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TECO Energy 10-Q 2009 Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
FORM 10-Q
For the quarterly period ended March 31, 2009 OR
For the transition period from to
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES x NO ¨ Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). YES ¨ 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 Apr. 24, 2009 was 212,877,953. As of Apr. 24, 2009, 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.
Index to Exhibits appears on page 54.
Table of ContentsPART I. FINANCIAL INFORMATION
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 Mar. 31, 2009 and Dec. 31, 2008, and the results of their operations and cash flows for the periods ended Mar. 31, 2009 and 2008. The results of operations for the three month period ended Mar. 31, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 and to the notes on pages 8 through 24 of this report. INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
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Table of ContentsConsolidated Condensed Balance Sheets Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsTECO ENERGY, INC. Consolidated Condensed Balance Sheets – continued Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsConsolidated Condensed Statements of Income Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsConsolidated Condensed Statements of Comprehensive Income Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsConsolidated Condensed Statements of Cash Flows Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsNOTES 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 variable interest entities for which it is the primary beneficiary (TECO Energy or the company). 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 subsidiaries as of Mar. 31, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Mar. 31, 2009 and 2008. The results of operations for the three month period ended Mar. 31, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year-end 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 Mar. 31, 2009 and Dec. 31, 2008, unbilled revenues of $48.2 million and $47.4 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Purchased Power Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $42.2 million for the three months ended Mar. 31, 2009, compared to $81.9 million for the three months ended Mar. 31, 2008. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses. Accounting for Franchise Fees and Gross Receipts The regulated utilities (Tampa Electric and Peoples Gas System (PGS)) are allowed to recover from customers certain costs incurred through rates 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. These amounts totaled $30.1 million for the three months ended Mar. 31, 2009, compared to $26.4 million for the three months ended Mar. 31, 2008. 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 totaled $30.0 million for the three months ended Mar. 31, 2009, compared to $26.2 million for the three months ended Mar. 31, 2008. 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 heating oil swaps which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operations section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.
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Table of Contents2. New Accounting Pronouncements Fair Value Measurements In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and non-financial liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial assets and liabilities and Jan. 1, 2009 for non-financial assets and liabilities. No adoption adjustment was necessary. Financial assets and liabilities of the company measured at fair value include derivatives and certain investments, for which fair values are primarily based on observable inputs. Non-financial assets and liabilities of the company measured at fair value include asset retirement obligations (AROs) when they are incurred and any long-lived assets or equity-method investments that are impaired in a currently reported period. In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4), FSP FAS 115-2 and FAS 124-2 , Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS124-2), and FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1) to address fair value valuation concerns in the current market environment. FSP FAS 157-4 affirms that when the market for an asset is not active, the objective of fair value is the price that would be received to sell the asset in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date in the inactive market. The determination of whether a transaction was not orderly should be based on the weight of the evidence. The FSP requires an entity to disclose a change in valuation technique and the related inputs resulting from the application of the FSP and to quantify its effects. Retrospective application is not permitted. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. This is not expected to materially affect the company’s results of operations, statement of position or cash flows. FSP FAS 115-2 and FAS 124-2 are applicable to debt securities and require that a company recognize the credit component of an other-than-temporary impairment in earnings and the remaining portion in other comprehensive income if management asserts it does not have the intent to sell the security and it is more likely than not it will not have to sell the security before recovery of its cost basis. It requires an entity to present separately in the financial statement where the components of other comprehensive income are reported, amounts recognized in accumulated other comprehensive income related to the noncredit portion of other-than-temporary impairments recognized for available-for-sale and held-to-maturity debt securities. Additionally, disclosure requirements are amended and will be required for interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009 and is not expected to materially affect the company’s results of operations, statement of position or cash flows. FSP FAS 107-1 and APB 28-1 require an entity to disclose fair value information, including methods and significant assumptions in measuring fair value, of financial instruments within the scope of FAS 107 in interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The new disclosure requirements of FSP FAS 107-1 and APB 28-1 will have no effect on the company’s results of operations, statement of position or cash flows. Employers’ Disclosures about Postretirement Benefit Plan Assets In December 2008, the FASB issued FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1). This FSP requires enhanced disclosures about plan assets of defined benefit pension plans or other postretirement plans, including the concentrations of risk in those plans. The guidance in FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. These additional required disclosures will have no effect on the company’s results of operations, statement of position or cash flows. Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities In June 2008, the FASB issued FSP No. Emerging Issues Task Force (EITF) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1). FSP EITF 03-6-1 requires that the two-class method earnings per share calculation include unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether the dividend or dividend equivalents are paid or not paid. The guidance in FSP EITF 03-6-1 is effective for fiscal years beginning after Dec. 15, 2008. The company adopted FSP EITF 03-6-1 effective Jan. 1, 2009 with no material impact to its results of operations, statement of position or cash flows.
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Table of ContentsDisclosures about Derivative Instruments and Hedging Activities In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 is significant to the company’s financial statement disclosures but has no effect on its results of operations, statement of position or cash flows. The company adopted FAS 161 effective Jan. 1, 2009. Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. These revisions are significant to its financial statement disclosures but have no effect on the company’s results of operations, statement of position or cash flows. 3. Regulatory As discussed in Note 1, Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with FERC’s regulations, TECO Energy is not subject to certain of the accounting, record-keeping and reporting requirements prescribed by FERC’s regulations under PUHCA 2005. Base Rates – Tampa Electric In order for Tampa Electric to continue meeting customers’ growing needs for reliable, efficient and affordable electric service, Tampa Electric filed with the FPSC for a base rate increase in August 2008. After an extensive review of the company’s request, on Mar. 17, 2009, the FPSC approved an ROE mid-point of 11.25% with a range of 10.25% to 12.25% and an increase to base rates and miscellaneous service charges of $104 million starting May 7, 2009. Additionally, the FPSC approved a revenue requirement step increase of $33.6 million effective Jan. 1, 2010 for capital additions placed in service in 2009 bringing the total approved revenue requirement amount to approximately $138 million. As part of its base rate increase, Tampa Electric also requested modifications to its cost of service methodology and rate design, which were also approved by the FPSC. The new base rates and service charges will remain in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. In addition to several base rate design changes, residential base rates and fuel charges will reflect a two-block structure which offers a lower rate for the first 1,000 kilowatt-hours of usage each month. Base Rates – PGS PGS’s current rates, which became effective in January 2003, were agreed to in a settlement with all parties involved prior to a full rate proceeding, and a final FPSC order was granted on Dec. 17, 2002. PGS’ authorized rates provide an allowed ROE range from 10.25% to 12.25% with an 11.25% midpoint. Recognizing the significant decline in ROE, PGS filed with the FPSC for a $3.7 million interim rate increase in August 2008. The FPSC approved an interim rate increase of $2.4 million effective Oct. 29, 2008. PGS also filed in August 2008, with the FPSC for a $26.5 million base rate increase. The major factors in the filing included a request for an ROE mid-point of 11.5%, 55% equity in the capital structure, and a rate base of $564 million. The formal hearings before the FPSC were held in March and the FPSC is scheduled to make its final decision on the requested increase in May, with final rates becoming effective in June 2009. Cost Recovery – Tampa Electric Tampa Electric’s fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred. In September 2008, Tampa Electric filed with the FPSC for approval of rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2009. In November 2008, the FPSC approved Tampa Electric’s requested rates. The rates included: 1) the 2009 projected costs for fuel and purchased power, including higher natural gas and coal prices, 2) the recovery of $132.9 million of under-recovered fuel and purchased power expenses in 2008 and 2007, 3) the over-recovery of $4.7 million of costs recovered through the Environmental Cost Recovery Clause (ECRC) for 2008 and 2007, and 4) the operating cost for and a return on the capital invested in the third selective catalytic reduction (SCR) project at the Big Bend Station as well as the operations and maintenance expense associated with the projects as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment. Rates in 2009 also reflect a two-block fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month.
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Table of ContentsOn Mar. 5, 2009, Tampa Electric filed a mid-course adjustment of its fuel and purchased power costs to reflect the significant decline in fuel commodity prices. Tampa Electric’s re-forecasted 2009 fuel and purchased power costs using actual costs for January and updated data for the balance of the year resulted in a decrease of projected fuel and purchased power costs of $190.8 million. Additionally, the FPSC approved Tampa Electric refunding the 2008 final true-up amount of $35.4 million as part of the mid-course adjustment. After, including the impacts of the rate case, Tampa Electric’s residential customer rate per 1,000 kilowatt-hours will decrease $14.38 from $128.44 to $114.06 starting on May 7, 2009. The FPSC determined in 2004 and 2005 that it was appropriate for Tampa Electric to recover SCR operating costs through the ECRC as well as earn a return on its SCR investment installed on Big Bend Units 1-4 for NOx control in compliance with the environmental consent decree. The SCRs for Big Bend Units 4 and 3 entered service in May 2007 and 2008, respectively, and cost recovery started in 2007 and 2008. The SCR for Big Bend Unit 2 is scheduled to enter service in May 2009 and recovery is included in the ECRC rates approved by the FPSC. The SCR for Big Bend Unit 1 is scheduled to enter service in May 2010 and cost recovery for the capital investment, which is dependent on a filing, is expected to start in 2010. Cost Recovery – PGS PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2008, the FPSC approved rates under PGS’ PGA for the period January 2009 through December 2009 for the recovery of the costs of natural gas purchased for its distribution customers. In addition to PGS’s base rates and purchased gas adjustment clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover its costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers. Other Items Storm Damage Cost Recovery Tampa Electric accrues $4.0 million annually to a FERC-authorized and FPSC-approved, self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $23.7 million and $22.7 million as of Mar. 31, 2009 and Dec. 31, 2008, respectively. In Tampa Electric’s base rate proceeding, the FPSC approved an increase in the annual storm damage accrual to $8.0 million effective May 2009. 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 treatment permitted by FAS 71, Accounting for the Effects of Certain Types of Regulation (FAS 71). 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.
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Table of ContentsDetails of the regulatory assets and liabilities as of Mar. 31, 2009 and Dec. 31, 2008 are presented in the following table: Regulatory Assets and Liabilities
All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods: Regulatory assets
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Table of Contents4. Income Taxes The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The Internal Revenue Service (IRS) concluded its examination of the company’s 2007 consolidated federal income tax return during 2008. The U.S. federal statute of limitations remains open for the year 2008 and onward. Year 2008 is currently under examination by the IRS under the Compliance Assurance Program, a program in which the company is a participant. The company does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2009. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from 3 to 5 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 2003 and forward. The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income in accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. During the three month periods ended Mar. 31, 2009 and Mar. 31, 2008, the company recorded $0.3 million and $0.2 million, respectively, of pre-tax charges for interest only. No amounts have been recorded for penalties for the three month periods ended Mar. 31, 2009 and Mar. 31, 2008. During the three month periods ended Mar. 31, 2009 and Mar. 31, 2008, the company experienced events that have impacted the overall effective tax rate on continuing operations. These events included depletion and the sale of a foreign subsidiary (see Note 13). 5. Employee Postretirement Benefits Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company.
For the fiscal 2009 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 6.05% for pension benefits under its qualified pension plan as of its Jan. 1, 2009 measurement date, and a discount rate of 6.05% for its SERP and other postretirement benefits as of their Jan. 1, 2009 measurement date. For the three month period ended Mar. 31, 2009, the pension plan trust experienced a net loss on its invested assets. For the three months ended Mar. 31, 2009, TECO Energy and its subsidiaries reclassed $0.5 million of unamortized transition obligation, prior service cost and actuarial gains and losses from accumulated other comprehensive income to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2009, Tampa Electric Company reclassed $2.0 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.
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Table of Contents6. Short-Term Debt At Mar. 31, 2009 and Dec. 31, 2008, the following credit facilities and related borrowings existed:
These credit facilities require commitment fees ranging from 9.0 to 125.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2009 and Dec. 31, 2008 was 1.22% and 2.65%, respectively.
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Table of Contents7. Other Comprehensive Income TECO Energy reported the following other comprehensive income (OCI) for the three months ended Mar. 31, 2009 and 2008, related to changes in the fair value of cash flow hedges, amortization of unrecognized benefit costs associated with the company’s pension plans and unrecognized gains and losses on available-for-sale securities:
8. Earnings Per Share In accordance with FSP EITF 03-6-1, TECO Energy adopted the two-class method for computing earnings per share (EPS) in the first quarter of 2009. FSP EITF 03-6-1 defines share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method described in FAS 128¸ Earnings Per Share (FAS 128). FSP EITF 03-6-1 requires retrospective application for all prior periods presented. The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.
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9. 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 SFAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition. Superfund and Former Manufactured Gas Plant Sites Tampa Electric Company, through its Tampa Electric and PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2009, Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.4 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices. The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy. 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 and changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.
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Table of ContentsGuarantees and Letters of Credit A summary of the face amount or maximum theoretical obligation under TECO Energy’s and Tampa Electric Company’s letters of credit and guarantees as of Mar. 31, 2009 is as follows:
Financial Covenants In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance and Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2009, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants. 10. 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 SFAS No. 131, 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.
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Table of Contents11. 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:
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 provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, SFAS 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities, and SFAS 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (FAS 161). 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. FAS 161 became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, FAS 161 requires qualitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. The company adopted FAS 161 effective Jan. 1, 2009. The company applies FAS 71 for financial instruments used to hedge the purchase of natural gas for our regulated companies. The provisions of FAS 71, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect 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 normal purchase/normal sale (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 Mar. 31, 2009, 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 Mar. 31, 2009 and Dec. 31, 2008:
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The following table presents the derivative hedges of heating oil contracts at Mar. 31, 2009 and Dec. 31, 2008 to limit the exposure to changes in the market price for diesel fuel:
The following table presents the derivative hedges of natural gas contracts at Mar. 31, 2009 and Dec. 31, 2008 to limit the exposure to changes in market price for natural gas used to produce energy, natural gas purchased for resale to customers and natural gas used as a component price for explosives purchased:
The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Mar. 31, 2009 is a net loss of $22.6 million after tax and accumulated amortization. This compares to a net loss of $25.1 million in AOCI after tax and accumulated amortization at Dec. 31, 2008. The following table presents the fair values and locations of derivative instruments recorded in the balance sheet at Mar. 31, 2009:
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Table of ContentsThe following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the balance sheet as of Mar. 31, 2009:
Based on the fair value of the instruments at Mar. 31, 2009, net pretax losses of $154.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. The following table presents the effect of hedging instruments on OCI and income for the quarter ended Mar. 31, 2009:
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 Mar. 31, 2009, all hedges were effective.
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Table of ContentsThe following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the quarter ended Mar. 31, 2009:
The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2011 for both financial natural gas and financial heating oil fuel contracts. The following table presents the company’s derivative volumes by commodity type that are expected to settle each year at Mar. 31, 2009:
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 Mar. 31, 2009, approximately 99.9% of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies while the remaining 0.1% are either rated below investment grade or are not rated by 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) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - 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 our counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standing, 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 their 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. Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where Tampa Electric Company is the counterparty, Tampa Electric Company’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including Tampa Electric
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Table of ContentsCompany’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 Mar. 31, 2009:
12. Fair Value Measurements Determination of Fair Value The company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines. When available, the company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2. If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable. Items Measured at Fair Value on a Recurring Basis The following table sets 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 Mar. 31, 2009. As required by FAS 157, 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 heating oil swaps, the market approach was used in determining fair value. For other investments, the income approach was used. Recurring Fair Value Measures
Natural gas and heating oil swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these swaps are the New York Mercantile Exchange (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.
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Table of ContentsThe primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate is used to determine the stream of cash flows over the life of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. A $2.7 million liability, primarily in interest rate swaps, is held on the books of unconsolidated affiliates of TECO Guatemala, but is reflected in “Investment in unconsolidated affiliates” on the TECO Energy, Inc. Consolidated Condensed Balance Sheets. Other investments reflect two auction rate securities, backed by pools of student loans, with a combined par value of $15.0 million. As a result of auction failures and the lack of an alternative active market, the valuation technique for these securities is an income approach using a discounted cash flow model and is considered Level 3 within FAS 157’s three tier fair value hierarchy. The model assumes a continuation of failed auctions and interest payments at the default rate. Cash flows are discounted at a rate reflecting current market spreads for similarly rated maturities. The valuation is sensitive to the discount rate used; a 100 basis point increase in the discount rate results in a $0.8 million decrease in value. Based on the protracted disruption of the market for these securities and the uncertain potential for its recovery, the company no longer expects to hold the securities indefinitely to recover the original value. Accordingly, the impairment was deemed other-than-temporary and recognized in “Other income” on the Consolidated Condensed Statement of Income for the first quarter. 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 and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Mar. 31, 2009, the fair value of derivatives was not materially affected by nonperformance risk. Net positions with substantially all counterparties were liability positions. Assets Measured at Fair Value on a Recurring Basis Using Unobservable Inputs (Level 3)
13. Mergers, Acquisitions and Dispositions Sale of Navega On Mar. 13, 2009, TECO Guatemala sold its 16.5% interest in the Central American fiber optic telecommunications provider Navega. The sale resulted in a pre-tax gain of $18.3 million and total proceeds of $29.0 million.
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Table of ContentsTAMPA 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 Tampa Electric Company as of Mar. 31, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Mar. 31, 2009 and 2008. The results of operations for the three months ended Mar. 31, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 and to the notes on pages 30 - 41 of this report. INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
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Table of ContentsConsolidated Condensed Balance Sheets Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsTAMPA ELECTRIC COMPANY Consolidated Condensed Balance Sheets – continued Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsConsolidated Condensed Statements of Income and Comprehensive Income Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsConsolidated Condensed Statements of Cash Flows Unaudited
The accompanying notes are an integral part of the consolidated condensed financial statements.
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Table of ContentsNOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS UNAUDITED 1. Summary of Significant Accounting Policies The significant accounting policies are as follows: Principles of Consolidation and Basis of Presentation Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS). 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 Tampa Electric Company and subsidiaries as of Mar. 31, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Mar. 31, 2009 and 2008. The results of operations for the three month period ended Mar. 31, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year-end 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 Mar. 31, 2009 and Dec. 31, 2008, unbilled revenues of $48.2 million and $47.4 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Purchased Power Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $42.2 million for the three months ended Mar. 31, 2009, compared to $81.9 million for the three months ended Mar. 31, 2008. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses. Accounting for Franchise Fees and Gross Receipts The regulated utilities (Tampa Electric and Peoples Gas System (PGS)) are allowed to recover from customers certain costs incurred through rates 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. These amounts totaled $30.1 million for the three months ended Mar. 31, 2009, compared to $26.4 million for the three months ended Mar. 31, 2008. 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 totaled $30.0 million for the three months ended Mar. 31, 2009, compared to $26.2 million for the three months ended Mar. 31, 2008. Cash Flows Related to Derivatives and Hedging Activities Tampa Electric Company 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 Fair Value Measurements In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FSP 157-2, which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and non-financial liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial
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Table of Contentsassets and liabilities and Jan. 1, 2009 for non-financial assets and liabilities. No adoption adjustment was necessary. Financial assets and liabilities of the company measured at fair value include derivatives and certain investments, for which fair values are primarily based on observable inputs. Non-financial assets and liabilities of the company measured at fair value include asset retirement obligations (AROs) when they are incurred. In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4), FSP FAS 115-2 and FAS 124-2 , Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS124-2), and FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1) to address fair value valuation concerns in the current market environment. FSP FAS 157-4 affirms that when the market for an asset is not active, the objective of fair value is the price that would be received to sell the asset in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date in the inactive market. The determination of whether a transaction was not orderly should be based on the weight of the evidence. The FSP requires an entity to disclose a change in valuation technique and the related inputs resulting from the application of the FSP and to quantify its effects. Retrospective application is not permitted. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. This is not expected to materially affect the company’s results of operations, statement of position or cash flows. FSP FAS 115-2 and FAS 124-2 are applicable to debt securities and require that a company recognize the credit component of an other-than-temporary impairment in earnings and the remaining portion in other comprehensive income if management asserts it does not have the intent to sell the security and it is more likely than not it will not have to sell the security before recovery of its cost basis. It requires an entity to present separately in the financial statement where the components of other comprehensive income are reported, amounts recognized in accumulated other comprehensive income related to the noncredit portion of other-than-temporary impairments recognized for available-for-sale and held-to-maturity debt securities. Additionally, disclosure requirements are amended and will be required for interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009 and is not expected to materially affect the company’s results of operations, statement of position or cash flows. FSP FAS 107-1 and APB 28-1 require an entity to disclose fair value information, including methods and significant assumptions in measuring fair value, of financial instruments within the scope of FAS 107 in interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The new disclosure requirements of FSP FAS 107-1 and APB 28-1 will have no effect on the company’s results of operations, statement of position or cash flows. Employers’ Disclosures about Postretirement Benefit Plan Assets In December 2008, the FASB issued FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1). This FSP requires enhanced disclosures about plan assets of defined benefit pension plans or other postretirement plans, including the concentrations of risk in those plans. The guidance in FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. These additional required disclosures will have no effect on the company’s results of operations, statement of position or cash flows. Disclosures about Derivative Instruments and Hedging Activities In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows, and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 is significant to the company’s financial statement disclosures but has no effect on its results of operations, statement of position or cash flows. The company adopted FAS 161 effective Jan. 1, 2009. Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. These revisions are significant to the company’s financial statement disclosures but have no effect on its results of operations, statement of position or cash flows. 3. Regulatory As discussed in Note 1, Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with FERC’s regulations, Tampa Electric is not subject to certain of the accounting, record-keeping and reporting requirements prescribed by FERC’s regulations under PUHCA 2005.
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Table of ContentsBase Rates – Tampa Electric In order for Tampa Electric to continue meeting customers’ growing needs for reliable, efficient and affordable electric service, Tampa Electric filed with the FPSC for a base rate increase in August 2008. After an extensive review of the company’s request, on Mar. 17, 2009, the FPSC approved an ROE mid-point of 11.25% with a range of 10.25% to 12.25% and an increase to base rates and miscellaneous service charges of $104 million starting May 7, 2009. Additionally, the FPSC approved a revenue requirement step increase of $33.6 million effective Jan. 1, 2010 for capital additions placed in service in 2009 bringing the total approved revenue requirement amount to approximately $138 million. As part of its base rate increase, Tampa Electric also requested modifications to its cost of service methodology and rate design, which were also approved by the FPSC. The new base rates and service charges will remain in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. In addition to several base rate design changes, residential base rates and fuel charges will reflect a two-block structure which offers a lower rate for the first 1,000 kilowatt-hours of usage each month. Base Rates – PGS PGS’ current rates, which became effective in January 2003, were agreed to in a settlement with all parties involved prior to a full rate proceeding, and a final FPSC order was granted on Dec. 17, 2002. PGS’ authorized rates provide an allowed ROE range from 10.25% to 12.25% with an 11.25% midpoint. Recognizing the significant decline in ROE, PGS filed with the FPSC for a $3.7 million interim rate increase in August 2008. The FPSC approved an interim rate increase of $2.4 million effective Oct. 29, 2008. PGS also filed in August 2008 with the FPSC for a $26.5 million base rate increase. The major factors in the filing included a request for an ROE mid-point of 11.5%, 55% equity in the capital structure, and a rate base of $564 million. The formal hearings before the FPSC were held in March and the FPSC is scheduled to make its final decision on the requested increase in May, with final rates becoming effective in June 2009. Cost Recovery – Tampa Electric Tampa Electric’s fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred. In September 2008, Tampa Electric filed with the FPSC for approval of rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2009. In November 2008, the FPSC approved Tampa Electric’s requested rates. The rates included: 1) the 2009 projected costs for fuel and purchased power, including higher natural gas and coal prices, 2) the recovery of $132.9 million of under-recovered fuel and purchased power expenses in 2008 and 2007, 3) the over-recovery of $4.7 million of costs recovered through the Environmental Cost Recovery Clause (ECRC) for 2008 and 2007, and 4) the operating cost for and a return on the capital invested in the third selective catalytic reduction (SCR) project at the Big Bend Station as well as the operations and maintenance expense associated with the projects as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment. Rates in 2009 also reflect a two-block fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month. On Mar. 5, 2009, Tampa Electric filed a mid-course adjustment of its fuel and purchased power costs to reflect the significant decline in fuel commodity prices. Tampa Electric’s re-forecasted 2009 fuel and purchased power costs using actual costs for January and updated data for the balance of the year resulted in a decrease of projected fuel and purchased power costs of $190.8 million. Additionally, the FPSC approved Tampa Electric refunding the 2008 final true-up amount of $35.4 million as part of the mid-course adjustment. After, including the impacts of the rate case, Tampa Electric’s residential customer rate per 1,000 kilowatt-hours will decrease $14.38 from $128.44 to $114.06 starting on May 7, 2009. The FPSC determined in 2004 and 2005 that it was appropriate for Tampa Electric to recover SCR operating costs through the ECRC as well as earn a return on its SCR investment installed on Big Bend Units 1-4 for NOx control in compliance with the environmental consent decree. The SCRs for Big Bend Units 4 and 3 entered service in May 2007 and 2008, respectively, and cost recovery started in 2007 and 2008. The SCR for Big Bend Unit 2 is scheduled to enter service in May 2009 and recovery is included in the ECRC rates approved by the FPSC. The SCR for Big Bend Unit 1 is scheduled to enter service in May 2010 and cost recovery for the capital investment, which is dependent on a filing, is expected to start in 2010. Cost Recovery – PGS PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2008, the FPSC approved rates under PGS’ PGA for the period January 2009 through December 2009 for the recovery of the costs of natural gas purchased for its distribution customers.
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Table of ContentsIn addition to PGS’s base rates and purchased gas adjustment clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover its costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers. Other Items Storm Damage Cost Recovery Tampa Electric accrues $4.0 million annually to a FERC-authorized and FPSC-approved, self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $23.7 million and $22.7 million as of Mar. 31, 2009 and Dec. 31 2008, respectively. In Tampa Electric’s base rate proceeding, the FPSC approved an increase in the annual storm damage accrual to $8.0 million effective May 2009. 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 treatment permitted by FAS 71, Accounting for the Effects of Certain Types of Regulation (FAS 71). 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.
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Table of ContentsDetails of the regulatory assets and liabilities as of Mar. 31, 2009 and Dec. 31, 2008 are presented in the following table: Regulatory Assets and Liabilities
All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods: Regulatory assets
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Table of Contents4. Income Taxes Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the three months ended Mar. 31, 2009 and 2008 differ from the statutory rate principally due to state income taxes, equity portion of AFUDC, amortization of investment tax credits and the domestic activity production deduction. The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax return for the year 2007 during 2008. The U.S. federal statute of limitations remains open for the year 2008 and onward. Year 2008 is currently under examination by the IRS under the Compliance Assurance Program, a program in which TECO Energy is a participant. 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 2009. 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 jurisdictions include 2005 and onward. The company does not currently have any uncertain tax positions and does not anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease by the end of 2009. 5. Employee Postretirement Benefits Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Other than the remeasurement of the Supplemental Executive Retirement Plan (SERP) plan obligations at Jan. 1, 2008 for certain participant retirements and the impacts of the termination of TECO Transport employees’ participation in these plans as a result of the sale of TECO Transport in December 2007, no significant changes have been made to these benefit plans since Dec. 31, 2003. 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. Tampa Electric Company’s portion of the net pension expense for the three months ended Mar. 31, 2009 and 2008, respectively, was $3.4 million and $2.1 million for pension benefits, and $3.4 million and $3.5 million for other postretirement benefits. Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2008, Tampa Electric Company reclassed $2.0 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income. For the fiscal 2009 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 6.05% for pension benefits under its qualified pension plan as of its Jan. 1, 2009 measurement date, and a discount rate of 6.05% for its SERP and other postretirement benefits as of their Jan. 1, 2009 measurement date. For the three month period ended Mar. 31, 2009, the pension plan trust experienced a net loss on its invested assets. 6. Short-Term Debt At Mar. 31, 2009 and Dec. 31, 2008, the following credit facilities and related borrowings existed: Credit Facilities
These credit facilities require commitment fees ranging from 9.0 to 125.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2009 and Dec. 31, 2008 was 1.25% and 2.13%, respectively.
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Table of Contents7. Commitments and Contingencies Legal Contingencies From time to time Tampa Electric Company 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 FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition. Superfund and Former Manufactured Gas Plant Sites Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (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 Mar. 31, 2009, Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.4 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices. The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy. 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 and changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings. Guarantees and Letters of Credit At Mar. 31, 2009, Tampa Electric Company was not obligated under guarantees, but had $1.4 million of letters of credit outstanding. Letters of Credit -Tampa Electric Company
At Mar. 31, 2009, TECO Energy had provided a $20.0 million fuel purchase guarantee and a $0.3 million letter of credit on behalf of Tampa Electric Company. Financial Covenants In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2009, Tampa Electric Company was in compliance with applicable financial covenants.
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Table of Contents8. Segment Information
9. Accounting for Derivative Instruments and Hedging Activities From time to time, Tampa Electric Company enters into futures, forwards, swaps and option contracts for the following purposes:
Tampa Electric Company uses derivatives only to reduce normal operating and market risks, not for speculative purposes. Tampa Electric 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 Tampa Electric Company 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. Tampa Electric Company applies the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activity, SFAS 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities, and SFAS 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (FAS 161). 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 other comprehensive income (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. FAS 161 became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, FAS 161 requires qualitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. Tampa Electric Company adopted FAS 161 effective Jan. 1, 2009. Tampa Electric Company applies FAS 71 for financial instruments used to hedge the purchase of natural gas for the regulated companies. The provisions of FAS 71, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (See Note 3).
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Table of ContentsA company’s physical contracts qualify for the normal purchase/normal sale (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 Mar. 31, 2009, all of Tampa Electric Company’s physical contracts qualify for the NPNS exception. The following table presents the derivative hedges of natural gas contracts at Mar. 31, 2009 and Dec. 31, 2008 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:
The ending balance in accumulated other comprehensive income (AOCI) related to previously settled interest rate swaps at Mar. 31, 2009 is a net loss of $6.6 million after tax and accumulated amortization. This compares to a net loss of $6.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2008. The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the balance sheet as of Mar. 31, 2009:
Based on the fair value of the instruments at Mar. 31, 2009, net pretax losses of $154.2 million are expected to be reclassified from regulatory assets to the Consolidated Statements of Income within the next twelve months.
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Table of ContentsThe following table presents the effect of hedging instruments on OCI and income for the quarter ended Mar. 31, 2009:
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 Mar. 31, 2009, 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 2011 for the financial natural gas contracts. The following table presents the company’s derivative volumes by commodity type that are expected to settle each year at Mar. 31, 2009:
Tampa Electric 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 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 exposure 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 Mar. 31, 2009, approximately 99.9% of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies while the remaining 0.1% are either rated below investment grade or are not rated by rating agencies. Tampa Electric Company assesses credit risk internally for counterparties that are not rated. Tampa Electric 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) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. Tampa Electric Company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination. Tampa Electric Company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Tampa Electric Company monitors counterparties’ credit standing, 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 Tampa Electric 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, Tampa Electric Company considers general market conditions and the observable
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Table of Contentsfinancial 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. Certain of Tampa Electric Company’s derivative instruments contain provisions that require Tampa Electric Company’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. Tampa Electric 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 Tampa Electric Company’s derivative activity at Mar. 31, 2009:
10. Fair Value Measurements Determination of Fair Value Tampa Electric Company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines. When available, Tampa Electric Company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2. If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable. Items Measured at Fair Value on a Recurring Basis The following table sets 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 Mar. 31, 2009. As required by FAS 157, 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 all assets and liabilities presented below the market approach was used in determining fair value. Recurring Derivative Fair Value Measures
Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the New York Mercantile Exchange (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.
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Table of ContentsTampa Electric Company considered the impact of nonperformance risk in determining the fair value of derivatives. Tampa Electric Company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which we transact have experienced dislocation. At Mar. 31, 2009, the fair value of derivatives was not materially affected by nonperformance risk. Tampa Electric Company’s net positions with substantially all counterparties were liability positions. 11. Other Comprehensive Income
Accumulated Other Comprehensive Loss
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This Management’s Discussion and 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 Form 10-Q, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities, including the decision by the Florida Public Service Commission regarding new base rates at Peoples Gas System scheduled for May; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; access to capital and credit markets when required in the current unsettled economic conditions; 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; 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 price and operating cost changes affecting the production levels and margins at TECO Coal, fuel cost recoveries and cash at Tampa Electric and natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; the ability to increase the amount of power generated by the San Josè Power Station during a period of lower oil prices; and the ultimate outcome of efforts to revise the significantly lower EEGSA VAD tariff rates implemented by regulatory authorities in Guatemala effective Aug. 1, 2008 affecting TECO Guatemala’s results. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2008. Earnings Summary - Unaudited
Operating Results Three Months Ended Mar. 31, 2009: TECO Energy, Inc. reported first-quarter net income of $34.7 million or $0.16 per share, compared to $30.8 million, or $0.15 per share, in the first quarter of 2008. First-quarter 2009 net income included an $8.7 million net gain on the sale of TECO Guatemala’s 16.5% interest in the Central American fiber optic telecommunications provider Navega, and a $3.6 million valuation adjustment to student loan securities held at TECO Energy parent. First-quarter 2008 net income included a $0.6 million charge for adjustments to previously estimated costs associated with the sale of TECO Transport. Operating Company Results All amounts included in the operating company and “Other and Eliminations” discussions are after-tax, unless otherwise noted. Tampa Electric Company – Electric division (Tampa Electric) Tampa Electric reported net income for the first quarter of $18.3 million, compared with $15.9 million for the same period in 2008. Results for the quarter reflected slightly higher retail energy sales, a 0.2% lower average number of customers, and higher operations and maintenance expenses. Net income included $3.3 million of Allowance for Funds Used During Construction (AFUDC) - equity, which represents allowed equity cost capitalized to construction costs, related to the installation of nitrogen oxide pollution control equipment and combustion turbines for peak loads, compared with $1.3 million in the 2008 period. Sales to other utilities declined 23% from the 2008 period, reflecting lower demand and lower natural gas prices.
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Table of ContentsIn the first quarter of 2009, there was no reduction in net income due to the waterborne transportation disallowance for the transporation of solid fuel, compared to a $1.6 million reduction in the 2008 period. In November 2008, the Florida Public Service Commission (FPSC)-approved Tampa Electric’s fuel adjustment filing, which included full recovery of waterborne transportation costs under new contracts effective Jan. 1, 2009. This approval eliminates the annual reduction in net income that occurred in 2004 through 2008 during the previous transportation contract. Total retail energy sales increased 0.1%, driven primarily by higher sales to weather-sensitive residential customers partially offset by lower sales to commercial and non-phosphate industrial customers. Sales to the residential customer segment increased 6.2% in the first quarter primarily due to colder winter weather patterns. Total degree days in Tampa Electric’s service area were 3% above normal and 14% above the first quarter 2008. Pretax base revenues increased $4.8 million in the quarter primarily due to the colder winter weather; other operating income was essentially unchanged from the 2008 period, as higher earnings on the new selective catalytic reduction equipment through the environmental cost recovery clause and increased by-product sales were offset primarily by lower off-system sales of electricity. Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, increased $2.9 million. The increase included $0.8 million related to maintenance on power generating equipment, $0.3 million higher bad-debt expense, $1.0 million of higher employee benefit related costs, primarily pension, and $0.6 million higher distribution system maintenance expense. Compared to the first quarter of 2008, depreciation expense increased $1.7 million, reflecting additions to facilities to serve customers. Interest expense at Tampa Electric decreased slightly due to lower interest on tax-exempt debt remarketed in March 2008, which more than offset the impact of higher long-term debt balances outstanding, and interest income decreased due to lower under-recovered fuel balances on which interest is accrued. On Mar. 17, 2009 the FPSC made a final determination of the revenue requirements in Tampa Electric’s base revenue increase filing. The total annual revenue increase in 2010 is approximately $138 million, consisting of two components. The first component is the 2009 annual base revenue increase of approximately $104 million, with new rates effective May 7, 2009. Tampa Electric will benefit from almost eight months of the new base rates in 2009, with a full-year benefit in 2010. The second component is a step increase effective in January 2010 of approximately $34 million to reflect the revenue requirements associated with combustion turbines to serve peak load requirements and rail unloading facilities to provide bimodal fuel delivery capability that are currently under construction and expected to be in service by year-end 2009. This second step increase is subject to two conditions: 1) the facilities being in service by year-end 2009, and 2) a prudence review as to whether the combustion turbines are required to serve customer load. The revenue requirements for 2009 and 2010 reflect a mid-point return on equity (ROE) of 11.25%. The allowed equity in the capital structure is 53.94% from all financial sources of capital (and 46.04% including other regulatory sources of capital such as deferred taxes and customer deposits) on an allowed rate base of $3.4 billion. The allowed ROE also applies to other regulatory calculations such as AFUDC and the allowed return on investments recovered through the Environmental Cost Recovery Clause. As part of its base rate increase Tampa Electric also requested modifications to its cost of service methodology and rate design, which were also approved by the FPSC. Based on the approved 2009 revenue requirements the FPSC voted on Apr. 7, 2009 to approve the resulting base rates and service charges, effective May 7, 2009. The new base rates and service charges will remain in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.
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Table of ContentsA summary of Tampa Electric’s operating statistics for the three months ended Mar. 31, 2009 and 2008 follows:
Tampa Electric Company – Natural gas division (PGS) Peoples Gas reported net income of $11.2 million for the first quarter, compared to $10.0 million in the same period in 2008. Quarterly results reflect a 0.2% lower average number of customers, increased sales to residential and commercial customers due to colder winter weather, and higher base rates due to an interim rate increase of $2.4 million (annual) granted in October 2008. Gas transported for power generation customers increased over the first quarter of 2008, when volumes were reduced due to mild weather and the use of other fuels for power generation. Non-fuel operations and maintenance expense increased, primarily due to higher spending on pipeline integrity inspections partially offset by lower medical claims costs. Results also reflect higher depreciation expense due to routine plant additions. A summary of PGS’ regulated operating statistics for the three months ended Mar. 31, 2009 and 2008 follows: Tampa Electric Company – Natural gas division (PGS)
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