UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

For the quarterly period ended March 31, 2015

OR

For the transition period from                      to                     

 

 

 

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.     YES  x    NO  ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).     YES  x    NO  ¨

Indicate by check mark whether TECO Energy, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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.

 

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of April 24, 2015 was 235,121,846. As of April 24, 2015, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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.

 

 

 

 

 

 

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DEFINITIONS

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

 

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PART I. FINANCIAL INFORMATION

 

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

 

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

 

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 TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

 

 

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

 

 

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

 

 

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

 

 

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

 

 

 

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TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

 

 

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

 

 

 

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

 

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Mar. 31, 2015 and 2014. The results of operations for the three months ended Mar. 31, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015.

The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Mar. 31, 2015. In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly related to TECO Coal (see Note 15).

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

Revenues

As of Mar. 31, 2015 and Dec. 31, 2014, unbilled revenues of $63.8 million and $86.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.4 million and $27.2 million for the three months ended Mar. 31, 2015 and 2014, respectively.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

 

2. New Accounting Pronouncements

Revenue from Contracts with Customers

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

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. This guidance is effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented.

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3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

 

Regulatory Assets and Liabilities

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

Details of the regulatory assets and liabilities as of Mar. 31, 2015 and Dec. 31, 2014 are presented in the following table:

 

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

 

 

4. Income Taxes

The effective tax rate increased to 38.48% for the three months ended Mar. 31, 2015 from 37.55% for the same period in 2014.

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2011 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. 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 taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward.    

 

 

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 2015 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.256% for pension benefits under its qualified pension plan. For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.206%. Additionally, TECO Energy made contributions of $14.9 million and $16.0 million to its pension plan for the three months ended Mar. 31, 2015 and 2014, respectively.

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For the three months ended Mar. 31, 2015 and 2014, TECO Energy and its subsidiaries reclassified $0.8 million and $0.6 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2015 and 2014, the regulated companies reclassified $2.2 million and $2.5 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

 

Black Lung Liability

TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. TECO Coal applies the accounting guidance of ASC 715, Compensation – Retirement Benefits, and annual expense is recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially-computed liability for such benefits over the employee’s applicable term of service. At Mar. 31, 2015 and Dec. 31, 2014, TECO Coal had an actuarially-determined black lung liability of $24.8 million and $24.7 million, respectively. Expense related to the black lung liability recognized during the three months ended Mar. 31, 2015 and 2014 was not material.

As discussed in Note 15, TECO Coal was classified as an asset held for sale at Mar. 31, 2015. In accordance with ASC 715, an after-tax settlement charge of approximately $7.7 million related to the unfunded black lung obligations recorded in AOCI will be recognized as a loss from discontinued operations upon completion of the sale of TECO Coal, which is expected to occur in 2015.

 

 

6. Short-Term Debt

At Mar. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

 

 

At Mar. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2015 and Dec. 31, 2014 was 1.12% and 1.16%, respectively.  

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent.

 

7. Long-Term Debt

Fair Value of Long-Term Debt

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At Mar. 31, 2015, total long-term debt had a carrying amount of $3,627.7 million and an estimated fair market value of $4,035.8 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.  

 

Issuance of TECO Finance Floating Rate Notes due 2018

On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018, which are guaranteed by TECO Energy. See Note 16 for additional information.

 

 

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended Mar. 31, 2015 and 2014, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

 

 

 

 

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9. Earnings Per Share

 

 

 

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10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A thirty-six year old man died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and nineteen other defendants alleges, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death.

In September 2014, a man was electrocuted when allegedly two energized, downed primary conductors fell during a heavy storm, leading to his death. Plaintiff's wrongful death complaint against Tampa Electric alleged, among other things, negligence and code violations. In March 2015, Tampa Electric entered into a confidential settlement in connection with this matter.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

 

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”  

The two purported class action suits (three purported classes) were consolidated. The court dismissed the class actions in their entirety with prejudice in October 2014 and appeals from the dismissal were taken by the plaintiffs in November 2014 and are pending.  

Two lawsuits representing 18 insurance carriers have filed subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. These subrogation matters are pending and discovery is proceeding. NMGC anticipates filing motions to dismiss similar to those filed in the class actions.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

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

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On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

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

While the duration of the annulment proceedings is uncertain, a hearing is scheduled in October 2015 and the proceedings as a whole are expected to take approximately two years to conclude, with a decision by the ad hoc committee in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2015, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2015 is as follows:

 

 

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2015, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

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11. Segment Information

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

 

 

 

 

 

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12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 13). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Mar. 31, 2015, all of the company’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Mar. 31, 2015 and Dec. 31, 2014 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.3 million and $0 as of Mar. 31, 2015 and Dec. 31, 2014, respectively, and derivative liabilities totaled $40.8 million and $42.7 million as of Mar. 31, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2015, net pretax losses of $35.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

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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, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2015 and 2014 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in Interest expense for TEC and Income (loss) from discontinued operations for TECO Coal.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Mar. 31, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years:

 

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 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, 2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could 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.

 

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

 

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

 

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

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Level 3:  Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

 

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

 

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).  

 

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.     

 

 

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

Interest rate swaps are also OTC swap instruments. The income approach is used in determining the fair value of interest rate swaps and the primary pricing inputs are LIBOR swap rates. 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 fair value.

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Mar. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

14. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of

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available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $5.4 million and $5.9 million of capacity pursuant to PPAs for the three months ended Mar. 31, 2015 and 2014, respectively.

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

 

15. Discontinued Operations, Assets Held for Sale and Asset Impairments

TECO Coal

In September 2014, the Board of Directors of TECO Energy authorized management to enter into negotiations for the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014.

On Oct. 17, 2014, TECO Diversified entered into an SPA to sell all of its ownership interest in TECO Coal to Cambrian Coal Corporation (“Cambrian”). On Feb. 5, 2015, the SPA was amended to extend the closing date to Mar. 13, 2015 and modify the purchase price to $80 million, subject to working capital adjustments, plus contingent payments of up to $60 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. As a result, in 2014 the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value based on the binding offer less estimated costs to sell. On Mar. 12, 2015, the SPA was further amended to extend the closing date to Apr. 24, 2015. On Apr. 17, 2015, the SPA was amended again to further extend the closing date to June 5, 2015, in order to allow for Cambrian’s financing arrangements to be completed (see Note 16).  No additional asset impairments were recorded in the first quarter of 2015.

The SPA contains customary representations, warranties, covenants, and closing conditions, including the purchaser’s obtaining debt financing in order to pay a portion of the purchase prices. The SPA also contains indemnification provisions subject to specified limitations as to time and amount. In addition, the SPA, as amended, is subject to termination by either party if specified closing conditions are not met by June 5, 2015. After closing of the sale, TECO Energy will not have influence over operations of TECO Coal, therefore the contingent payments and indemnification provisions are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal.

 

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

 

TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and

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its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 10). The first quarter 2015 charges shown in the table below are legal costs associated with that claim.  Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

Combined Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

 

 

 

    

16. Subsequent Events

Issuance of TECO Finance Floating Rate Notes due 2018

On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018. The 2018 Notes will bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points, which is payable quarterly on Jan. 10, Apr. 10, July 10 and Oct. 10 of each year, beginning July 10, 2015. Interest on the 2018 Notes will be computed on the basis of the actual number of days elapsed over a 360-day year. The 2018 Notes will not be subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness. TECO Finance is a wholly owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance will use these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the redemption of $191 million of TECO Finance notes due in May 2015.  

Amendment to TECO Coal SPA

On Apr. 17, 2015, TECO Diversified entered into an amendment (the Amendment) to the SPA dated as of Oct. 17, 2014, as amended, with Cambrian. As disclosed in Note 15, the SPA related to the sale of all of the ownership interest in TECO Coal to Cambrian, and was subject to termination by either party if specified closing conditions, including the purchaser’s obtaining financing in order to pay a portion of the purchase price, were not met by Apr. 24, 2015. The Amendment extends this date and provides that the SPA, as amended, is subject to termination by either party if the specified closing conditions are not met by June 5, 2015.

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

 

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

 

 

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 TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

 

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

 

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

 

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

 

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

 

1. Summary of Significant Accounting Policies

See TEC’s 2014 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

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

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31, 2015 and Dec. 31, 2014, and the results of operations and cash flows for the periods ended Mar. 31, 2015 and 2014. The results of operations for the three months ended Mar. 31, 2015 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2015.

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

Revenues

As of Mar. 31, 2015 and Dec. 31, 2014, unbilled revenues of $52.5 million and $49.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.4 million and $27.2 million for the three months ended Mar. 31, 2015 and 2014, respectively.

 

2. New Accounting Pronouncements

Revenue from Contracts with Customers

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

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. This guidance is effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented.

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3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

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

Details of the regulatory assets and liabilities as of Mar. 31, 2015 and Dec. 31, 2014 are presented in the following table:

 

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

 

 

4. Income Taxes

 

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three months ended Mar. 31, 2015 and 2014 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2013 consolidated federal income tax return in January 2015. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2014 and 2015 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2015. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.

 

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Mar. 31, 2015 and 2014, respectively, was $2.6 million and $3.8 million for pension benefits, and $1.4 million and $2.6 million for other postretirement benefits.

For the fiscal 2015 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.256%. For the Jan. 1, 2015 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.206%. Additionally, TECO Energy made contributions of $14.9 million and $16.0 million to its pension plan in the three months ended Mar. 31, 2015 and 2014, respectively. TEC’s portion of the contributions was $11.0 million and $13.0 million, respectively.

Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2015 and 2014, TEC reclassified $1.9 million and $2.5 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

 

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6. Short-Term Debt

At Mar. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

 

At Mar. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2015 and Dec. 31, 2014 was 0.87% and 0.7%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent.

 

 

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,414.8 million. At Dec. 31, 2014, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

 

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A thirty-six year old man died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and nineteen other defendants alleges, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death.

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In September 2014, a man was electrocuted when allegedly two energized, downed primary conductors fell during a heavy storm, leading to his death. Plaintiff's wrongful death complaint against Tampa Electric alleged, among other things, negligence and code violations. In March 2015, Tampa Electric entered into a confidential settlement in connection with this matter.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2015, TEC has estimated its ultimate financial liability to be $33.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Mar. 31, 2015 is as follows:

 

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2015, TEC was in compliance with all applicable financial covenants.

 

 

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9. Segment Information

 

 

 

 

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 11). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Mar. 31, 2015, all of TEC’s physical contracts qualify for the NPNS exception.

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The derivatives that are designated as cash flow hedges at Mar. 31, 2015 and Dec. 31, 2014 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.3 million and $0 as of Mar. 31, 2015 and Dec. 31, 2014, respectively, and derivative liabilities totaled $40.8 million and $42.7 million as of Mar. 31, 2015 and Dec. 31, 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2015 and Dec. 31, 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2015, net pretax losses of $35.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2015 and Dec. 31, 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

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, 2015 and 2014, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2015 and 2014 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Mar. 31, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2015, are expected to settle during the 2015, 2016 and 2017 fiscal years:

 

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Mar. 31, 2015, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these

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provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

 

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

 

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

 

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3:  Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

 

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

 

(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).

  

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2015 and Dec. 31, 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  

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

Interest rate swaps are also OTC swap instruments. The income approach is used in determining the fair value of interest rate swaps and the primary pricing inputs are LIBOR swap rates. For each instrument, the projected forward swap rate is used to determine

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the stream of cash flows over the life of the contract. The cash flows are then discounted using a spot discount rate to determine fair value.

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Mar. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 

12. Other Comprehensive Income

 

 

 

 

 

13. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $5.4 million and $5.9 million of capacity pursuant to PPAs for the three months ended Mar. 31, 2015 and 2014, respectively.

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

 

 

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This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company's current expectations and assumptions, and the company does not undertake to update that information or any other  information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; the ability to successfully implement the integration plans for NMGC and generate the financial results to make the acquisition accretive; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices  affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or failures; the ability of the purchaser of TECO Coal to obtain suitable financing and for TECO Energy to successfully close the pending sale transaction, or otherwise exit the coal business. Additional information is contained under "Risk Factors" in TECO Energy, Inc.'s Annual Report on Form 10-K for the period ended Dec. 31, 2014.

 

 

Operating Results

Three Months Ended Mar. 31, 2015

TECO Energy, Inc. reported first-quarter 2015 net income of $58.0 million, or $0.25 per share, compared with $50.1 million, or $0.23 per share, in the first quarter of 2014. Net income from continuing operations was $63.8 million, or $0.27 per share, in the 2015 first quarter, compared with $48.4 million, or $0.22 per share, for the same period in 2014. Net income from continuing operations included $0.7 million of integration costs associated with the acquisition of NMGC.

As a result of the previously announced agreement to sell TECO Coal, those operations were classified as discontinued operations effective in the third quarter of 2014 (see Note 15 to the TECO Energy Consolidated Financial Statements and the Discontinued Operations section later in this MD&A).

Operating Company Results

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

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the first quarter of 2015 was $48.2 million, compared with $45.2 million for the same period in 2014. First-quarter results in 2015 reflect customer growth and higher energy sales due to warm March weather. Results reflected

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operations and maintenance expenses essentially unchanged from 2014 and higher interest expense from higher long-term debt balances.  First-quarter net income in 2015 included $3.8 million of AFUDC-equity, which represents allowed equity cost capitalized to construction costs, compared with $2.4 million in the 2014 quarter.

 

Total degree days in Tampa Electric's service area in the first quarter of 2015 were 6% above normal and 11% above the 2014 period, driven by much warmer than normal weather in March. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 1.4% in the first quarter of 2015 compared with the same period in 2014. Customer growth in the quarter was 1.7%.  In the 2015 period, pretax base revenues increased $3.8 million due to higher energy sales and the pro rata portion of $7.5 million of higher annual pretax base revenue effective November 2014. Sales to the weather-sensitive residential customers increased primarily from the warmer than normal March weather, while sales to non-phosphate industrial customers increased due to the improving economy. Sales to lower-margin industrial-phosphate customers were lower as self-generation by those customers increased. (The quarterly energy sales in the following table reflect the energy sales based on the timing of billing cycles, which can vary period to period.)

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was essentially unchanged from the 2014 quarter. These results reflect higher payroll costs offset by lower other benefit costs and lower costs to reliably serve customers and operate and maintain the system, due to cost efficiencies and the benefit of synergies from shared services among all three utilities. Depreciation and amortization expense increased approximately $0.5 million as higher depreciation on normal additions to facilities to reliably serve customers was partially offset by the reduction in depreciation expense associated with the retirement of assets that were either obsolete or no longer required to serve customers.

A summary of Tampa Electric’s regulated operating statistics for the three months ended Mar. 31, 2015 and 2014 follows:

 

Tampa Electric Company – Natural Gas Division

Peoples Gas System reported net income of $14.6 million for the first quarter, unchanged from 2014. Therm sales to the weather-sensitive residential customers increased as a result of average customer growth of 2.0% in the quarter and colder February winter weather, which more than offset mild March weather.  Sales to commercial and industrial customers increased as a result of the stronger Florida economy and conversions of vehicle fleets to compressed natural gas. Sales to power-generation customers increased due to higher utilization of gas-fired power generators versus coal-fired generation by a single customer. Non-fuel operations and maintenance expense was $0.8 million higher than the 2014 period, which included a $1.6 million benefit from the recovery of costs from a 2010 contractor damage incident.  Depreciation and amortization increased slightly due to normal additions to facilities to serve customers.

A summary of PGS’s regulated operating statistics for the three months ended Mar. 31, 2015 and 2014 follows:

 

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New Mexico Gas Company

NMGC reported first quarter net income of $13.9 million. First-quarter heating degree days in New Mexico were 9% below normal and 1% below 2014, reflecting one of the mildest winters in recent years.  First quarter 2015 customer growth was 0.6%. On a per-share basis, the NMGC acquisition was approximately $0.04 accretive to first-quarter results. Due to the seasonal nature of the local gas distribution business driven by the use of natural gas for heating in New Mexico, NMGC is expected to be dilutive to earnings in the second and third quarters, but accretive in the fourth quarter and for the full-year period.

A summary of NMGC’s regulated operating statistics for the three months ended Mar. 31, 2015 and 2014 follows:

 

(1)     Information presented for 2014 is for comparative purposes only, as this was before the date of acquisition (Sept. 2, 2014).

Discontinued Operations – TECO Coal

The first quarter 2015 loss in discontinued operations of $5.8 million consisted of the TECO Coal loss from operations and a favorable tax adjustment recorded in the Other (net) segment. The first-quarter loss from operations was driven by sales of 0.9 million tons, compared with 1.3 million tons sold in the same period in 2014. The lower tons reflect the harsh winter weather, which reduced production and caused rail service interruptions. In 2015, first-quarter results also reflect selling prices and costs associated with reductions in personnel and steps taken in advance of closing the sale of the company.

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Other (net)

The cost from continuing operations for Other (net) in the first quarter of 2015 was $12.9 million, compared with a cost of $11.4 million in the same period in 2014. Net income in 2015 included $0.7 million of costs associated with the integration of NMGC, compared with $2.1 million of NMGC-related costs in 2014. The costs in 2015 reflect $1.1 million of interest expense related to notes at NMGI, the parent of NMGC, and $1.0 million of interest expense previously allocated to TECO Coal.

The segment data in Note 11 to the TECO Energy Consolidated Condensed Financial Statements presents Other and Eliminations as separate segments. The discussion above nets the two segments.

2015 Guidance from Continuing Operations

TECO Energy is maintaining its previously provided 2015 earnings-per-share guidance from continuing operations, excluding charges or gains, in a range between $1.08 and $1.11 in 2015, driven by the factors discussed below.

Tampa Electric expects to earn in the upper half of its allowed Return on Equity (ROE) range of 9.25% to 11.25%, driven by $7.5 million of higher base revenues that were effective Nov. 1, 2014 as a result of its September 2013 rate case settlement agreement, average customer growth trends in line with those experienced in 2014, and higher AFUDC.  Retail energy sales to residential, commercial and non-phosphate industrial customers are expected to grow by almost 1.0%. Total retail sales are expected to be about 0.3% higher, as sales to lower-margin interruptible Industrial-Phosphate customers are expected to decline due to increased self-generation. These sales forecasts reflect the impact of improved lighting and appliance efficiency and customer energy conservation. Full-year operations and maintenance expenses are expected to be lower than 2014 as lower employee-related costs and the impact of synergies in Florida as a result of the NMGC integration more than offset higher costs to operate the system and reliably serve customers. Depreciation expense is expected to be higher due to normal additions to facilities to serve customers.

Peoples Gas expects to continue to earn in the upper half of its allowed ROE range of 9.75% to 11.75% from customer growth trends in line with those experienced in 2015, and continued interest from customers utilizing petroleum and other fuel sources to convert to natural gas.  Operations and maintenance expense and depreciation trends are expected to be similar to Tampa Electric.

NMGC expects 2015 customer growth of more than 0.5%, volume growth at about the same level, and lower operations and maintenance expense from integration synergies.  NMGC will credit $2.0 million to customer bills in the first 12 months post-closing and $4.0 million in each subsequent 12-month period until new base rates are established. NMGC is expected to be accretive to TECO Energy’s earnings per share in 2015.  

The forecasts for all utilities assume normal weather for the remainder of 2015.

Other (net) cost is expected to increase in 2015.  The benefit of refinancing the $191 million of TECO Finance 6.75% notes due in May 2015 with $250 million of floating rate notes completed in early April will more than offset the impact of no longer allocating interest expense to TECO Coal. The non-utility interest cost in 2015 will reflect a full year of interest on debt at NMGI.  

Discontinued operations will include the operating results for TECO Coal through the closing of the sale as well as the accounting for the completion of the sale.  

Environmental

Tampa Electric produces ash and other by-products, collectively known as CCRs. The CCRs produced at Big Bend include fly ash, FGD gypsum, boiler slag, bottom ash and economizer ash. The CCRs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, over 97% of all CCRs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products. The remaining 3% were either disposed of onsite or shipped offsite to nearby industrial waste landfills in Central Florida.

The U.S. EPA published its CCR rule in the Federal Register on April 17, starting a 90-day period for legal challenges. This publication finalizes a rule setting federal standards for how companies may dispose of CCRs. It is expected that the litigation could have a material impact on both the content and the timing of the implementation of the rules.  Accordingly, the outcome of this rule-making process and its impact on our businesses cannot be determined at this time. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, we cannot be assured that any increased costs associated with complying with those regulations will be eligible for such treatment.

Income Taxes

The provisions for income taxes from continuing operations for the three month periods ended Mar. 31, 2015 and 2014 were $39.9 million and $29.1 million, respectively. The provision for income taxes for the three months ended Mar. 31, 2015 was impacted by higher operating income.

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Liquidity and Capital Resources

The table below sets forth the Mar. 31, 2015 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

 

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2015, TECO Energy and its subsidiaries were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Mar. 31, 2015. Reference is made to the specific agreements and instruments for more details.

 

Significant Financial Covenants

 

 

 

Credit Ratings of Senior Unsecured Debt at Mar. 31, 2015

 

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On Oct. 27, 2014, S&P placed the issuer credit rating of TECO Energy and the senior unsecured debt rating of its subsidiaries, TECO Finance, TEC and NMGC on credit watch with positive implications, following the announcement of the agreement to sell TECO Coal.

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

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section of TECO Energy’s 2014 Annual Report on Form 10-K). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Fair Value Measurements

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying accounting standards for regulated operations, the changes in value of natural gas derivatives of Tampa Electric, PGS and NMGC are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

The valuation methods used to determine fair value are described in Notes 7 and 13 to the TECO Energy Consolidated Condensed Financial Statements. In addition, 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 the company transacts have experienced dislocation. At Mar. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets, goodwill, purchase accounting and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2014.

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Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 9% from Dec. 31, 2014 to Mar. 31, 2015. For natural gas, the company maintained a similar volume hedged as of Mar. 31, 2015 from Dec. 31, 2014.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three month period ended Mar. 31, 2015:

 

Change in Fair Value of Derivatives (millions)

 

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

 

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Mar. 31, 2015:

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

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TECO Energy, Inc.

On Sept. 2, 2014, TECO Energy completed the acquisition of the privately-held NMGI and its wholly owned subsidiary, NMGC. NMGI and NMGC’s business combined constitute 14.7% and 15.1% of total assets of TECO Energy at Mar. 31, 2015 and Dec. 31, 2014, respectively, and 17.2% of TECO Energy’s revenues for the three months ended Mar. 31, 2015. As permitted by SEC guidance for newly acquired businesses, because it was not possible to complete an effective assessment of the acquired companies’ controls by Mar. 31, 2015, TECO Energy’s management has excluded NMGI and NMGC from its evaluation of disclosure controls and procedures from the date of such acquisition through Mar. 31, 2015. TECO Energy’s management is in the process of reviewing the operations of NMGI and NMGC and implementing TECO Energy’s internal control structure over the acquired operations.

Tampa Electric Company

 

 

 

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PART II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

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

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Notes 10 and 8, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

 

 

The following table shows the number of shares of TECO Energy common stock deemed to have been repurchased by TECO Energy:

 

 

 

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

 

Exhibits - See index on pages 48 and 49.

 

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

 

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INDEX TO EXHIBITS

 

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