XNYS:TE TECO Energy Inc Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

XNYS:TE (TECO Energy Inc): Fair Value Estimate
Premium
XNYS:TE (TECO Energy Inc): Consider Buying
Premium
XNYS:TE (TECO Energy Inc): Consider Selling
Premium
XNYS:TE (TECO Energy Inc): Fair Value Uncertainty
Premium
XNYS:TE (TECO Energy Inc): Economic Moat
Premium
XNYS:TE (TECO Energy Inc): Stewardship
Premium
 
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 March 31, 2012

OR

 

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

For the transition period from            to            

 

 

 

Commission

File No.

 

Exact name of each registrant as specified

in its charter, state of incorporation, address of

principal executive offices, telephone number

 

I.R.S. Employer

Identification

Number

1-8180   TECO ENERGY, INC.   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 April 27, 2012 was $215,679,828. As of April 27, 2012, 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 1 of 47

Index to Exhibits appears on page 47.


Table of Contents

DEFINITIONS

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

 

Term

  

Meaning

ABS    asset-backed security
ADR    American depository receipt
AFUDC    allowance for funds used during construction
AFUDC - debt    debt component of allowance for funds used during construction
AFUDC - equity    equity component of allowance for funds used during construction
AOCI    accumulated other comprehensive income
APBO    accumulated postretirement benefit obligation
ARO    asset retirement obligation
capacity clause    capacity cost-recovery clause, as established by the FPSC
CGESJ    Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMO    collateralized mortgage obligation
CO2    carbon dioxide
CT    combustion turbine
DECA II    Distribución Eléctrica Centro Americana, II, S.A.
DOE    U.S. Department of Energy
EEGSA    Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America
EEI    Edison Electric Institute
EPA    U.S. Environmental Protection Agency
EPS    earnings per share
ERISA    Employee Retirement Income Security Act
EROA    expected return on plan assets
FASB    Financial Accounting Standards Board
FDEP    Florida Department of Environmental Protection
FERC    Federal Energy Regulatory Commission
FGT    Florida Gas Transmission Company
FPSC    Florida Public Service Commission
fuel clause    fuel and purchased power cost-recovery clause, as established by the FPSC
GAAP    generally accepted accounting principles
GHG    greenhouse gas(es)
HCIDA    Hillsborough County Industrial Development Authority
HPP    Hardee Power Partners
IFRS    International Financial Reporting Standards
IGCC    integrated gasification combined-cycle
IOU    investor owned utility
IRS    Internal Revenue Service
ISDA    International Swaps and Derivatives Association
ISO    independent system operator
ITCs    investment tax credits
KW    kilowatt
KWH    kilowatt-hour(s)
LIBOR    London Interbank Offered Rate
MARN    Ministry of Environment, Guatemala
MBS    mortgage-backed securities
MD&A    Management’s Discussion and Analysis
MMA    The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MM&A    Marshall Miller & Associates
MMBTU    one million British Thermal Units
MRV    market-related value

 

2


Table of Contents
MSHA    Mine Safety and Health Administration
MW    megawatt(s)
MWH    megawatt-hour(s)
NAESB    North American Energy Standards Board
NAV    net asset value
NERC    North American Electric Reliability Corporation
NOL    net operating loss
Note         Note    to consolidated financial statements
NOx    nitrogen oxide
NPNS    normal purchase normal sale
NYMEX    New York Mercantile Exchange
o&m expenses    operations and maintenance expenses
OATT    open access transmission tariff
OCI    other comprehensive income
OTC    over-the-counter
OTTI    other than temporary impairment
PBGC    Pension Benefit Guarantee Corporation
PBO    postretirement benefit obligation
PCI    pulverized coal injection
PCIDA    Polk County Industrial Development Authority
PGA    purchased gas adjustment
PGS    Peoples Gas System, the gas division of Tampa Electric Company
PPA    power purchase agreement
PPSA    Power Plant Siting Act
PRP    potentially responsible party
PUHCA 2005    Public Utility Holding Company Act of 2005
REIT    real estate investment trust
REMIC    real estate mortgage investment conduit
RFP    request for proposal
ROE    return on common equity
Regulatory ROE    return on common equity as determined for regulatory purposes
RPS    renewable portfolio standards
RTO    regional transmission organization
SEC    U.S. Securities and Exchange Commission
SO2    sulfur dioxide
SERP    Supplemental Executive Retirement Plan
SPA    stock purchase agreement
STIF    short-term investment fund
TCAE    Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
Tampa Electric    Tampa Electric, the electric division of Tampa Electric Company
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, a coal producing subsidiary of TECO Diversified
TECO Finance    TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.
TEMSA    Tecnología Marítima, S.A., a provider of dry bulk and coal unloading services located in Guatemala
TRC    TEC Receivables Company
VIE    variable interest entity
WRERA    The Worker, Retiree and Employer Recovery Act of 2008

 

3


Table of Contents

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 March 31, 2012 and Dec. 31, 2011, and the results of their operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. 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, 2011 and to the notes on pages 10 through 23 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page
No.
 

Consolidated Condensed Balance Sheets, March 31, 2012 and Dec. 31, 2011

     5-6   

Consolidated Condensed Statements of Income for the three month periods ended March 31, 2012 and 2011

     7   

Consolidated Condensed Statements of Comprehensive Income for the three month periods ended March  31, 2012 and 2011

     8   

Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2012 and 2011

     9   

Notes to Consolidated Condensed Financial Statements

     10-23   

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.

 

4


Table of Contents

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

Assets

(millions)

   Mar. 31,
2012
    Dec. 31,
2011
 

Current assets

    

Cash and cash equivalents

   $ 59.0      $ 44.0   

Restricted cash

     8.7        8.7   

Receivables, less allowance for uncollectibles of $2.6 at Mar. 31, 2012 and Dec. 31, 2011

     278.4        327.7   

Inventories, at average cost

    

Fuel

     146.6        136.8   

Materials and supplies

     87.0        87.3   

Derivative assets

     2.1        0.9   

Regulatory assets

     107.0        87.3   

Deferred income taxes

     33.2        72.7   

Prepayments and other current assets

     29.7        31.9   

Income tax receivables

     0.1        0.6   
  

 

 

   

 

 

 

Total current assets

     751.8        797.9   
  

 

 

   

 

 

 

Property, plant and equipment

    

Utility plant in service

    

Electric

     6,767.0        6,731.7   

Gas

     1,184.7        1,169.9   

Construction work in progress

     274.0        247.4   

Other property

     435.3        432.3   
  

 

 

   

 

 

 

Property, plant and equipment, at original costs

     8,661.0        8,581.3   

Accumulated depreciation

     (2,675.4     (2,613.5
  

 

 

   

 

 

 

Total property, plant and equipment, net

     5,985.6        5,967.8   
  

 

 

   

 

 

 

Other assets

    

Regulatory assets

     359.2        364.5   

Goodwill

     55.4        55.4   

Deferred charges and other assets

     134.8        136.6   
  

 

 

   

 

 

 

Total other assets

     549.4        556.5   
  

 

 

   

 

 

 

Total assets

   $ 7,286.8      $ 7,322.2   
  

 

 

   

 

 

 

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

 

5


Table of Contents

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

 

Liabilities and Capital

(millions)

   Mar. 31,
2012
    Dec. 31,
2011
 

Current liabilities

    

Long-term debt due within one year

    

Recourse

   $ 374.8      $ 374.9   

Non-recourse

     11.2        11.2   

Notes payable

     44.0        0.0   

Accounts payable

     244.5        252.3   

Customer deposits

     160.9        159.5   

Regulatory liabilities

     72.3        86.2   

Derivative liabilities

     70.0        58.4   

Interest accrued

     59.9        39.3   

Taxes accrued

     34.1        20.7   

Other current liabilities

     17.2        17.2   
  

 

 

   

 

 

 

Total current liabilities

     1,088.9        1,019.7   
  

 

 

   

 

 

 

Other liabilities

    

Deferred income taxes

     137.3        150.8   

Investment tax credits

     10.0        10.0   

Regulatory liabilities

     644.8        647.8   

Derivative liabilities

     6.6        8.6   

Deferred credits and other liabilities

     525.8        530.8   

Long-term debt, less amount due within one year

    

Recourse

     2,579.1        2,665.0   

Non-recourse

     19.6        22.3   
  

 

 

   

 

 

 

Total other liabilities

     3,923.2        4,035.3   
  

 

 

   

 

 

 

Commitments and contingencies (see Note 10)

    

Capital

    

Common equity (400.0 million shares authorized; par value $1; 215.8 million shares outstanding at Mar. 31, 2012 and Dec. 31, 2011)

     215.8        215.8   

Additional paid in capital

     1,556.2        1,553.4   

Retained earnings

     522.5        519.4   

Accumulated other comprehensive loss

     (20.4     (22.0
  

 

 

   

 

 

 

TECO Energy stockholders’ equity

     2,274.1        2,266.6   

Noncontrolling interest

     0.6        0.6   
  

 

 

   

 

 

 

Total capital

     2,274.7        2,267.2   
  

 

 

   

 

 

 

Total liabilities and capital

   $ 7,286.8      $ 7,322.2   
  

 

 

   

 

 

 

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

 

6


Table of Contents

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

     Three months ended Mar. 31,  

(millions, except per share amounts)

   2012     2011  

Revenues

    

Regulated electric and gas (includes franchise fees and gross receipts taxes of $26.1 in 2012 and $28.4 in 2011)

   $ 556.3      $ 587.1   

Unregulated

     173.7        209.0   
  

 

 

   

 

 

 

Total revenues

     730.0        796.1   
  

 

 

   

 

 

 

Expenses

    

Regulated operations

    

Fuel

     157.5        144.9   

Purchased power

     28.2        27.2   

Cost of natural gas sold

     41.6        82.0   

Other

     83.3        78.3   

Operation other expense

    

Mining related costs

     89.4        124.0   

Guatemalan power generation

     19.2        20.1   

Other

     2.6        1.4   

Maintenance

     44.0        48.8   

Depreciation and amortization

     83.0        79.8   

Taxes, other than income

     56.0        58.7   
  

 

 

   

 

 

 

Total expenses

     604.8        665.2   
  

 

 

   

 

 

 

Income from operations

     125.2        130.9   
  

 

 

   

 

 

 

Other income

    

Allowance for other funds used during construction

     0.4        0.3   

Other income

     2.0        1.5   
  

 

 

   

 

 

 

Total other income

     2.4        1.8   
  

 

 

   

 

 

 

Interest charges

    

Interest expense

     50.6        52.8   

Allowance for borrowed funds used during construction

     (0.2     (0.2
  

 

 

   

 

 

 

Total interest charges

     50.4        52.6   
  

 

 

   

 

 

 

Income before provision for income taxes

     77.2        80.1   

Provision for income taxes

     26.6        28.4   
  

 

 

   

 

 

 

Net income

   $ 50.6      $ 51.7   

Less: Net income attributable to noncontrolling interest

     (0.1     0.0   
  

 

 

   

 

 

 

Net income attributable to TECO Energy

   $ 50.5      $ 51.7   
  

 

 

   

 

 

 

Average common shares outstanding – Basic

     213.9        213.0   

  – Diluted

     215.3        215.0   
  

 

 

   

 

 

 

Earnings per share attributable to TECO Energy – Basic

   $ 0.24      $ 0.24   

         – Diluted

   $ 0.23      $ 0.24   
  

 

 

   

 

 

 

Dividends paid per common share outstanding

   $ 0.220      $ 0.205   

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

 

7


Table of Contents

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2012     2011  

Net income

   $ 50.6      $ 51.7   
  

 

 

   

 

 

 

Other comprehensive income, net of tax

    

Net unrealized gains on cash flow hedges

     1.5        2.3   

Amortization of unrecognized benefit costs

     0.1        0.4   
  

 

 

   

 

 

 

Other comprehensive income, net of tax

     1.6        2.7   
  

 

 

   

 

 

 

Comprehensive income

     52.2        54.4   
  

 

 

   

 

 

 

Comprehensive income attributable to noncontrolling interest

     (0.1     0.0   
  

 

 

   

 

 

 

Comprehensive income attributable to TECO Energy

   $ 52.1      $ 54.4   
  

 

 

   

 

 

 

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

 

8


Table of Contents

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2012     2011  

Cash flows from operating activities

    

Net income

   $ 50.6      $ 51.7   

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

    

Depreciation and amortization

     83.0        79.8   

Deferred income taxes

     24.8        27.2   

Investment tax credits

     0.0        (0.1

Allowance for funds used during construction

     (0.4     (0.3

Non-cash stock compensation

     2.5        2.0   

Deferred recovery clauses

     (20.5     26.9   

Receivables, less allowance for uncollectibles

     49.3        36.1   

Inventories

     (9.5     4.1   

Prepayments and other current assets

     2.2        1.9   

Taxes accrued

     13.9        9.7   

Interest accrued

     20.6        21.9   

Accounts payable

     1.7        (51.1

Other

     5.7        20.1   
  

 

 

   

 

 

 

Cash flows from operating activities

     223.9        229.9   
  

 

 

   

 

 

 

Cash flows from investing activities

    

Capital expenditures

     (117.4     (92.9

Allowance for funds used during construction

     0.4        0.3   

Other investing activities

     0.0        17.0   
  

 

 

   

 

 

 

Cash flows used in investing activities

     (117.0     (75.6
  

 

 

   

 

 

 

Cash flows from financing activities

    

Dividends

     (47.5     (44.1

Proceeds from the sales of common stock

     0.3        1.8   

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

     (88.7     (78.0

Net increase (decrease) in short-term debt

     44.0        (12.0
  

 

 

   

 

 

 

Cash flows used in financing activities

     (91.9     (132.3
  

 

 

   

 

 

 

Net increase in cash and cash equivalents

     15.0        22.0   

Cash and cash equivalents at beginning of period

     44.0        67.5   
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 59.0      $ 89.5   
  

 

 

   

 

 

 

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

 

9


Table of Contents

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries and the accounts of VIEs for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it 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 (see Note 14).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary, but is able to exert significant influence. 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 March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

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 GAAP in the United States of America.

Revenues

As of March 31, 2012 and Dec. 31, 2011, unbilled revenues of $51.1 million and $50.2 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 $26.1 million and $28.4 million for the three months ended March 31, 2012 and 2011, respectively.

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.

2. New Accounting Pronouncements

There have been no accounting pronouncements issued applicable to TECO Energy, Inc. or its subsidiaries since Dec. 31, 2011.

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 the 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

 

10


Table of Contents

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

Tampa Electric accrues $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. Tampa Electric’s storm reserve was $45.6 million and $43.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.

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 that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of March 31, 2012 and Dec. 31, 2011 are presented in the following table:

 

Regulatory Assets and Liabilities      

(millions)

   Mar. 31,
2012
     Dec. 31,
2011
 

Regulatory assets:

     

Regulatory tax asset (1)

   $ 63.0       $ 63.6   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     92.6         73.3   

Postretirement benefit asset

     248.9         252.4   

Deferred bond refinancing costs (2)

     10.1         11.1   

Environmental remediation

     30.6         30.5   

Competitive rate adjustment

     3.4         3.5   

Other

     17.6         17.4   
  

 

 

    

 

 

 

Total other regulatory assets

     403.2         388.2   
  

 

 

    

 

 

 

Total regulatory assets

     466.2         451.8   

Less: Current portion

     107.0         87.3   
  

 

 

    

 

 

 

Long-term regulatory assets

   $ 359.2       $ 364.5   
  

 

 

    

 

 

 

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 15.7       $ 16.0   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     47.8         61.4   

Environmental remediation

     28.4         28.4   

Transmission and delivery storm reserve

     45.6         43.6   

Deferred gain on property sales (3)

     4.5         5.0   

Provision for stipulation and other

     0.9         0.8   

Accumulated reserve - cost of removal

     574.2         578.8   
  

 

 

    

 

 

 

Total other regulatory liabilities

     701.4         718.0   
  

 

 

    

 

 

 

Total regulatory liabilities

     717.1         734.0   

Less: Current portion

     72.3         86.2   
  

 

 

    

 

 

 

Long-term regulatory liabilities

   $ 644.8       $ 647.8   
  

 

 

    

 

 

 

 

(1) Primarily related to plant life and derivative positions.
(2) Amortized over the term of the related debt instruments.
(3) Amortized over a 4- or 5-year period with various ending dates.

 

11


Table of Contents

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

 

Regulatory Assets      

(millions)

   Mar.  31,
2012
     Dec 31,
2011
 
     

Clause recoverable (1)

   $ 96.0       $ 76.8   

Components of rate base (2)

     261.8         264.9   

Regulatory tax assets (3)

     63.0         63.6   

Capital structure and other (3)

     45.4         46.5   
  

 

 

    

 

 

 

Total

   $ 466.2       $ 451.8   
  

 

 

    

 

 

 

 

(1) To be recovered through cost-recovery clauses 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.

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 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for years 2008 and onward. Years 2011 and 2012 are currently under examination by the IRS under their Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2012. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five 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 2006 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. During the first quarter of 2012, the company recorded $0.1 million of pretax charges for interest only and an immaterial amount for penalties.

The effective tax rate decreased to 34.5% for the three months ended March 31, 2012 from 35.4% for the same period in 2011. The decrease is principally due to state income taxes.

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 Mar. 31,

   2012     2011     2012      2011  

Components of net periodic benefit expense

         

Service cost

   $ 4.4      $ 4.2      $ 0.7       $ 0.6   

Interest cost on projected benefit obligations

     7.4        7.8        2.5         2.8   

Expected return on assets

     (9.6     (9.7     0.0         0.0   

Amortization of:

         

Transition obligation

     0.0        0.0        0.4         0.6   

Prior service (benefit) cost

     (0.1     (0.1     0.2         0.2   

Actuarial loss

     3.7        2.8        0.0         0.1   
  

 

 

   

 

 

   

 

 

    

 

 

 

Net pension expense recognized in the Consolidated Condensed Statements of Income

   $ 5.8      $ 5.0      $ 3.8       $ 4.3   
  

 

 

   

 

 

   

 

 

    

 

 

 

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $12.4 million to its pension plan in the first quarter of 2012.

For the three months ended March 31, 2012, TECO Energy and its subsidiaries reclassed $0.7 million pretax of unamortized transition obligation, prior service cost and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended March 31, 2012, TEC reclassed $3.5 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

 

12


Table of Contents

6. Short-Term Debt

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

 

Credit Facilities                  
     Mar. 31, 2012      Dec. 31, 2011  

(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       $ 0.0       $ 0.7   

1-year accounts receivable facility

     150.0         34.0         0.0         150.0         0.0         0.0   

TECO Energy/TECO Finance:

                 

5-year facility (2)(3)

     200.0         10.0         0.0         200.0         0.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 675.0       $ 44.0       $ 0.7       $ 675.0       $ 0.0       $ 0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Oct. 25, 2016.
(3) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

At March 31, 2012, these credit facilities require commitment fees ranging from 17.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2012 was 0.65%. There were no outstanding borrowings at Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 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. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 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 and (iv) makes other technical changes.

7. Long-Term Debt

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously were in auction rate mode and were held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the March 15, 2012 purchase of the HCIDA Bonds, $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of March 31, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

 

13


Table of Contents

Fair Value of Long-Term Debt

At March 31, 2012, total long-term debt had a carrying amount of $2,987.0 million and an estimated fair market value of $3,363.4 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $3,075.8 million and an estimated fair market value of $3,435.3 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.

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

 

Other Comprehensive Income       
     Three months ended Mar. 31,  

(millions)

   Gross     Tax     Net  

2012

      

Unrealized gain on cash flow hedges

   $ 2.5      $ (0.9   $ 1.6   

Less: Gain reclassified to net income

     (0.2     0.1        (0.1
  

 

 

   

 

 

   

 

 

 

Gain on cash flow hedges

     2.3        (0.8     1.5   

Amortization of unrecognized benefit costs

     0.7        (0.6     0.1   
  

 

 

   

 

 

   

 

 

 

Total other comprehensive income

   $ 3.0      $ (1.4   $ 1.6   
  

 

 

   

 

 

   

 

 

 

2011

      

Unrealized gain on cash flow hedges

   $ 4.1      $ (1.5   $ 2.6   

Less: Gain reclassified to net income

     (0.5     0.2        (0.3
  

 

 

   

 

 

   

 

 

 

Gain on cash flow hedges

     3.6        (1.3     2.3   

Amortization of unrecognized benefit costs

     0.6        (0.2     0.4   
  

 

 

   

 

 

   

 

 

 

Total other comprehensive income

   $ 4.2      $ (1.5   $ 2.7   
  

 

 

   

 

 

   

 

 

 

 

Accumulated Other Comprehensive Loss     

(millions)

   Mar. 31, 2012     Dec. 31, 2011  

Unrecognized pension loss and prior service credit (1)

   $ (31.1   $ (31.2

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

     14.2        14.2   

Net unrealized losses from cash flow hedges (3)

     (3.5     (5.0
  

 

 

   

 

 

 

Total accumulated other comprehensive loss

   $ (20.4   $ (22.0
  

 

 

   

 

 

 

 

(1) Net of tax benefit of $19.1 million and $19.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.
(2) Net of tax expense of $6.2 million and $6.2 million as of March 31, 2012 and Dec. 31, 2011, respectively.
(3) Net of tax benefit of $2.3 million and $3.2 million as of March 31, 2012 and Dec. 31, 2011, respectively.

 

14


Table of Contents

9. Earnings Per Share

 

Earnings Per Share     
     Three months ended Mar. 31,  

(millions, except per share amounts)

   2012     2011  

Basic earnings per share

    

Net income

   $ 50.6      $ 51.7   

Less: Income attributable to noncontrolling interest

     (0.1     0.0   

Less: Amount allocated to nonvested participating shareholders

     (0.2     (0.3
  

 

 

   

 

 

 

Net income attributable to TECO Energy available to common shareholders - Basic

   $ 50.3      $ 51.4   
  

 

 

   

 

 

 

Average common shares outstanding - Basic

     213.9        213.0   
  

 

 

   

 

 

 

Earnings per share attributable to TECO Energy available to common shareholders - Basic

   $ 0.24      $ 0.24   
  

 

 

   

 

 

 

Diluted earnings per share

    

Net income

   $ 50.6      $ 51.7   

Less: Income attributable to noncontrolling interest

     (0.1     0.0   

Less: Amount allocated to nonvested participating shareholders

     (0.2     (0.3
  

 

 

   

 

 

 

Net income attributable to TECO Energy available to common shareholders - Diluted

   $ 50.3      $ 51.4   
  

 

 

   

 

 

 

Average common shares outstanding - Basic

     213.9        213.0   

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

     1.4        2.0   
  

 

 

   

 

 

 

Average common shares outstanding - Diluted

     215.3        215.0   
  

 

 

   

 

 

 

Earnings per share attributable to TECO Energy available to common shareholders - Diluted

   $ 0.23      $ 0.24   
  

 

 

   

 

 

 

Anti-dilutive shares

     1.4        2.4   
  

 

 

   

 

 

 

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.

Merco Group at Aventura Landings v. Peoples Gas System

In a Florida district court case pending in Miami, Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and the parties are awaiting a ruling by the Judge. Co-defendant Continental Holdings, Inc. reached a settlement with Merco but still remains as a defendant in PGS’s third-party complaint.

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 March 31, 2012, TEC has estimated its ultimate financial liability to be $28.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on the company’s Consolidated Condensed Balance Sheet. 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 estimated 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.

 

15


Table of Contents

In instances where other PRPs are involved, many 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. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the EPA notified TEC that it is a PRP under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by TEC in Tampa, Florida. The property owned by TEC is undeveloped except for the location of transmission lines and poles, and is adjacent to an industrial site, not owned by TEC, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to TEC’s ownership of the property described above but, to the knowledge of TEC, this assertion is not based upon any release of hazardous substances by TEC. TEC has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal, received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. TECO Coal responded to the EPA on Feb. 14, 2011. The scope and extent of TECO Coal’s potential liability, if any, and the costs of any required investigation and remediation related to these inactive mining operations in the area have not been determined.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and TEC’s letters of credit and guarantees as of March 31, 2012 is as follows:

 

Guarantees - TECO Energy               

(millions)

Guarantees for the Benefit of:

   2012      2013-2016      After(1)
2016
     Total      Liabilities Recognized
at Mar. 31, 2012
 

TECO Coal

              

Fuel purchase related (2)

   $ 0.0       $ 0.0       $ 5.4       $ 5.4       $ 1.2   

Other subsidiaries

              

Fuel purchase/energy management (2)

     0.0         10.0         94.7         104.7         0.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 10.0       $ 100.1       $ 110.1       $ 1.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

Letters of Credit - Tampa Electric Company               

(millions)

Letters of Credit for the Benefit of:

   2012      2013-2016      After(1)
2016
     Total      Liabilities Recognized
at Mar. 31, 2012
 
              

Tampa Electric (2)

   $ 0.0       $   0.0       $     0.7       $     0.7       $ 0.2   

 

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2016.
(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 March 31, 2012. 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 as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At March 31, 2012, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

 

16


Table of Contents

11. Segment Information

TECO Energy is an electric and gas utility holding company with significant 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.

 

Segment Information (1)                 

(millions)

Three months ended Mar. 31,

   Tampa
Electric
     Peoples
Gas
     TECO
Coal
     TECO
Guatemala
     Other &
Eliminations
    TECO
Energy
 

2012

                

Revenues - external

   $ 446.3       $ 110.0       $ 138.4       $ 32.9       $ 2.4      $ 730.0   

Sales to affiliates

     0.3         0.2         0.0         0.0         (0.5     0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     446.6         110.2         138.4         32.9         1.9        730.0   

Depreciation and amortization

     57.4         12.6         10.8         1.8         0.4        83.0   

Total interest charges(1)

     30.0         4.4         1.8         2.1         12.1        50.4   

Internally allocated interest (1)

     0.0         0.0         1.7         1.8         (3.5     0.0   

Provision (benefit) for income taxes

     18.9         6.9         3.1         2.7         (5.0     26.6   

Net income (loss) attributable to

                

TECO Energy

   $ 31.4       $ 11.0       $ 9.8       $ 6.6       ($ 8.3   $ 50.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

2011

                

Revenues - external

   $ 432.9       $ 154.2       $ 173.7       $ 33.6       $ 1.7      $ 796.1   

Sales to affiliates

     0.3         1.9         0.0         0.0         (2.2     0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     433.2         156.1         173.7         33.6         (0.5     796.1   

Depreciation and amortization

     54.9         11.8         10.9         1.8         0.4        79.8   

Total interest charges(1)

     30.9         4.5         1.7         1.9         13.6        52.6   

Internally allocated interest (1)

     0.0         0.0         1.6         1.5         (3.1     0.0   

Provision (benefit) for income taxes

     20.0         9.3         1.6         2.8         (5.3     28.4   

Net income (loss) attributable to

                

TECO Energy

   $ 31.6       $ 14.7       $ 8.2       $ 6.3       ($ 9.1   $ 51.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

At Mar. 31, 2012

                

Goodwill

     0.0         0.0         0.0         55.4         0.0        55.4   

Total assets

   $ 5,932.3       $ 947.7       $ 363.8       $ 314.2       ($ 271.2   $ 7,286.8   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

At Dec. 31, 2011

                

Goodwill

     0.0         0.0         0.0         55.4         0.0        55.4   

Total assets

   $ 5,940.9       $ 932.0       $ 385.2       $ 304.1       ($ 240.0   $ 7,322.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(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 2012 through March 2012 were at a pretax rate of 6.00% and for 2011 were at a pretax rate of 6.25% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

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

 

17


Table of Contents

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 March 31, 2012, 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 March 31, 2012 and Dec. 31, 2011:

 

Total Derivatives(1)      

(millions)

   Mar. 31,
2012
     Dec. 31,
2011
 

Current assets

   $ 2.1       $ 0.9   

Long-term assets

     0.0         0.0   
  

 

 

    

 

 

 

Total assets

   $ 2.1       $ 0.9   
  

 

 

    

 

 

 

Current liabilities

   $ 70.0       $ 58.4   

Long-term liabilities

     6.6         8.6   
  

 

 

    

 

 

 

Total liabilities

   $ 76.6       $ 67.0   
  

 

 

    

 

 

 

 

(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 derivative hedges of diesel fuel contracts at March 31, 2012 and Dec. 31, 2011 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

 

Diesel Fuel Derivatives      

(millions)

   Mar. 31,
2012
     Dec. 31,
2011
 

Current assets

   $ 2.1       $ 0.9   

Long-term assets

     0.0         0.0   
  

 

 

    

 

 

 

Total assets

   $ 2.1       $ 0.9   
  

 

 

    

 

 

 

Current liabilities

   $ 0.0       $ 0.0   

Long-term liabilities

     0.4         1.2   
  

 

 

    

 

 

 

Total liabilities

   $ 0.4       $ 1.2   
  

 

 

    

 

 

 

 

18


Table of Contents

The following table presents the derivative hedges of natural gas contracts at March 31, 2012 and Dec. 31, 2011 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)

   Mar. 31,
2012
     Dec. 31,
2011
 

Current assets

   $ 0.0       $ 0.0   

Long-term assets

     0.0         0.0   
  

 

 

    

 

 

 

Total assets

   $ 0.0       $ 0.0   
  

 

 

    

 

 

 

Current liabilities

   $ 70.0       $ 58.4   

Long-term liabilities

     6.2         7.4   
  

 

 

    

 

 

 

Total liabilities

   $ 76.2       $ 65.8   
  

 

 

    

 

 

 

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at March 31, 2012 is a net loss of $3.5 million after tax and accumulated amortization. This compares to a net loss of $5.0 million in AOCI after tax and accumulated amortization at Dec. 31, 2011.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2012:

 

Derivatives Designated as Hedging Instruments

 

  

        
     Asset Derivatives      Liability Derivatives  

(millions)

Mar. 31, 2012

   Balance Sheet
Location
     Fair
Value
     Balance Sheet
Location
     Fair
Value
 

Commodity Contracts:

           

Diesel fuel derivatives:

           

Current

     Derivative assets       $ 2.1         Derivative liabilities       $ 0.0   

Long-term

     Derivative assets         0.0         Derivative liabilities         0.4   

Natural gas derivatives:

           

Current

     Derivative assets         0.0         Derivative liabilities         70.0   

Long-term

     Derivative assets         0.0         Derivative liabilities         6.2   
     

 

 

       

 

 

 

Total derivatives designated as hedging instruments

  

   $ 2.1          $ 76.6   
     

 

 

       

 

 

 

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of March 31, 2012:

 

Energy Related Derivatives

 

     
     Asset Derivatives      Liability Derivatives  

(millions)

Mar. 31, 2012

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

Commodity Contracts:

           

Natural gas derivatives:

           

Current

     Regulatory liabilities       $ 0.0         Regulatory assets       $ 70.0   

Long-term

     Regulatory liabilities         0.0         Regulatory assets         6.2   
     

 

 

       

 

 

 

Total

      $ 0.0          $ 76.2   
     

 

 

       

 

 

 

 

(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 March 31, 2012, net pretax losses of $70.0 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

 

19


Table of Contents

The following table presents the effect of hedging instruments on OCI and income for the three months ended March 31:

 

(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)
 

2012

        

Interest rate contracts

   $ 0.0       Interest expense    ($ 0.1

Commodity contracts:

        

Diesel fuel derivatives

     1.6       Mining related costs      0.2   
  

 

 

       

 

 

 

Total

   $ 1.6          $ 0.1   
  

 

 

       

 

 

 

2011

        

Interest rate contracts

   $ 0.0       Interest expense    ($ 0.1

Commodity contracts:

        

Diesel fuel derivatives

     2.6       Mining related costs      0.4   
  

 

 

       

 

 

 

Total

   $ 2.6          $ 0.3   
  

 

 

       

 

 

 

 

(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 months ended March 31, 2012 and 2011, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the three months ended March 31:

 

(millions)

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

2012

        

Interest rate swaps

   $ 0.0       $ 0.0       ($ 0.1

Diesel fuel derivatives

     1.7         1.6         0.2   
  

 

 

    

 

 

    

 

 

 

Total

   $ 1.7       $ 1.6       $ 0.1   
  

 

 

    

 

 

    

 

 

 

2011

        

Interest rate swaps

   $ 0.0       $ 0.0       ($ 0.1

Diesel fuel derivatives

     5.1         2.6         0.4   
  

 

 

    

 

 

    

 

 

 

Total

   $ 5.1       $ 2.6       $ 0.3   
  

 

 

    

 

 

    

 

 

 

 

(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 both financial natural gas and financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

 

(millions)

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

Year

   Physical      Financial      Physical      Financial  

2012

     0.0         7.4         0.0         30.8   

2013

     0.0         2.7         0.0         10.7   

2014

     0.0         1.5         0.0         1.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     0.0         11.6         0.0         42.5   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

20


Table of Contents

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 March 31, 2012, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are 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 in valuing counterparty positions. The company monitors counterparties’ credit standings, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. 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, forward-looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2012, all positions with counterparties are net liabilities.

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.

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at March 31, 2012:

 

Contingent Features

 

      

(millions)

At Mar. 31, 2012

   Fair Value
Asset/
(Liability)
    Derivative
Exposure
Asset/
(Liability)
    Posted
Collateral
 

Credit Rating

   ($ 76.6   ($ 76.6   $ 0.0   

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 March 31, 2012 and Dec. 31, 2011. 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.

 

21


Table of Contents

Recurring Fair Value Measures

 

  
     At fair value as of Mar. 31, 2012  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   

Diesel fuel swaps

     0.0         2.1         0.0         2.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 2.1       $ 0.0       $ 2.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 76.2       $ 0.0       $ 76.2   

Diesel fuel swaps

     0.0         0.4         0.0         0.4   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 76.6       $ 0.0       $ 76.6   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     At fair value as of Dec. 31, 2011  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   

Diesel fuel swaps

     0.0         0.9         0.0         0.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.9       $ 0.0       $ 0.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 65.8       $ 0.0       $ 65.8   

Diesel fuel swaps

     0.0         1.2         0.0         1.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 67.0       $ 0.0       $ 67.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Natural gas and diesel fuel swaps are over-the-counter 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 March 31, 2012, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were liability positions.

14. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE’s primary beneficiary. Under the amended standard, 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 370 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 $22.5 million and $15.8 million of capacity pursuant to PPAs for the three months ended March 31, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore,

 

22


Table of Contents

the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $14.6 million and $7.1 million for the three months ended March 31, 2012 and 2011, respectively, under this PPA.

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.

 

23


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 March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. 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, 2011 and to the notes on pages 29 through 38 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

     Page
No.
 

Consolidated Condensed Balance Sheets, March 31, 2012 and Dec. 31, 2011

     25-26   

Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended March 31, 2012 and 2011

     27   

Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2012 and 2011

     28   

Notes to Consolidated Condensed Financial Statements

     29-38   

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.

 

24


Table of Contents

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

Assets

(millions)

   Mar. 31,
2012
    Dec. 31,
2011
 

Property, plant and equipment

    

Utility plant in service

    

Electric

   $ 6,549.8      $ 6,516.0   

Gas

     1,128.3        1,113.5   

Construction work in progress

     266.2        239.2   
  

 

 

   

 

 

 

Utility plant in service, at original costs

     7,944.3        7,868.7   

Accumulated depreciation

     (2,284.9     (2,230.3
  

 

 

   

 

 

 
     5,659.4        5,638.4   

Other property, net

     6.4        6.5   
  

 

 

   

 

 

 

Total property, plant and equipment, net

     5,665.8        5,644.9   
  

 

 

   

 

 

 

Current assets

    

Cash and cash equivalents

     10.5        13.9   

Receivables, less allowance for uncollectibles of $1.3 at Mar. 31, 2012 and Dec. 31, 2011

     204.2        216.8   

Inventories, at average cost

    

Fuel

     83.4        97.9   

Materials and supplies

     67.0        67.7   

Regulatory assets

     107.0        87.3   

Taxes receivable

     0.0        14.6   

Deferred income taxes

     28.2        30.4   

Prepayments and other current assets

     9.6        10.5   
  

 

 

   

 

 

 

Total current assets

     509.9        539.1   
  

 

 

   

 

 

 

Deferred debits

    

Unamortized debt expense

     13.3        14.1   

Regulatory assets

     359.2        364.5   

Other

     5.5        8.8   
  

 

 

   

 

 

 

Total deferred debits

     378.0        387.4   
  

 

 

   

 

 

 

Total assets

   $ 6,553.7      $ 6,571.4   
  

 

 

   

 

 

 

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

 

25


Table of Contents

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

 

Liabilities and Capital

(millions)

   Mar. 31,
2012
    Dec. 31,
2011
 

Capital

    

Common stock

   $ 1,852.4      $ 1,852.4   

Accumulated other comprehensive loss

     (4.5     (4.6

Retained earnings

     296.6        305.7   
  

 

 

   

 

 

 

Total capital

     2,144.5        2,153.5   

Long-term debt, less amount due within one year

     1,530.5        1,616.3   
  

 

 

   

 

 

 

Total capitalization

     3,675.0        3,769.8   
  

 

 

   

 

 

 

Current liabilities

    

Long-term debt due within one year

     374.9        374.9   

Notes payable

     34.0        0.0   

Accounts payable

     187.2        191.3   

Customer deposits

     160.9        159.5   

Regulatory liabilities

     72.3        86.2   

Derivative liabilities

     70.0        58.4   

Interest accrued

     44.1        25.6   

Taxes accrued

     21.2        11.9   

Other

     11.6        11.6   
  

 

 

   

 

 

 

Total current liabilities

     976.2        919.4   
  

 

 

   

 

 

 

Deferred credits

    

Deferred income taxes

     861.6        833.0   

Investment tax credits

     10.0        10.0   

Derivative liabilities

     6.2        7.4   

Regulatory liabilities

     644.8        647.8   

Other

     379.9        384.0   
  

 

 

   

 

 

 

Total deferred credits

     1,902.5        1,882.2   
  

 

 

   

 

 

 

Total liabilities and capital

   $ 6,553.7      $ 6,571.4   
  

 

 

   

 

 

 

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

 

26


Table of Contents

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2012     2011  

Revenues

    

Electric (includes franchise fees and gross receipts taxes of $19.9 in 2012 and $19.3 in 2011)

   $ 446.5      $ 433.1   

Gas (includes franchise fees and gross receipts taxes of $6.2 in 2012 and $9.1 in 2011)

     110.0        154.2   
  

 

 

   

 

 

 

Total revenues

     556.5        587.3   
  

 

 

   

 

 

 

Expenses

    

Operations

    

Fuel

     157.5        144.9   

Purchased power

     28.2        27.2   

Cost of natural gas sold

     41.6        82.0   

Other

     83.1        78.2   

Maintenance

     29.0        31.5   

Depreciation and amortization

     70.0        66.7   

Taxes, federal and state

     25.6        29.1   

Taxes, other than income

     45.4        46.6   
  

 

 

   

 

 

 

Total expenses

     480.4        506.2   
  

 

 

   

 

 

 

Income from operations

     76.1        81.1   
  

 

 

   

 

 

 

Other income

    

Allowance for other funds used during construction

     0.4        0.3   

Taxes, non-utility federal and state

     (0.2     (0.2

Other income, net

     0.5        0.5   
  

 

 

   

 

 

 

Total other income

     0.7        0.6   
  

 

 

   

 

 

 

Interest charges

    

Interest on long-term debt

     31.7        32.7   

Other interest

     2.9        2.9   

Allowance for borrowed funds used during construction

     (0.2     (0.2
  

 

 

   

 

 

 

Total interest charges

     34.4        35.4   
  

 

 

   

 

 

 

Net income

     42.4        46.3   
  

 

 

   

 

 

 

Other comprehensive income, net of tax

    

Net unrealized gains on cash flow hedges

     0.1        0.1   
  

 

 

   

 

 

 

Total other comprehensive income, net of tax

     0.1        0.1   
  

 

 

   

 

 

 

Comprehensive income

   $ 42.5      $ 46.4   
  

 

 

   

 

 

 

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

 

27


Table of Contents

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

     Three months ended Mar. 31,  

(millions)

   2012     2011  

Cash flows from operating activities

    

Net income

   $ 42.4      $ 46.3   

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

    

Depreciation and amortization

     70.0        66.7   

Deferred income taxes

     31.0        27.3   

Investment tax credits

     0.0        (0.1

Allowance for funds used during construction

     (0.4     (0.3

Gain on sale of business/assets, pretax

     (0.1     (0.1

Deferred recovery clauses

     (20.5     26.9   

Receivables, less allowance for uncollectibles

     11.2        58.4   

Inventories

     15.1        5.9   

Prepayments

     0.9        1.3   

Taxes accrued

     23.9        37.3   

Interest accrued

     18.5        18.8   

Accounts payable

     6.6        (60.4

Other

     5.3        12.4   
  

 

 

   

 

 

 

Cash flows from operating activities

     203.9        240.4   
  

 

 

   

 

 

 

Cash flows from investing activities

    

Capital expenditures

     (104.6     (78.1

Allowance for funds used during construction

     0.4        0.3   

Net proceeds from sale of assets

     0.3        2.6   
  

 

 

   

 

 

 

Cash flows used in investing activities

     (103.9     (75.2
  

 

 

   

 

 

 

Cash flows from financing activities

    

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

     (86.0     (75.2

Net increase (decrease) in short-term debt

     34.0        (12.0

Dividends

     (51.4     (54.5
  

 

 

   

 

 

 

Cash flows used in financing activities

     (103.4     (141.7
  

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

     (3.4     23.5   

Cash and cash equivalents at beginning of period

     13.9        3.7   
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 10.5      $ 27.2   
  

 

 

   

 

 

 

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

 

28


Table of Contents

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant 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. TEC is considered to be the primary beneficiary of VIEs if it 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. 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 March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

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 GAAP in the United States of America.

Revenues

As of March 31, 2012 and Dec. 31, 2011, unbilled revenues of $51.1 million and $50.2 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for 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 $26.1 million and $28.4 million for the three months ended March 31, 2012 and 2011, respectively.

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

There have been no accounting pronouncements issued applicable to TEC or its subsidiaries since Dec. 31, 2011.

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.

 

29


Table of Contents

Storm Damage Cost Recovery

Tampa Electric accrues $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. Tampa Electric’s storm reserve was $45.6 million and $43.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.

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 that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of March 31, 2012 and Dec. 31, 2011 are presented in the following table:

 

Regulatory Assets and Liabilities      

(millions)

   Mar. 31,
2012
     Dec. 31,
2011
 

Regulatory assets:

     

Regulatory tax asset (1)

   $ 63.0       $ 63.6   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     92.6         73.3   

Postretirement benefit asset

     248.9         252.4   

Deferred bond refinancing costs (2)

     10.1         11.1   

Environmental remediation

     30.6         30.5   

Competitive rate adjustment

     3.4         3.5   

Other

     17.6         17.4   
  

 

 

    

 

 

 

Total other regulatory assets

     403.2         388.2   
  

 

 

    

 

 

 

Total regulatory assets

     466.2         451.8   

Less: Current portion

     107.0         87.3   
  

 

 

    

 

 

 

Long-term regulatory assets

   $ 359.2       $ 364.5   
  

 

 

    

 

 

 

Regulatory liabilities:

     

Regulatory tax liability (1)

   $ 15.7       $ 16.0   
  

 

 

    

 

 

 

Other:

     

Cost-recovery clauses

     47.8         61.4   

Environmental remediation

     28.4         28.4   

Transmission and delivery storm reserve

     45.6         43.6   

Deferred gain on property sales (3)

     4.5         5.0   

Provision for stipulation and other

     0.9         0.8   

Accumulated reserve - cost of removal

     574.2         578.8   
  

 

 

    

 

 

 

Total other regulatory liabilities

     701.4         718.0   
  

 

 

    

 

 

 

Total regulatory liabilities

     717.1         734.0   

Less: Current portion

     72.3         86.2   
  

 

 

    

 

 

 

Long-term regulatory liabilities

   $ 644.8       $ 647.8   
  

 

 

    

 

 

 

 

(1) Primarily related to plant life and derivative positions.
(2) Amortized over the term of the related debt instruments.
(3) Amortized over a 4- or 5-year period with various ending dates.

 

30


Table of Contents

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

 

Regulatory Assets      

(millions)

   Mar. 31,
2012
     Dec. 31,
2011
 

Clause recoverable (1)

   $ 96.0       $ 76.8   

Components of rate base (2)

     261.8         264.9   

Regulatory tax assets (3)

     63.0         63.6   

Capital structure and other (3)

     45.4         46.5   
  

 

 

    

 

 

 

Total

   $ 466.2       $ 451.8   
  

 

 

    

 

 

 

 

(1) To be recovered through cost-recovery clauses 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.

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 three months ended March 31, 2012 and 2011 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 the company’s 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2011 and 2012 are currently under examination by the IRS under the Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2012. 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 2008 and onward.

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 March 31, 2012 and 2011, respectively, was $4.2 million and $3.6 million for pension benefits, and $3.1 million and $3.5 million for other postretirement benefits.

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $12.4 million to its pension plan in the first quarter of 2012. TEC’s portion of the contributions was $9.7 million.

Included in the benefit expenses discussed above, for the three months ended March 31, 2012, TEC reclassed $3.5 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

 

31


Table of Contents

6. Short-Term Debt

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

 

Credit Facilities                  
     Mar. 31, 2012      Dec. 31, 2011  

(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       $ 0.0       $ 0.7   

1-year accounts receivable facility

     150.0         34.0         0.0         150.0         0.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 475.0       $ 34.0       $ 0.7       $ 475.0       $ 0.0       $ 0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Oct. 25, 2016.

At March 31, 2012, these credit facilities require commitment fees ranging from 17.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2012 was 0.65%. There were no outstanding borrowings at Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 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. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 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 and (iv) makes other technical changes.

7. Long-Term Debt

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA had remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

On March 1, 2011, TEC purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously were in auction rate mode and were held by TEC since March 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to March 1, 2011.

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the March 15, 2012 purchase of the HCIDA Bonds, $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of March 31, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Fair Value of Long-Term Debt

At March 31, 2012, TEC’s total long-term debt had a carrying amount of $1,906.3 million and an estimated fair market value of $2,197.2 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $1,992.3 million and an estimated fair market value of $2,291.5 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.

 

32


Table of Contents

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 TEC’s results of operations, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

In a Florida district court case pending in Miami, Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and the parties are awaiting a ruling by the Judge. Co-defendant Continental Holdings, Inc. reached a settlement with Merco but still remains as a defendant in PGS’s third-party complaint.

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 March 31, 2012, TEC has estimated its ultimate financial liability to be $28.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on TEC’s Consolidated Condensed Balance Sheet. 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 estimated 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, many 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. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the EPA notified TEC that it is a PRP under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by TEC in Tampa, Florida. The property owned by TEC is undeveloped except for the location of transmission lines and poles, and is adjacent to an industrial site, not owned by TEC, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to TEC’s ownership of the property described above but, to the knowledge of TEC, this assertion is not based upon any release of hazardous substances by TEC. TEC has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

 

33


Table of Contents

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of March 31, 2012 are as follows:

 

Letters of Credit -Tampa Electric Company               

(millions)

   2012      2013-2016      After(1)
2016
     Total      Liabilities Recognized
at Mar. 31, 2012
 

Letters of Credit for the Benefit of:

              

Tampa Electric (2) 

   $ 0.0       $ 0.0       $ 0.7       $ 0.7       $ 0.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2016.
(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 March 31, 2012. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At March 31, 2012, TEC was in compliance with all applicable financial covenants.

9. Segment Information

 

(millions)

Three months ended Mar. 31,

   Tampa
Electric
     Peoples
Gas
     Other &
Eliminations
    Tampa Electric
Company
 

2012

          

Revenues - external

   $ 446.4       $ 110.1       $ 0.0      $ 556.5   

Sales to affiliates

     0.2         0.1         (0.3     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     446.6         110.2         (0.3     556.5   

Depreciation and amortization

     57.4         12.6         0.0        70.0   

Total interest charges

     30.0         4.4         0.0        34.4   

Provision for income taxes

     18.9         6.9         0.0        25.8   

Net income

   $ 31.4       $ 11.0       $ 0.0      $ 42.4   
  

 

 

    

 

 

    

 

 

   

 

 

 

2011

          

Revenues - external

   $ 431.3       $ 156.0       $ 0.0      $ 587.3   

Sales to affiliates

     1.9         0.1         (2.0     0.0   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     433.2         156.1         (2.0     587.3   

Depreciation and amortization

     54.9         11.8         0.0        66.7   

Total interest charges

     30.9         4.5         0.0        35.4   

Provision for income taxes

     20.0         9.3         0.0        29.3   

Net income

   $ 31.6       $ 14.7       $ 0.0      $ 46.3   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets at Mar. 31, 2012

   $ 5,676.0       $ 904.8       ($ 27.1   $ 6,553.7   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets at Dec. 31, 2011

   $ 5,693.0       $ 888.4       ($ 10.0   $ 6,571.4   
  

 

 

    

 

 

    

 

 

   

 

 

 

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.

 

34


Table of Contents

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 March 31, 2012, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at March 31, 2012 and Dec. 31, 2011 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)

   Mar. 31,
2012
     Dec. 31,
2011
 

Current assets

   $ 0.0       $ 0.0   

Long-term assets

     0.0         0.0   
  

 

 

    

 

 

 

Total assets

   $ 0.0       $ 0.0   
  

 

 

    

 

 

 

Current liabilities (1)

   $ 70.0       $ 58.4   

Long-term liabilities

     6.2         7.4   
  

 

 

    

 

 

 

Total liabilities

   $ 76.2       $ 65.8   
  

 

 

    

 

 

 

 

(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 March 31, 2012 is a net loss of $4.5 million after tax and accumulated amortization. This compares to a net loss of $4.6 million in AOCI after tax and accumulated amortization at Dec. 31, 2011.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of March 31, 2012:

 

Energy Related Derivatives            
     Asset Derivatives      Liability Derivatives  

(millions)

Mar. 31, 2012

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

Commodity Contracts:

           

Natural gas derivatives:

           

Current

   Regulatory liabilities    $ 0.0       Regulatory assets    $ 70.0   

Long-term

   Regulatory liabilities      0.0       Regulatory assets      6.2   
     

 

 

       

 

 

 

Total

      $ 0.0          $ 76.2   
     

 

 

       

 

 

 

 

(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 March 31, 2012, net pretax losses of $70.0 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

 

35


Table of Contents

The following table presents the effect of hedging instruments on OCI and income for the three months ended March 31:

 

(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)
 

2012

        

Interest rate contracts

   $ 0.0       Interest expense    ($ 0.1
  

 

 

       

 

 

 

Total

   $ 0.0          ($ 0.1
  

 

 

       

 

 

 

2011

        

Interest rate contracts

   $ 0.0       Interest expense    ($ 0.1
  

 

 

       

 

 

 

Total

   $ 0.0          ($ 0.1
  

 

 

       

 

 

 

 

(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 months ended March 31, 2012 and 2011, all hedges were effective.

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 the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

 

(millions)

   Natural Gas Contracts
(MMBTUs)
 

Year

   Physical      Financial  

2012

     0.0         30.8   

2013

     0.0         10.7   

2014

     0.0         1.0   
  

 

 

    

 

 

 

Total

     0.0         42.5   
  

 

 

    

 

 

 

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 March 31, 2012, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio are 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. 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. 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 in valuing counterparty positions. TEC monitors counterparties’ credit standings, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. 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, forward-looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2012, all positions with counterparties are net liabilities.

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.

 

36


Table of Contents

The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at March 31, 2012:

 

Contingent Features       

(millions)

Mar. 31, 2012

   Fair Value
Asset/
(Liability)
    Derivative
Exposure
Asset/
(Liability)
    Posted
Collateral
 

Credit Rating

   ($ 76.2   ($ 76.2   $ 0.0   

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 March 31, 2012 and Dec. 31, 2011. 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 Mar. 31, 2012  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 76.2       $ 0.0       $ 76.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 76.2       $ 0.0       $ 76.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     At fair value as of Dec. 31, 2011  

(millions)

   Level 1      Level 2      Level 3      Total  

Assets

           

Natural gas swaps

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 0.0       $ 0.0       $ 0.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities

           

Natural gas swaps

   $ 0.0       $ 65.8       $ 0.0       $ 65.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 0.0       $ 65.8       $ 0.0       $ 65.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

Natural gas swaps are over-the-counter 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 March 31, 2012, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions.

 

37


Table of Contents

12. Other Comprehensive Income

 

Other Comprehensive Income    Three months ended Mar. 31,  

(millions)

   Gross      Tax     Net  

2012

       

Unrealized gain on cash flow hedges

   $ 0.0       $ 0.0      $ 0.0   

Plus: Loss reclassified to net income

     0.3         (0.2     0.1   
  

 

 

    

 

 

   

 

 

 

Gain on cash flow hedges

     0.3         (0.2     0.1   
  

 

 

    

 

 

   

 

 

 

Total other comprehensive income (loss)

   $ 0.3       ($ 0.2   $ 0.1   
  

 

 

    

 

 

   

 

 

 

2011

       

Unrealized gain on cash flow hedges

   $ 0.0       $ 0.0      $ 0.0   

Plus: Loss reclassified to net income

     0.3         (0.2     0.1   
  

 

 

    

 

 

   

 

 

 

Gain on cash flow hedges

     0.3         (0.2     0.1   
  

 

 

    

 

 

   

 

 

 

Total other comprehensive income (loss)

   $ 0.3       ($ 0.2   $ 0.1   
  

 

 

    

 

 

   

 

 

 

 

Accumulated Other Comprehensive Loss

            

(millions)

   Mar. 31, 2012     Dec. 31, 2011  

Net unrealized losses from cash flow hedges (1)

   ($ 4.5   ($ 4.6
  

 

 

   

 

 

 

Total accumulated other comprehensive loss

   ($ 4.5   ($ 4.6
  

 

 

   

 

 

 

 

(1) Net of tax benefit of $2.7 million and $2.9 million as of March 31, 2012 and Dec. 31, 2011, respectively.

13. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE’s primary beneficiary. Under the amended standard, 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 370 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 $22.5 million and $15.8 million of capacity pursuant to PPAs for the three months ended March 31, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $14.6 million and $7.1 million for the three months ended March 31, 2012 and 2011, respectively, under this PPA.

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

 

38


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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. 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; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; 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 alternative fuels used for power generation affecting demand for TECO Coal’s thermal coal production; weather variations and changes in customer energy usage patterns affecting sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions or hurricanes; operating conditions; commodity prices; operating cost and environmental or safety regulations affecting the production levels and margins at TECO Coal; fuel cost recoveries and related cash at Tampa Electric and natural gas demand at Peoples Gas; the ability to complete the scheduled 2012 outage at the San José Power Station on time and on budget; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2011.

 

Earnings Summary - Unaudited      
     Three months ended Mar. 31,  

(millions, except per share amounts)

   2012      2011  

Consolidated revenues

   $ 730.0       $ 796.1   
  

 

 

    

 

 

 

Net income attributable to TECO Energy

   $ 50.5       $ 51.7   
  

 

 

    

 

 

 

Average common shares outstanding

     

Basic

     213.9         213.0   
  

 

 

    

 

 

 

Diluted

     215.3         215.0   
  

 

 

    

 

 

 

Earnings per share - Basic

   $ 0.24       $ 0.24   
  

 

 

    

 

 

 

Earnings per share - Diluted

   $ 0.23       $ 0.24   
  

 

 

    

 

 

 

Operating Company Results

All amounts included in the operating company and Parent/other results discussions are after tax, unless otherwise noted.

Tampa Electric – Electric Division

Net income for the first quarter was $31.4 million, compared with $31.6 million for the same period in 2011 reflecting slightly higher base revenues offset by higher depreciation expense. Energy sales were higher driven in part by higher industrial volumes. Residential sales were impacted by very mild winter weather in January and February offset by warmer than normal March weather, compared to 2011, when the weather was mild throughout the quarter.

Total heating and cooling degree days were 9% above normal in 2012 and 10% above 2011 levels, driven by warmer than normal March weather. The benefit of above-normal cooling degree days in March was partially offset by heating degree days approximately 50% below normal in the first quarter.

Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 3.4% in the first quarter of 2012, compared to the same period in 2011. The first quarter energy sales shown on the statistical summary that follows reflect the higher sales associated with the late December 2010 cold weather that were included in 2011 energy sales due to the timing of billing cycles, and year-to-year variations in the billing cycles. Higher sales to industrial-phosphate customers were driven by an outage on a phosphate customer’s own generating unit in the first quarter of 2012 and relocation of large electric-driven mining equipment to Tampa Electric’s system. Higher sales to commercial customers reflect improvements in the local economy, and lower sales to the weather-sensitive residential customers are a result of the mild winter weather.

Because the 3.4% increase in energy sales was driven primarily by higher sales to the lower margin interruptible customers, first quarter pretax base revenues were only $1.8 million higher than 2011, reflecting the effects of mild weather on the weather-sensitive residential and small commercial customers. The average number of customers increased 1.0% in the 2012 first quarter as a result of improvements in the Florida economy and Tampa area housing market. First quarter 2012 customer growth was the strongest customer growth since the fourth quarter of 2007.

 

39


Table of Contents

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was essentially unchanged in the first quarter of 2012, compared to the same period in 2011, reflecting lower bad debt expense offset by higher other operating costs. Depreciation and amortization expense increased $1.5 million due to additions to facilities to serve customers.

A summary of Tampa Electric’s regulated operating statistics for the three months ended March 31, 2012 and 2011 follows:

 

(millions, except average customers)    Operating Revenues     Kilowatt-hour sales  

Three months ended Mar. 31,

   2012      2011     % Change     2012      2011      % Change  

By Customer Type

               

Residential

   $ 197.3       $ 225.3        (12.4     1,725.1         1,973.9         (12.6

Commercial

     139.9         138.8        0.8        1,393.9         1,391.2         0.2   

Industrial – Phosphate

     18.4         15.5        18.7        222.7         184.3         20.8   

Industrial – Other

     24.1         23.3        3.4        258.3         251.4         2.7   

Other sales of electricity

     42.6         43.1        (1.2     416.1         420.2         (1.0

Deferred and other revenues (1)

     7.5         (33.8     (122.2        
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Total energy sales

   $ 429.8       $ 412.2        4.3        4,016.1         4,221.0         (4.9

Sales for resale

     3.1         6.2        (50.0     64.7         105.0         (38.4

Other operating revenue

     13.7