuel derivatives

     (1.1     (0.2     (0.1
  

 

 

   

 

 

   

 

 

 

Total

   ($ 1.1   ($ 0.2   ($ 0.5
  

 

 

   

 

 

   

 

 

 

 

(1) Changes in OCI and AOCI are reported in after-tax dollars.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

 

(millions)

   Diesel Fuel Contracts
(Gallons)
     Natural Gas Contracts
(MMBTUs)
 

Year

   Physical      Financial      Physical      Financial  

2014

     0.0         1.0         0.0         19.4   

2015

     0.0         0.0         0.0         25.0   

2016

     0.0         0.0         0.0         2.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     0.0         1.0         0.0         47.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

The company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements - standardized power sales contracts in the electric industry; (2) ISDA agreements - standardized financial gas and electric contracts; and (3) NAESB agreements - standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments. Substantially all of the company’s open positions with counterparties as of June 30, 2014 were asset positions.

 

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13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

 

Recurring Fair Value Measures

                           
     At fair value as of Jun 30, 2014  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 8.6       $ 0.0       $ 8.6   

Diesel fuel swaps

     0.0         0.1         0.0         0.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 8.7       $ 0.0       $ 8.7   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 0.3       $ 0.0       $ 0.3   

Diesel fuel swaps

     0.0         0.0         0.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.3       $ 0.0       $ 0.3   
  

 

 

    

 

 

    

 

 

    

 

 

 
     At fair value as of Dec 31, 2013  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 9.8       $ 0.0       $ 9.8   

Diesel fuel swaps

     0.0         0.2         0.0         0.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 10.0       $ 0.0       $ 10.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 0.2       $ 0.0       $ 0.2   

Diesel fuel swaps

     0.0         0.1         0.0         0.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.3       $ 0.0       $ 0.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 12).

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

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14. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

15. Discontinued Operations

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

The following table provides selected components of discontinued operations:

 

Components of income from discontinued operations    Three months ended     Six months ended  
     Jun 30,     Jun 30,  

(millions)

   2014      2013     2014      2013  

Revenues

   $ 0.0       $ 0.0      $ 0.0       $ 0.0   
  

 

 

    

 

 

   

 

 

    

 

 

 

(Loss) Income from operations

     0.0         (0.2     5.0         0.2   
  

 

 

    

 

 

   

 

 

    

 

 

 

(Loss) Income from discontinued operations

     0.0         (0.2     5.0         0.2   
  

 

 

    

 

 

   

 

 

    

 

 

 

Less: Provision for income taxes

     0.0         0.0        1.9         0.1   
  

 

 

    

 

 

   

 

 

    

 

 

 

(Loss) Income from discontinued operations, net

     0.0         (0.2     3.1         0.1   
  

 

 

    

 

 

   

 

 

    

 

 

 

16. Asset Impairments

The company accounts for long-lived asset impairments in accordance with the accounting guidance for long-lived assets, which requires that long-lived assets held and used be tested for recoverability whenever events or changes in circumstances indicate that its carrying value may not be recoverable, and assets held for sale be recorded at the lower of its carrying amount or fair value less cost to sell. An asset is considered not recoverable if its carrying value exceeds the sum of its undiscounted expected cash flows. If it is determined that the carrying value is not recoverable and its carrying value exceeds its fair value, an impairment charge is made and the value of the asset is reduced to its fair value.

In 2014, the benchmark price for coal significantly fell from what was used in the long-lived asset impairment testing that was done for TECO Coal in 2013. Additionally, the company is currently in active discussions with potential buyers of TECO Coal; however, no agreement or understanding with respect to any sale has been reached, nor has the company’s board of directors made a determination regarding whether the company would sell TECO Coal based on current indications of value. These indications suggest that a sale price above book value may be unlikely at this time. Although there can be no assurances that a sale of TECO Coal will be completed and TECO Coal is not considered an asset held for sale, the company felt that these factors, coupled together, caused a triggering event requiring impairment testing of TECO Coal in the second quarter of 2014.

The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. A 20-year forecast was developed based on proven and probable reserves, prices using current average coal benchmark prices as a pricing base, and costs using current average costs. A market recovery was assumed for prices and increased costs that moved in line with the prices were factored into the forecast. The book value of TECO Coal’s long-lived assets (including capitalized mine development costs) was determined to be recoverable; therefore, no impairment charge was deemed necessary. Additionally, due to the uncertainty in the soft coal market, the company performed sensitivity analyses on revenues and noted that if revenues declined 15 percent from forecast, all assets would still be recoverable.

 

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Table of Contents

17. Pending Acquisition of New Mexico Gas Company

Pending Acquisition of New Mexico Gas Company

As previously disclosed, TECO Energy must obtain approval for the acquisition from the NMPRC prior to closing the transaction. Hearings before the hearing examiner were concluded on April 3, 2014.

On May 14, 2014, the Joint Applicants announced they had reached a settlement agreement in the case with certain interveners, which was not opposed by NMPRC staff or any other interveners in the proceeding. On June 30, 2014, the hearing examiner issued a certification of the stipulation recommending approval of the stipulation.

A meeting of the NMPRC to consider the hearing examiner’s certification has not been scheduled. It is anticipated that the NMPRC will issue a final order approving the acquisition and certification of stipulation in time for the transaction to close in the third quarter of 2014.

In July 2014, TECO Energy completed a public offering of common stock, the proceeds from which are intended to be used to pay a portion of the acquisition price (see Note 18). With TECO Energy’s consent, NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. The proceeds from the NMGC notes are to be used to repay existing debt at closing and the proceeds from the NMGI notes are to be primarily used to repay existing debt and to fund the transaction, costs and expenses.

18. Subsequent Events

Public Offering of 15.5 million in Common Shares

On July 1, 2014, the company entered into an underwriting agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014.

Pursuant to the terms of the underwriting agreement, the company granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

The company plans to use the net proceeds from this offering to fund, in part, the company’s previously announced acquisition of New Mexico Gas Company and for general corporate purposes.

NMGC and NMGI Note Purchase Agreement

NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. (See Note 17)

 

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Table of Contents

TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC and its subsidiaries as of June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three month and six month periods ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 37 through 48 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page
No.
 

Consolidated Condensed Balance Sheets, June 30, 2014 and Dec. 31, 2013

     32-33   

Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended June 30, 2014 and 2013

     34-35   

Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2014 and 2013

     36   

Notes to Consolidated Condensed Financial Statements

     37-48   

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

Assets    Jun 30,     Dec 31,  

(millions)

   2014     2013  

Property, plant and equipment

    

Utility plant in service

    

Electric

   $ 6,941.7      $ 6,934.0   

Gas

     1,265.6        1,249.5   

Construction work in progress

     493.4        385.3   
  

 

 

   

 

 

 

Utility plant in service, at original costs

     8,700.7        8,568.8   

Accumulated depreciation

     (2,530.9     (2,562.6
  

 

 

   

 

 

 
     6,169.8        6,006.2   

Other property

     8.4        8.3   
  

 

 

   

 

 

 

Total property, plant and equipment, net

     6,178.2        6,014.5   
  

 

 

   

 

 

 

Current assets

    

Cash and cash equivalents

     55.2        9.8   

Receivables, less allowance for uncollectibles of $2.3 and $2.0 at Jun 30, 2014 and Dec. 31, 2013, respectively

     256.7        227.6   

Inventories, at average cost

    

Fuel

     98.7        93.7   

Materials and supplies

     74.4        76.8   

Regulatory assets

     33.7        34.3   

Derivative assets

     8.1        9.5   

Taxes receivable

     0.0        54.9   

Deferred income taxes

     20.4        29.4   

Prepayments and other current assets

     21.2        12.5   
  

 

 

   

 

 

 

Total current assets

     568.4        548.5   
  

 

 

   

 

 

 

Deferred debits

    

Unamortized debt expense

     17.1        14.8   

Regulatory assets

     283.9        293.1   

Derivative assets

     0.5        0.3   

Other

     3.8        4.6   
  

 

 

   

 

 

 

Total deferred debits

     305.3        312.8   
  

 

 

   

 

 

 

Total assets

   $ 7,051.9      $ 6,875.8   
  

 

 

   

 

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets – continued

Unaudited

 

Liabilities and Capitalization    Jun 30,     Dec 31,  

(millions)

   2014     2013  

Capitalization

    

Common stock

   $ 2,047.4      $ 2,030.4   

Accumulated other comprehensive loss

     (7.6     (7.8

Retained earnings

     325.6        308.1   
  

 

 

   

 

 

 

Total capital

     2,365.4        2,330.7   

Long-term debt

     2,013.9        1,797.5   
  

 

 

   

 

 

 

Total capitalization

     4,379.3        4,128.2   
  

 

 

   

 

 

 

Current liabilities

    

Long-term debt due within one year

     83.3        83.3   

Notes payable

     0.0        84.0   

Accounts payable

     198.2        226.0   

Customer deposits

     167.5        164.5   

Regulatory liabilities

     65.7        85.8   

Derivative liabilities

     0.2        0.0   

Interest accrued

     18.6        16.4   

Taxes accrued

     57.8        12.2   

Other

     12.1        12.0   
  

 

 

   

 

 

 

Total current liabilities

     603.4        684.2   
  

 

 

   

 

 

 

Deferred credits

    

Deferred income taxes

     1,145.1        1,114.3   

Investment tax credits

     9.2        9.4   

Derivative liabilities

     0.1        0.2   

Regulatory liabilities

     621.4        631.4   

Other

     293.4        308.1   
  

 

 

   

 

 

 

Total deferred credits

     2,069.2        2,063.4   
  

 

 

   

 

 

 

Commitments and Contingencies (see Note 8)

    

Total liabilities and capitalization

   $ 7,051.9      $ 6,875.8   
  

 

 

   

 

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

     Three months ended Jun 30,  

(millions)

   2014     2013  

Revenues

    

Electric (includes franchise fees and gross receipts taxes of $22.7 in 2014 and $21.5 in 2013)

   $ 512.7      $ 502.8   

Gas (includes franchise fees and gross receipts taxes of $5.1 in 2014 and $5.2 in 2013)

     90.6        101.3   
  

 

 

   

 

 

 

Total revenues

     603.3        604.1   
  

 

 

   

 

 

 

Expenses

    

Regulated operations and maintenance

    

Fuel

     169.7        174.5   

Purchased power

     19.9        20.5   

Cost of natural gas sold

     29.0        40.9   

Other

     126.8        129.5   

Depreciation and amortization

     75.1        74.0   

Taxes, other than income

     47.6        45.8   
  

 

 

   

 

 

 

Total expenses

     468.1        485.2   
  

 

 

   

 

 

 

Income from operations

     135.2        118.9   
  

 

 

   

 

 

 

Other income

    

Allowance for other funds used during construction

     2.0        1.4   

Other income, net

     1.1        1.3   
  

 

 

   

 

 

 

Total other income

     3.1        2.7   
  

 

 

   

 

 

 

Interest charges

    

Interest on long-term debt

     26.4        26.4   

Other interest

     1.0        1.0   

Allowance for borrowed funds used during construction

     (0.7     (0.8
  

 

 

   

 

 

 

Total interest charges

     26.7        26.6   
  

 

 

   

 

 

 

Income before provision for income taxes

     111.6        95.0   

Provision for income taxes

     41.9        36.5   
  

 

 

   

 

 

 

Net income

     69.7        58.5   
  

 

 

   

 

 

 

Other comprehensive income, net of tax

    

Amortization of settled interest rate swaps

     0.0        0.2   
  

 

 

   

 

 

 

Total other comprehensive income, net of tax

     0.0        0.2   
  

 

 

   

 

 

 

Comprehensive income

   $ 69.7      $ 58.7   
  

 

 

   

 

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

     Six months ended Jun 30,  

(millions)

   2014     2013  

Revenues

    

Electric (includes franchise fees and gross receipts taxes of $43.0 in 2014 and $40.5 in 2013)

   $ 965.7      $ 920.7   

Gas (includes franchise fees and gross receipts taxes of $12.0 in 2014 and $11.6 in 2013)

     213.1        223.2   
  

 

 

   

 

 

 

Total revenues

     1,178.8        1,143.9   
  

 

 

   

 

 

 

Expenses

    

Regulated operations and maintenance

    

Fuel

     319.3        314.5   

Purchased power

     38.1        35.1   

Cost of natural gas sold

     76.2        90.4   

Other

     247.1        250.1   

Depreciation and amortization

     150.5        146.0   

Taxes, other than income

     95.0        90.3   
  

 

 

   

 

 

 

Total expenses

     926.2        926.4   
  

 

 

   

 

 

 

Income from operations

     252.6        217.5   
  

 

 

   

 

 

 

Other income

    

Allowance for other funds used during construction

     4.4        2.5   

Other income, net

     2.3        2.5   
  

 

 

   

 

 

 

Total other income

     6.7        5.0   
  

 

 

   

 

 

 

Interest charges

    

Interest on long-term debt

     52.1        52.9   

Other interest

     2.1        1.9   

Allowance for borrowed funds used during construction

     (2.1     (1.4
  

 

 

   

 

 

 

Total interest charges

     52.1        53.4   
  

 

 

   

 

 

 

Income before provision for income taxes

     207.2        169.1   

Provision for income taxes

     77.7        65.0   
  

 

 

   

 

 

 

Net income

     129.5        104.1   
  

 

 

   

 

 

 

Other comprehensive income, net of tax

    

Amortization of settled interest rate swaps

     0.2        0.4   
  

 

 

   

 

 

 

Total other comprehensive income, net of tax

     0.2        0.4   
  

 

 

   

 

 

 

Comprehensive income

   $ 129.7      $ 104.5   
  

 

 

   

 

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Six months ended Jun 30,  

(millions)

   2014     2013  

Cash flows from operating activities

    

Net income

   $ 129.5      $ 104.1   

Adjustments to reconcile net income to net cash from operating activities:

    

Depreciation and amortization

     150.5        146.0   

Deferred income taxes

     35.0        42.6   

Investment tax credits

     (0.2     (0.2

Allowance for funds used during construction

     (4.4     (2.5

Deferred recovery clauses

     (14.4     (5.9

Receivables, less allowance for uncollectibles

     (29.1     (43.0

Inventories

     (2.6     (18.9

Prepayments

     (2.8     (5.6

Taxes accrued

     100.5        63.5   

Interest accrued

     2.2        1.6   

Accounts payable

     (34.3     13.9   

Other

     (10.6     (0.2
  

 

 

   

 

 

 

Cash flows from operating activities

     319.3        295.4   
  

 

 

   

 

 

 

Cash flows from investing activities

    

Capital expenditures

     (312.7     (239.9

Allowance for funds used during construction

     4.4        2.5   

Net proceeds from sale of assets

     0.1        0.0   
  

 

 

   

 

 

 

Cash flows used in investing activities

     (308.2     (237.4
  

 

 

   

 

 

 

Cash flows from financing activities

    

Common stock

     17.0        20.0   

Proceeds from long-term debt issuance

     296.6        0.0   

Repayment of long-term debt/Purchase in lieu of redemption

     (83.3     0.0   

Net decrease in short-term debt

     (84.0     0.0   

Dividends

     (112.0     (94.1
  

 

 

   

 

 

 

Cash flows provided by (used in) financing activities

     34.3        (74.1
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     45.4        (16.1

Cash and cash equivalents at beginning of period

     9.8        45.2   
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 55.2      $ 29.1   
  

 

 

   

 

 

 

Supplemental disclosure of non-cash activities

    

Capital expenditures not yet paid

   $ 8.6      $ (3.1

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

 

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements, however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

Cash Flows Related to Derivatives and Hedging Activities

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a

 

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component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for TEC beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for TEC beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC under PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations 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 sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC.

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year.

 

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Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

 

Regulatory Assets and Liabilities

             

(millions)

   Jun 30, 2014      Dec 31, 2013  

Regulatory assets:

     

Regulatory tax asset (1)

   $ 68.1       $ 67.4   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     1.8         6.1   

Postretirement benefit asset

     177.6         182.7   

Deferred bond refinancing costs (2)

     7.6         8.0   

Environmental remediation

     52.0         51.4   

Competitive rate adjustment

     2.8         4.1   

Other

     7.7         7.7   
  

 

 

    

 

 

 

Total other regulatory assets

     249.5         260.0   
  

 

 

    

 

 

 

Total regulatory assets

     317.6         327.4   

Less: Current portion

     33.7         34.3   
  

 

 

    

 

 

 

Long-term regulatory assets

   $ 283.9       $ 293.1   
  

 

 

    

 

 

 

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 5.6       $ 9.8   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     34.8         54.5   

Transmission and delivery storm reserve

     56.1         56.1   

Deferred gain on property sales (3)

     1.4         2.0   

Provision for stipulation and other

     0.8         0.8   

Accumulated reserve - cost of removal

     588.4         594.0   
  

 

 

    

 

 

 

Total other regulatory liabilities

     681.5         707.4   
  

 

 

    

 

 

 

Total regulatory liabilities

     687.1         717.2   

Less: Current portion

     65.7         85.8   
  

 

 

    

 

 

 

Long-term regulatory liabilities

   $ 621.4       $ 631.4   
  

 

 

    

 

 

 

 

(1) Primarily related to plant life and derivative positions.
(2) Amortized over the term of the related debt instruments.
(3) Amortized over a 5-year period with various ending dates.

All regulatory assets are recovered through the regulatory process. The following table further details the regulatory assets and the related recovery periods:

 

Regulatory Assets

   Jun 30,      Dec 31,  

(millions)

   2014      2013  

Clause recoverable (1)

     $4.6         $10.2   

Components of rate base (2)

     180.7         185.6   

Regulatory tax assets (3)

     68.1         67.4   

Capital structure and other (3)

     64.2         64.2   
  

 

 

    

 

 

 

Total

   $ 317.6       $ 327.4   
  

 

 

    

 

 

 

 

(1) To be recovered through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC.
(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

 

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4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the six months ended June 30, 2014 and 2013 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2010 and forward.

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended June 30, 2014 and 2013, respectively, was $3.9 million and $5.6 million for pension benefits, and $2.6 million and $2.4 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2014 and 2013, respectively, was $7.7 million and $10.9 million for pension benefits, and $5.2 million and $5.0 million for other postretirement benefits.

For the 2014 plan year, TECO Energy assumed a long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan in the six months ended June 30, 2014. TEC’s portion of the contributions was $21.5 million.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

 

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6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

 

Credit Facilities

                           
     Jun 30, 2014      Dec. 31, 2013  
                   Letters                    Letters  
     Credit      Borrowings      of Credit      Credit      Borrowings      of Credit  

(millions)

   Facilities      Outstanding (1)      Outstanding      Facilities      Outstanding (1)      Outstanding  

Tampa Electric Company:

                 

5-year facility (2)

   $ 325.0       $ 0.0       $ 0.7       $ 325.0       $ 6.0       $ 0.7   

1-year accounts receivable facility

     150.0         0.0         0.0         150.0         78.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 475.0       $ 0.0       $ 0.7       $ 475.0       $ 84.0       $ 0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Dec. 17, 2018.

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, TEC’s total long-term debt had a carrying amount of $2,097.2 million and an estimated fair market value of $2,329.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

 

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8. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

TEC believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. 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 estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2014 is as follows:

 

Letters of Credit - Tampa Electric Company

                                  

(millions)

Letters of Credit for the Benefit of:

   2014      2015-2018      After(1)
2018
     Total      Liabilities Recognized
at Jun 30, 2014
 

Tampa Electric Company (2)

   $ 0.0       $ 0.0       $ 0.7       $ 0.7       $ 0.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at June 30, 2014. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TEC was in compliance with all applicable financial covenants.

 

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9. Segment Information

 

(millions)

Three months ended Jun 30,

   Tampa
Electric
     Peoples
Gas
     Other &
Eliminations
    Tampa Electric
Company
 

2014

          

Revenues - external

   $ 512.6       $ 90.7       $ 0.0      $ 603.3   

Sales to affiliates

     0.1         0.4         (0.5     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     512.7         91.1         (0.5     603.3   

Depreciation and amortization

     61.7         13.4         0.0        75.1   

Total interest charges

     23.3         3.4         0.0        26.7   

Provision for income taxes

     37.1         4.8         0.0        41.9   

Net income

   $ 62.2       $ 7.5       $ 0.0      $ 69.7   
  

 

 

    

 

 

    

 

 

   

 

 

 

2013

          

Revenues - external

   $ 502.8       $ 101.3       $ 0.0      $ 604.1   

Sales to affiliates

     0.1         0.5         (0.6     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     502.9         101.8         (0.6     604.1   

Depreciation and amortization

     60.8         13.2         0.0        74.0   

Total interest charges

     23.3         3.3         0.0        26.6   

Provision for income taxes

     31.5         5.0         0.0        36.5   

Net income

   $ 50.6       $ 7.9       $ 0.0      $ 58.5   
  

 

 

    

 

 

    

 

 

   

 

 

 

Six months ended Jun 30,

                          

2014

          

Revenues - external

   $ 965.7       $ 213.1       $ 0.0      $ 1,178.8   

Sales to affiliates

     0.2         0.6         (0.8     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     965.9         213.7         (0.8     1,178.8   

Depreciation and amortization

     123.8         26.7         0.0        150.5   

Total interest charges

     45.3         6.8         0.0        52.1   

Provision for income taxes

     63.7         14.0         0.0        77.7   

Net income

   $ 107.4       $ 22.1       $ 0.0      $ 129.5   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets at Jun 30, 2014

   $ 6,061.9       $ 1,002.4       ($ 12.4   $ 7,051.9   
  

 

 

    

 

 

    

 

 

   

 

 

 

2013

          

Revenues - external

   $ 920.7       $ 223.2       $ 0.0      $ 1,143.9   

Sales to affiliates

     0.2         0.5         (0.7     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     920.9         223.7         (0.7     1,143.9   

Depreciation and amortization

     119.8         26.2         0.0        146.0   

Total interest charges

     46.7         6.7         0.0        53.4   

Provision for income taxes

     51.3         13.7         0.0        65.0   

Net income

   $ 82.4       $ 21.7       $ 0.0      $ 104.1   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets at Dec 31, 2013

   $ 5,895.4       $ 989.3       ($ 8.9   $ 6,875.8   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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10. Accounting for Derivative Instruments and Hedging Activities

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

 

    to limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

 

    to limit the exposure to interest rate fluctuations on debt securities.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

TEC applies the accounting standards for derivatives and hedging. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

TEC applies accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for the regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

 

Natural Gas Derivatives

             

(millions)

   Jun 30,
2014
     Dec 31,
2013
 

Current assets

   $ 8.1       $ 9.5   

Long-term assets

     0.5         0.3   
  

 

 

    

 

 

 

Total assets

   $ 8.6       $ 9.8   
  

 

 

    

 

 

 

Current liabilities (1)

   $ 0.2       $ 0.0   

Long-term liabilities

     0.1         0.2   
  

 

 

    

 

 

 

Total liabilities

   $ 0.3       $ 0.2   
  

 

 

    

 

 

 

 

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The ending balance in AOCI related to previously settled interest rate swaps at June 30, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

 

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The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

 

Offsetting of Derivative Assets and Liabilities

                  

(millions)

   Gross Amounts
of Recognized
Assets
(Liabilities)
    Gross Amounts
offset on the
Balance Sheet
    Net Amounts of
Assets (Liabilities)
Presented on the
Balance Sheet
 

Jun 30, 2014

                  

Description

      

Derivative assets

   $ 9.8      $ (1.2   $ 8.6   

Derivative liabilities

   $ (1.5   $ 1.2      $ (0.3

Dec 31, 2013

                  

Description

      

Derivative assets

   $ 10.3      $ (0.5   $ 9.8   

Derivative liabilities

   $ (0.7   $ 0.5      $ (0.2

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

 

Energy Related Derivatives

 
    

Asset Derivatives

    

Liability Derivatives

 

(millions)

Jun 30, 2014

  

Balance Sheet
Location (1)

   Fair
Value
    

Balance Sheet
Location (1)

   Fair
Value
 

Commodity Contracts:

           

Natural gas derivatives:

           

Current

   Regulatory liabilities    $ 8.1       Regulatory assets    $ 0.2   

Long-term

   Regulatory liabilities      0.5       Regulatory assets      0.1   
     

 

 

       

 

 

 

Total

      $ 8.6          $ 0.3   
     

 

 

       

 

 

 

(millions)

Dec 31, 2013

  

Balance Sheet
Location (1)

   Fair
Value
    

Balance Sheet
Location (1)

   Fair
Value
 

Commodity Contracts:

           

Natural gas derivatives:

           

Current

   Regulatory liabilities    $ 9.5       Regulatory assets    $ 0.0   

Long-term

   Regulatory liabilities      0.3       Regulatory assets      0.2   
     

 

 

       

 

 

 

Total

      $ 9.8          $ 0.2   
     

 

 

       

 

 

 

 

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

 

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The following table presents the effect of hedging instruments on OCI and income for the three months and six months ended June 30:

 

(millions)

   Location of Gain/(Loss)
Reclassified From AOCI Into
Income
   Amount of Gain/(Loss) Reclassified
From AOCI Into Income
 

Derivatives in Cash Flow
Hedging Relationships

   Effective Portion (1)    Three months
ended Jun 30:
    Six months ended
Jun 30:
 

2014

       

Interest rate contracts:

   Interest expense    $ 0.0      $ 0.2   
     

 

 

   

 

 

 

Total

      $ 0.0      $ 0.2   
     

 

 

   

 

 

 

2013

       

Interest rate contracts:

   Interest expense    ($ 0.2   ($ 0.4
     

 

 

   

 

 

 

Total

      ($ 0.2   ($ 0.4
     

 

 

   

 

 

 

 

(1) Changes in OCI and AOCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three and six months ended June 30, 2014 and 2013, all hedges were effective.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

 

(millions)

   Natural Gas Contracts
(MMBTUs)
 

Year

   Physical      Financial  

2014

     0.0         19.4   

2015

     0.0         25.0   

2016

     0.0         2.8   
  

 

 

    

 

 

 

Total

     0.0         47.2   
  

 

 

    

 

 

 

TEC is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements- standardized power sales contracts in the electric industry; (2) ISDA agreements- standardized financial gas and electric contracts; and (3) NAESB agreements - standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments. Substantially all of TEC’s open positions with counterparties as of June 30, 2014 were asset positions.

 

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11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

 

Recurring Derivative Fair Value Measures

 
     At fair value as of Jun 30, 2014  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 8.6       $ 0.0       $ 8.6   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 8.6       $ 0.0       $ 8.6   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 0.3       $ 0.0       $ 0.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.3       $ 0.0       $ 0.3   
  

 

 

    

 

 

    

 

 

    

 

 

 
     At fair value as of Dec 31, 2013  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 9.8       $ 0.0       $ 9.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 9.8       $ 0.0       $ 9.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 0.2       $ 0.0       $ 0.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.2       $ 0.0       $ 0.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

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12. Other Comprehensive Income

 

Other Comprehensive Income    Three months ended June 30,      Six months ended June 30,  

(millions)

   Gross      Tax     Net      Gross      Tax     Net  

2014

               

Unrealized loss on cash flow hedges

   $ 0.0       $ 0.0      $ 0.0       $ 0.0       $ 0.0      $ 0.0   

Reclassification from AOCI to net income

     0.0         0.0        0.0         0.4         (0.2     0.2   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Gain on cash flow hedges

     0.0         0.0        0.0         0.4         (0.2     0.2   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total other comprehensive income

   $ 0.0       $ 0.0      $ 0.0       $ 0.4       ($ 0.2   $ 0.2   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

2013

               

Unrealized loss on cash flow hedges

   $ 0.0       $ 0.0      $ 0.0       $ 0.0       $ 0.0      $ 0.0   

Reclassification from AOCI to net income

     0.4         (0.2     0.2         0.7         (0.3     0.4   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Gain on cash flow hedges

     0.4         (0.2     0.2         0.7         (0.3     0.4   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total other comprehensive income

   $ 0.4       ($ 0.2   $ 0.2       $ 0.7       ($ 0.3   $ 0.4   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

 

Accumulated Other Comprehensive Loss

            

(millions)

   Jun 30, 2014     Dec 31, 2013  

Net unrealized losses from cash flow hedges (1)

   ($ 7.6   ($ 7.8
  

 

 

   

 

 

 

Total accumulated other comprehensive loss

   ($ 7.6   ($ 7.8
  

 

 

   

 

 

 

 

(1) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

13. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively, and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

 

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Item 2. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis of Financial Conditions 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. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities, including the required approval by the New Mexico Public Regulation Commission for the acquisition of NMGC; the risk that the transaction to acquire NMGC may be delayed, may be consummated on less favorable terms than originally expected, or not be consummated at all; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the ability to sell TECO Coal at an acceptable price; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and demand for TECO Coal’s production; costs for alternate fuels used for power generation affecting demand for TECO Coal’s thermal coal production; operating costs and environmental or safety regulations affecting production levels and margins at TECO Coal; weak demand and market pricing conditions affecting the value of TECO Coal’s facilities and coal reserves; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under Item IA “Risk Factors” in this Quarterly Report on Form 10-Q for the period ended June 30, 2014.

 

Earnings Summary - Unaudited

                          
     Three months ended June 30,     Six months ended June 30,  

(millions, except per share amounts)

   2014      2013     2014      2013  

Consolidated revenues

   $ 726.3       $ 735.9      $ 1,410.4       $ 1,397.0   
  

 

 

    

 

 

   

 

 

    

 

 

 

Continuing operations

   $ 58.4       $ 51.6      $ 105.4       $ 92.8   
  

 

 

    

 

 

   

 

 

    

 

 

 

Discontinued operations

     —           (0.2     3.1         0.1   
  

 

 

    

 

 

   

 

 

    

 

 

 

Net income

   $ 58.4       $ 51.4      $ 108.5       $ 92.9   
  

 

 

    

 

 

   

 

 

    

 

 

 

Average common shares outstanding

          

Basic

     215.4         215.0        215.3         214.8   
  

 

 

    

 

 

   

 

 

    

 

 

 

Diluted

     215.9         215.5        215.8         215.3   
  

 

 

    

 

 

   

 

 

    

 

 

 

Earnings per share - Basic

          

Continuing operations

   $ 0.27       $ 0.24      $ 0.49       $ 0.43   

Discontinued operations

     —           —          0.01         —     
  

 

 

    

 

 

   

 

 

    

 

 

 

Earnings per share - Basic

   $ 0.27       $ 0.24      $ 0.50       $ 0.43   
  

 

 

    

 

 

   

 

 

    

 

 

 

Earnings per share - Diluted

          

Continuing operations

   $ 0.27       $ 0.24      $ 0.49       $ 0.43   

Discontinued operations

     —           —          0.01         —     
  

 

 

    

 

 

   

 

 

    

 

 

 

Earnings per share - Diluted

   $ 0.27       $ 0.24      $ 0.50       $ 0.43   
  

 

 

    

 

 

   

 

 

    

 

 

 

TECO Energy Strategy

TECO Energy’s strategy is to transition into a growth plus sustainable yield company focused on its existing core businesses—electric and gas utilities—and to execute on accretive acquisitions of regulated utilities to grow its base. TECO Energy seeks to optimize its businesses by application of best practices in both gas and electric operations.

Our strategy, which is based on a long and successful history of owning and operating regulated electric and gas utilities, consistently delivering value to our shareholders over the long term, is to:

Invest in and grow our utilities, both in Florida and, upon consummation of the NMGC acquisition, in New Mexico with intentions to acquire additional utilities in areas of the country with favorable regulatory environments and above-average growth prospects;

Focus our gas utilities on CNG vehicle conversions and customer user-conversions from other forms of energy to natural gas;

Invest in proven and emerging technologies, such as smart grid applications, that benefit customers and shareholders;

Collaborate with customers to develop alternative solutions to meet their energy needs; and Utilize our expertise in intrastate pipelines and lateral development to support the growth of natural gas in Florida and in New Mexico.

 

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An important part of our strategy is that we expect our utilities to earn returns that are at or above the middle of their respective allowed ROE while maintaining their authorized capital structures and financial integrity. Tampa Electric’s 2013 Florida rate case settlement, which included $70 million of base rate increases through 2015, plus an additional $110 million base rate increase in January 2017, or when the Polk Power Station units two through five conversion project enters service, provides regulatory certainty through 2017.

Florida, with its favorable growth characteristics, combined with its supportive regulatory environment, is one of the most attractive states to operate regulated utilities. We see similar growth characteristics in New Mexico, an attractive sunbelt state with a growing population. We expect opportunities to invest capital to support the growth and reliability opportunities at PGS and NMGC, the largest LDCs Florida and New Mexico, respectively. Additionally, we have opportunities to invest significant capital in Tampa Electric over the next several years for the Polk Power Station units two through five conversion, which we believe will allow us to continue providing safe, affordable and reliable service to customers and support our growth.

TECO Coal Update

As we have previously indicated, we do not consider TECO Coal to be a core holding. Consistent with this view, we have had discussions from time to time with interested parties regarding a possible sale of TECO Coal, and have been working with an investment banking firm to help us determine whether there would be interest in a sale transaction that we would find acceptable. We are in active discussions with potential buyers, but no agreement or understanding with respect to any sale has been reached. Furthermore, our board of directors has not made a determination regarding whether we would sell TECO Coal based on current indications of value. These indications suggest that a sale price above book value may be unlikely in the current market conditions. In the context of furthering our overall strategy, that is a factor which we would consider, among others, in deciding whether to sell TECO Coal. Accordingly, there can be no assurances that a sale of TECO Coal will be completed, and if a sale is completed, the price received is expected to reflect current market conditions.

Update on Regulatory Status of NMGC Acquisition

In May 2013, TECO Energy announced that it had signed an agreement to acquire NMGI, the parent company of New Mexico Gas Company from CES. This acquisition is subject to approval by the NMPRC. In July 2013, we filed a joint application with NMGC and CES with the NMPRC for approval of the acquisition. On May 14, 2014, we reached a settlement agreement with the New Mexico Industrial Energy Consumers, which represents large customers of NMGC, and the New Mexico Attorney General’s office, which represents New Mexico residential and small business customers, with regards to the NMGC acquisition. Under the terms of the settlement, among other elements, NMGC will freeze customer rates until the end of 2017 and limit job reductions in the first three years after the NMGC acquisition. The NMPRC staff did not oppose the settlement, and on June 30, 2014, the NMPRC hearing examiner issued a certification of stipulation recommending that the NMPRC approve the transaction and related matters. The NMPRC still must decide whether the settlement is in the public interest and whether to approve the NMGC acquisition, which decision we expect in the third quarter of 2014. Under this schedule, however, closing of the NMGC acquisition will not occur within one year of our Hart-Scott-Rodino Premerger Notification and Report Form with the U.S. Department of Justice (HSR Form). Accordingly, on June 20, 2014, we filed a new HSR Form and the closing of the transaction will be subject to renewed clearance from anti-trust regulators and expiration of the new waiting period under the filing. As previously announced, we already reached a settlement agreement with the U.S. Department of Energy regarding the NMGC acquisition.

In July, we completed the permanent financing required to fund the closing of the NMGC acquisition.

Operating Results

Three Months Ended June 30, 2014

TECO Energy, Inc. reported second-quarter 2014 net income of $58.4 million, or $0.27 per share, compared with $51.4 million, or $0.24 per share, in the second quarter of 2013. Net income from continuing operations was also $58.4 million in the 2014 second quarter, compared with $51.6 million, or $0.24 per share, for the same period in 2013.

Six Months Ended June 30, 2014

Year-to-date net income was $108.5 million, or $0.50 per share, compared with net income of $92.9 million, or $0.43 per share in the 2013 period. Net income from continuing operations was $105.4 million or $0.49 per share, compared with $92.8 million or $0.43 per share in the 2013 period.

The 2014 benefit of $3.1 million reported in discontinued operations was related to the favorable resolution of an indemnification provision associated with the 2012 sale of TECO Guatemala.

 

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Operating Company Results

All amounts included in the operating company discussions below are after tax, unless otherwise noted.

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the second quarter of 2014 was $62.2 million, compared with $50.6 million for the same period in 2013. Results for the quarter reflected the benefits of the rate case settlement effective Nov. 1, 2013, a 1.7% higher average number of customers, higher energy sales primarily due to customer growth, and $0.8 million lower earnings on assets recovered through the Environmental Cost Recovery Clause (ECRC) due to a lower current weighted average cost of capital, which includes the lower return on equity (ROE) in the 2013 rate case settlement. Results reflected lower operations and maintenance expenses, partially offset by higher depreciation expense. Second-quarter net income in 2014 included $2.1 million of Allowance for Funds Used During Construction (AFUDC) equity, which represents allowed equity cost capitalized to construction costs, compared with $1.4 million in the 2013 quarter.

Total degree days in Tampa Electric’s service area in the second quarter of 2014 were 4% below normal, and 6% below the 2013 period. Although the total degree day comparisons indicate milder than normal weather, the pattern of periods of warm and dry weather, especially later in the quarter, contributed to higher energy sales. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 0.8% in the second quarter of 2014 compared with the same period in 2013. In the 2014 period, pretax base revenues were almost $17 million higher than in 2013, including approximately $15 million of higher revenue as a result of the 2013 rate case settlement. (The quarterly energy sales shown on the statistical summary that follows reflect the energy sales based on the timing of billing cycles, which can vary period to period.) Sales to residential customers increased primarily from customer growth. Sales to commercial and non-phosphate industrial customers increased due to the improving economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost-recovery clauses, was $1.6 million lower than in the 2013 quarter, reflecting $1.7 million of higher cost to operate and maintain the generating system and higher employee-related costs more than offset by a $1.2 million benefit from the elimination of the storm damage accrual as a result of the 2013 rate case settlement, almost $1.0 million lower pension expense and lower self-insurance reserves. Deprec