UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

For the quarterly period ended September 30, 2014

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 October 27, 2014 was 234,692,300. As of October 27, 2014, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

This combined Form 10-Q represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

 

 

 

 

 

Page 1 of 83

Index to Exhibits appears on pages 82-83

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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

 

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sept. 30, 2014 and Dec. 31, 2013, and the results of their operations and cash flows for the periods ended Sept. 30, 2014 and 2013. The results of operations for the three month and nine month periods ended Sept. 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 14 through 31 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

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

 

 

 

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 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 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for recently acquired NMGI and NMGC (see Note 16) are in alignment with TECO Energy, Inc.’s policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

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

The unaudited consolidated condensed financial statements include NMGI and NMGC as of the acquisition date of Sept. 2, 2014 (see Note 16). 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 Sept. 30, 2014 and Dec. 31, 2013, unbilled revenues of $61.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

Tampa Electric and PGS are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014, compared to $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013.

Cash Flows Related to Derivatives and Hedging Activities

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

Goodwill

Goodwill represents the excess of the purchase price over the value assigned to the net identifiable assets of businesses acquired.  Accounting guidance requires that the company perform impairment tests on its goodwill annually or at any time when events occur that could impact the value of the company’s goodwill. If an impairment test of goodwill shows that the carrying amount of the

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goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Statements of Operations.  The company added goodwill during the quarter resulting from the NMGC acquisition (see Note 16).  

 

 

 

2. New Accounting Pronouncements

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

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

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for the company beginning in 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.

Going Concern

In August 2014, the FASB issued guidance defining management’s responsibility to decide whether there is substantial doubt about an organization’s ability to continue as a going concern and the related footnote disclosures required. This guidance is effective for the company beginning in 2017. The company does not expect any significant impact from the adoption of this guidance on its financial statements.

 

3. Regulatory

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

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.

2011 NMGC Base Rate Case

In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately $34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on Jan. 31, 2012, revising, among other things, base rates for all service provided on or after Feb. 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately $21.5 million on a normalized annual basis. The monthly residential customer access fee increased from $9.59 to $11.50, with the remaining rate increase reflected in changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as part of the May 2014 Settlement and subsequent NMPRC order approving the TECO Energy acquisition of NMGC, the rates will be frozen at the approved 2012 levels until the end of 2017 as reported in Note 16.

 

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NMGC’s PGAC

Comparable to the PGS accounting for gas costs, NMGC’s cost of gas sold generally consists of (i) the amount paid to purchase the gas itself, (ii) variable pipeline transportation charges, (iii) fixed pipeline demand charges, (iv) storage charges, (v) commodity hedging costs and gains, and (vi) other related items. Virtually all of NMGC’s cost of gas sold is accounted for through an NMPRC-approved mechanism referred to as the PGAC. The PGAC is a ratemaking mechanism that allows for the adjustment of the gas commodity charge component of rates charged to gas sales service customers (referred to as the GCBF rate) to reflect monthly increases and decreases in NMGC’s cost of gas sold. Under this mechanism, gas sales service customers are charged a GCBF rate that allows NMGC to recoup its actual cost of gas sold to those customers on a near real-time basis. On a monthly basis, NMGC estimates its cost of gas for the next month (taking into consideration the expected cost of gas to be purchased for the next month, expected demand and any prior month under-recovery or over-recovery of NMGC’s cost of gas) and sets the GCBF rate to be used in the next month to recover those estimated costs. For any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in revenue collected through the PGAC. NMGC’s cost of gas sold is charged to customers with no mark-up and, therefore, NMGC does not earn any gross margin on the gas commodity charge component of customer bills. Despite the fact that NMGC does not earn any gross margin on the gas commodity charge component of customer bills, this portion of customer bills may generate significant increases or decreases in NMGC’s revenues, due to changes in the market price of natural gas.  

At any point in time, NMGC typically will be in either an under-recovery or over-recovery position with respect to its cost of gas.  An under-recovery or over-recovery occurs when there are differences between the cost of gas billed to customers through the PGAC and the actual cost of gas incurred by NMGC. The under-recovery or over-recovery is a cumulative continuous balance from month to month. An over-recovery of these costs is reflected in Regulatory Liabilities in the current liabilities section of the company’s Statements of Financial Position. An under-recovery of these costs is reflected in Regulatory Assets in the current assets section of the company’s Statements of Financial Position.  

NMGC also has regulatory authority to include a simple interest charge or credit, termed the PGAC Carrying Charge, in the PGAC and thus the GCBF rate, based upon the month-end balance of the PGAC under-recovery or over-recovery of NMGC’s cost of gas. PGAC Carrying Charges are reflected in Other Income in the company’s Statements of Operations.  

NMGC’s annual PGAC period runs from Sept. 1 to Aug. 31. NMGC’s objective is to complete each annual PGAC period with no significant under-recovery or over-recovery of its cost of gas. The NMPRC requires that NMGC file an independently-audited reconciliation of the PGAC period costs and recoveries, annually in December. Additionally, NMGC must file a PGAC Continuation Filing with the NMPRC every four years. The most recent PGAC Continuation Filing was submitted to the NMPRC in June 2012.  The purpose of the PGAC Continuation Filing is to establish that the continued use of the PGAC is reasonable and necessary. In January 2013, the NMPRC approved the PGAC Continuation Filing, which essentially allows for the continued use of the PGAC for another four years.

 

TEC Storm Damage Cost Recovery

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

 

Regulatory Assets and Liabilities

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

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; and the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year.

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

 

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

 

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4. Income Taxes

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

The effective tax rate decreased to 35.38% for the nine months ended Sept. 30, 2014 from 37.35% for the same period in 2013. The decrease in the effective tax rate is the result of a state consolidated tax adjustment related to the acquisition of NMGC in the third quarter of 2014.

 

 

5. Employee Postretirement Benefits

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

 

On Sept. 2, 2014, TECO Energy completed the purchase of NMGI, the holding company of NMGC. The employees of NMGC became participants of TECO Energy’s pension plan effective as of the closing date of the purchase; however, NMGC employees will remain in their current partially-funded other postretirement benefit plan. As such, remeasurements of TECO’s pension plan and NMGC’s other postretirement benefits plan were performed as of Sept. 2, 2014.

For the remeasurement of the pension plan, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.277% for pension benefits under its qualified pension plan. TECO Energy assumed an EROA of 5.75% and a discount rate of 4.282% for the Sept. 2, 2014 measurement of NMGC’s other postretirement benefits. For the Jan. 1, 2014 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 5.096%. Additionally, TECO Energy made contributions of $47.5 million to its pension plan for the nine months ended Sept. 30, 2014. Net pension expense presented above includes the effects of these items subsequent to Sept. 2, 2014.

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For the three and nine months ended Sept. 30, 2014, TECO Energy and its subsidiaries reclassed $0.7 million and $2.0 million pretax, respectively, of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and nine months ended Sept. 30, 2014, the regulated companies reclassed $2.7 million and $7.9 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 ACS 715 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 Sept. 30, 2014 and Dec. 31, 2013, TECO Coal had an actuarially-determined black lung liability of $27.8 million and $24.5 million, respectively. Expense related to the black lung liability recognized during the nine months ended Sept. 30, 2014 and 2013 was not material.

As discussed in Notes 15 and 18, TECO Coal was classified as an asset held for sale at Sept. 30, 2014. In accordance with ACS 715, an after-tax settlement charge of approximately $7 million related to the unfunded black lung obligations recorded in accumulated other comprehensive income will be recognized as a loss from discontinued operations upon completion of the sale of TECO Coal which is expected to occur in the fourth quarter of 2014.

 

 

6. Short-Term Debt

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

 

 

At Sept. 30, 2014, 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 Sept. 30, 2014 and Dec. 31, 2013 was 1.37% and 0.56%, respectively.  

Tampa Electric Company Accounts Receivable Facility

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

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LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

TECO Energy Credit Agreement Assigned to and Assumed by NMGC

As previously disclosed, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it was the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy had no rights or obligations to borrow under the NMGC Credit Agreement, which was entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, on Sept. 2, 2014, TECO Energy designated NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon (i) NMGC became the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy ceased to be a party to the NMGC Credit Agreement and any further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) allows NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows NMGC to borrow funds on a same-day basis under a Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) allows NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

TECO Energy and TECO Finance Bridge Facility

As previously disclosed, TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement (the Bridge Facility) on Jun. 24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders in the Bridge Facility. TECO Energy unconditionally guaranteed TECO Finance’s obligations under the Bridge Facility. In the third quarter of 2014, TECO Energy permanently financed the NMGC Acquisition with a combination of (i) a TECO Energy equity offering, (ii) the issuance of debt at NMGC and NMGI, (iii) cash on hand and (iv) short-term borrowings.  Upon closing of the acquisition on Sept. 2, 2014, the commitment under the Bridge Facility was permanently cancelled by TECO Energy and TECO Finance.

 

Amendment of TECO Energy/TECO Finance, Tampa Electric Company, and New Mexico Gas Company Bank Credit Facilities

On Sept. 30, 2014, TECO Energy amended its $200 million bank credit facility, entering into Amendment No. 2 to its Fourth Amended and Restated Credit Agreement dated as of Dec. 17, 2013, as previously amended, (the TECO Credit Facility) whereby TECO Energy continues as Guarantor and its wholly-owned subsidiary, TECO Finance, continues as Borrower. The amendment increases the total commitments under the TECO Credit Facility to $300 million, changed the swingline commitments, and reallocates commitments among the lenders.

On Sept. 30, 2014, TEC amended its $325 million bank credit facility, entering into Amendment No. 2 to its Fourth Amended and Restated Credit Agreement dated as of Dec. 17, 2013, as previously amended. The amendment changed the swingline commitments and reallocates commitments among the lenders.

On Sept. 30, 2014, NMGC amended its $125 million bank credit facility, entering into Amendment No. 2 to its Credit Agreement dated as of Dec. 17, 2013, as previously amended. The amendment changed the swingline commitments and reallocates commitments among the lenders.

 

 

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2014, total long-term debt had a carrying amount of $3,629.3 million and an estimated fair market value of $3,949.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.  

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Issuance of Tampa Electric Company 4.35% Notes due 2044

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

Issuance of New Mexico Gas Intermediate Series A Senior Unsecured 2.71% Notes due 2019

On Sept. 2, 2014, NMGI completed an offering of $50 million aggregate principal amount of 2.71% Series A Senior Unsecured Notes due July 30, 2019 (the NMGI Series A Notes). The NMGI Series A Notes were sold at 100% of par. The offering resulted in net proceeds to NMGI (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $49.3 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI Series A Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGI Series A Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the NMGI notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGI Series A Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.

Issuance of New Mexico Gas Intermediate Series B Senior Unsecured 3.64 % Notes due 2024

On Sept. 2, 2014, NMGI completed an offering of $150 million aggregate principal amount of 3.64% Series B Senior Unsecured Notes due July 30, 2024 (the NMGI Series B Notes). The NMGI Series B Notes were sold at 100% of par. The offering resulted in net proceeds to NMGI (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $149.1 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI Series B Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGI Series B Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the NMGI notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGI Series B Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.

Issuance of New Mexico Gas Company Senior Unsecured 3.54 % Notes due 2026

On Sept. 2, 2014, NMGC completed an offering of $70 million aggregate principal amount of 3.54% Senior Unsecured Notes due July 30, 2026 (the NMGC 2014 Notes). The NMGC 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGC (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $69.3 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGC may redeem all or any part of the NMGC 2014 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGC 2014 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.

Amendment of New Mexico Gas Company 4.87 % Notes due 2021

On Feb. 8, 2011, NMGC issued secured notes in an aggregate principal amount of $200 million (NMGC 2011 Notes), maturing Feb. 8, 2021. The NMGC 2011 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.  

On July 16, 2014, NMGC received approvals from the noteholders of the NMGC 2011 Notes to release the collateral securing the NMGC 2011 Notes by amending the existing note purchase agreement. The amendments to the note purchase agreement were subject to the approval of the NMPRC and on Oct. 22, 2014, NMGC received the required NMPRC approval of the amendments. On Oct. 30, 2014, the amendments became effective and the collateral securing the NMGC 2014 Notes was released (see Note 18).

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8. Other Comprehensive Income

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

 

 

 

 

 

 

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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. 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.

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. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

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

New Mexico Gas Company - February 2011 Gas Shortages, System Emergencies, Curtailments of Service, and Related Litigation

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. In September 2014, the court entered a final order dismissing the consolidated cases in their entirety with prejudice. A written order is pending. Plaintiffs have stated an intention to appeal. The period for appeal expires 30 days after the written order is signed, which is expected in October 2014.  

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.  

NMGC believes these claims in the pending actions described above in this item 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 claims.

Davis v. Tampa Electric Company, et. al.

Thirty six year old Scott Davis died from mesothelioma in March 2014. His estate and his family are suing Tampa Electric as a result.

Mr. Davis 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.  

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

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, Inc., against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from

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Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. Pursuant to ICSID’s rules and procedures, each party had 120 days after the date of the Award to file an application for its annulment.

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

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

While the duration of the annulment proceedings is uncertain, 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, 2014 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 Sept. 30, 2014, 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 prices.

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

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

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

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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 Sept. 30, 2014 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 Sept. 30, 2014, 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. All significant intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.

 

 

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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 company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

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

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

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC 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).

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

The NMPRC allows, and generally expects, NMGC to have a commodity hedging program in order to hedge against increases in natural gas prices. Each year, NMGC develops an annual gas hedging plan, reviews that plan with the Staff of the NMPRC and representatives of the Attorney General of the State of New Mexico, and includes certain aspects of that plan in a report on NMGC’s annual gas supply plan which is filed with the NMPRC. As discussed in Note 3 under the caption NMGC’s PGAC, unless there are program-related disallowances, all costs associated with NMGC’s commodity hedging program are recoverable from customers through the PGAC, and any income or savings associated with the commodity hedging program are credited to customers through the PGAC. The instruments NMGC uses in its commodity hedging program are generally limited to fixed-price gas purchase contracts and call options. The fixed-price gas purchase contracts into which NMGC enters to serve its gas sales service customers qualify for the normal purchase and sales exception discussed previously and, therefore, those contracts are not recognized at fair value in the company’s Consolidated Condensed Balance Sheet.  

NMGC enters into numerous natural gas call option contracts for hedging purposes during the winter heating season. These call options allow NMGC to hedge specific quantities of natural gas at specified prices during the period from December through February. The premiums NMGC pays to enter into these call options are deferred at the time of payment in the company’s Consolidated Condensed Balance Sheet. These call option premiums are amortized in equal monthly amounts through the PGAC over the period from October through March. Cash received by NMGC from call options at expiration is credited to customers through the PGAC in the month in which the call options expire. Unamortized call option premiums are generally recorded as derivative assets, but when there are mark-to-market losses associated with these derivative assets, a portion, or all, of derivative assets are reclassified to regulatory assets in the company’s Consolidated Condensed Balance Sheet due to the recoverability of the unamortized call option premiums through the PGAC. The mark-to-market losses are limited to the amount of unamortized call option premiums at any point in time due to the regulatory treatment given to NMGC’s natural gas call options.  

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

 

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

 

The following table presents the derivative hedges of diesel fuel contracts at Sept. 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal. All diesel fuel derivatives are expected to be settled prior to the closing of the sale of TECO Coal.

 

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

 

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at Sept. 30, 2014 is a net loss of $7.4 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at Sept. 30, 2014 and Dec. 31, 2013. All diesel fuel derivatives are expected to be settled prior to the closing on the sale of TECO Coal.

 

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

 

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Based on the fair value of the instruments at Sept. 30, 2014, net pretax losses of $3.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

The following table presents the effect of hedging instruments on OCI and income for the three and nine months ended Sept. 30. All diesel fuel derivatives are expected to be settled prior to the closing on the sale of TECO Coal.

 

 

 

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

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The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sept. 30. All diesel fuel derivatives are expected to be settled prior to the closing on the sale of TECO Coal.

 

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sept. 30, 2014, are expected to settle during the 2014, 2015 and 2016 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 diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

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

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

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

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major

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

 

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

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. At Sept. 30, 2014 and Dec. 31, 2013, the company did not have any financial assets or liabilities for which disclosures about fair value are required.  

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

 

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

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

 

14. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $8.1 million and $20.9 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2014, respectively, and $6.5 million and $16.4 million for the three and nine months ended Sept. 30, 2013, respectively.

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

 

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

TECO Coal Company

On Sept. 29, 2014, the Board of Directors of TECO Energy authorized management to enter into negotiations for the sale of TECO Coal. As a result, the TECO Coal segment was accounted for as an asset held for sale and discontinued operation at Sept. 30, 2014, which for the quarter includes TECO Coal’s operating results and a pretax $98.4 million impairment charge related to the held-for-sale TECO Coal assets. This charge represents the write down to TECO Coal’s implied fair value of the binding offer less estimated costs to sell. Although the offer is a binding offer, the fair value measurement is considered a Level 2 measurement since the market is not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis).  

As reported in Note 18, on Oct. 17, 2014, TECO Diversified entered into an SPA to sell all of its ownership interest in TECO Coal to Cambrian Coal Corporation for $120 million plus contingent payments of up to $50 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. The SPA also contains indemnification provisions subject to specified limitations as to time and amount. Closing on the sale is subject to the purchaser obtaining financing, and other normal closing

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conditions. After closing, TECO Energy will not have influence over operations of TECO Coal, therefore the contingent payments and indemnification provisions are not considered direct cash flows. The resulting sale price reflected in the SPA did not materially change from implied fair value of the binding offer.

  

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 have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

Combined Components of Discontinued Operations

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

 

 

 

 

 

 

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16. Acquisition of New Mexico Gas Intermediate

Description of Transaction

On Sept. 2, 2014, the company completed the acquisition contemplated by the SPA dated May 25, 2013 by and among the company, NMGI, and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI is the parent company of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments.

Description of NMGC

NMGC, with approximately 720 employees, serves more than 513,000 customers, predominately residential, in New Mexico with the majority located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company serves approximately 60 percent of the state’s population with customers in 23 of New Mexico’s 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines.

Strategic Rationale for Acquisition

Acquisition-Related Regulatory Matters

NMGC is a rate-regulated natural gas utility subject to the regulation of the NMPRC, including with respect to its rates, service standards, accounting, securities issuances, construction of major new transmission and distribution facilities and other matters affecting, directly or indirectly, the provision of natural gas sales and transportation services to NMGC’s customers.

In May 2014, TECO Energy reached a settlement with the New Mexico Industrial Energy Consumers (which represents large customers), the New Mexico Attorney General’s office (which represents the New Mexico residential and small business customers) and the U.S. Department of Energy. As part of this settlement of the application for approval of the acquisition by the NMPRC, TECO Energy agreed, among other things, to:

On Aug. 13, 2014, the NMPRC approved the acquisition with the conditions set forth in the settlement agreements described above. The transaction closed on Sept. 2, 2014.

Purchase Price

The total consideration in the acquisition was as follows:

 

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Purchase Price Allocation

The majority of NMGI’s assets acquired and liabilities assumed relate to deferred income taxes associated with its NOL. These were recorded in accordance with the applicable accounting guidance. Additionally, the company paid off the existing outstanding debt at NMGI and issued $200 million of new NMGI debt at closing. Since the refinancing took place at closing, face value approximated fair value.

The majority of NMGC’s operations are subject to the rate-setting authority of the FERC and NMPRC and are accounted for pursuant to U.S. GAAP, including the accounting guidance for regulated operations. Rate-setting and cost recovery provisions currently in place for NMGC’s regulated operations provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. Except for long-term debt, the ARO, derivatives, OPEB plans, and deferred taxes, fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any net adjustments related to these amounts. The difference between fair value and pre-merger carrying amounts for long-term debt, derivatives, and the OPEB plan for regulated operations were recorded as regulatory assets or liabilities.

The excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth, synergies and an improved risk profile. Goodwill resulting from the acquisition was allocated entirely to the NMGC segment. Goodwill of $146.1 million related to the formation of NMGC in 2009 is tax deductible. The incremental goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes will be recorded related to this portion of the goodwill.

The initial accounting for the acquisition of NMGI is not complete because the valuations necessary to assess the fair values of certain assets acquired and liabilities assumed are considered preliminary as a result of the short time period between the closing of the acquisition and the end of the quarter. The allocation of the purchase price may be modified up to one year from the date of the acquisition, as more information is obtained about the fair value of assets acquired and liabilities assumed; however, the company expects to finalize these amounts by the end of 2014. The significant assets and liabilities for which preliminary valuation amounts are recognized at Sept. 30, 2014 include the fair value of contingencies and intangible assets and liabilities. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and material changes could require the financial statements to be retroactively amended.

The preliminary purchase price allocation of the acquisition of NMGI and NMGC is as follows:

 

 

 

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Current Quarter and Year-to-Date Impact of Acquisition

The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2014 was an increase of $16.2 million. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the three months and nine months ended Sept. 30, 2014 was a decrease of $2.0 million.

Pro Forma Impact of the Acquisition

The following unaudited pro forma financial information reflects the consolidated results of operations of the company and reflects the amortization of purchase accounting adjustments assuming the acquisition had taken place on Jan. 1, 2013. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the company. This information is preliminary in nature and subject to change based on final purchase price adjustments.

Pro forma earnings presented below include adjustments related to non-recurring acquisition consummation, integration and other costs incurred by the company during the period. After-tax non-recurring acquisition consummation, integration and other costs incurred by the company were $0.9 million and $5.7 million, respectively, for the three and nine months ended Sept. 30, 2014, and $2.1 million and $3.9 million, respectively, for the three and nine months ended Sept. 30, 2013. The pro forma financial information also excludes potential future cost savings or non-recurring charges related to the acquisition.

 

Intangible Assets Recorded

 

 

Goodwill resulting from the acquisition was allocated entirely to the NMGC segment. The goodwill related to the formation of NMGC in 2009 in the amount of $146.1 million is tax deductible. The incremental goodwill recognized of $255.7 million is not deductible for income tax purposes, and as such, no deferred taxes will be recorded related to this portion of the goodwill.

Many of NMGC’s transmission and distribution facilities are located on lands that require the grant of rights-of-way or franchises (collectively, “ROW”) from non-tribal governmental entities, Native American Tribes and Pueblos, or private landowners. Historically, ROW costs have been recovered in rates charged to customers, and NMGC will continue to seek to recover ROW costs in future rates charged to customers. However, TECO Energy has agreed to freeze rates for NMGC’s customers until Dec. 31, 2017 as a condition to the acquisition.

The company’s intangible assets and liabilities acquired through the acquisition of NMGI included in its Consolidated Condensed Balance Sheets, along with the future estimated amortization, were as follows as of Sept. 30, 2014:

 

 

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Transaction and Integration Costs

The following after-tax transaction and integration charges were recognized in connection with the acquisition and are included in the TECO Energy Consolidated Statements of Operations for the nine months ended Sept. 30, 2014.

 

The company has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

In conjunction with the acquisition, in September 2014, TECO Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the severance plan began in the third quarter of 2014 and will continue through 2015. Substantially all cash payments under the plan are expected to be made by the end 2015 resulting in the substantial completion of the acquisition integration plan. As of Sept. 30, 2014, the obligations associated with the severance benefits costs are $2.2 million.

 

 

17. Common Stock

Public Offering of 15.5 million in Common Shares

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

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

The company used the net proceeds from the offering to fund, in part, the acquisition of NMGI and for general corporate purposes.

 

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18. Subsequent Events

Sale of TECO Coal Corporation

On Oct. 17, 2014, TECO Diversified entered into an SPA to sell all of its ownership interest in TECO Coal to Cambrian Coal Corporation for $120 million, subject to a working capital adjustment, plus contingent payments of up to $50 million that may be paid between 2015 and 2019 depending on specified coal benchmark prices. The SPA provides for TECO Coal to reorganize as a limited liability company prior to closing and for Cambrian Coal Corporation to acquire all of the membership interests in that limited liability company. Initial net proceeds from the sale (not including any contingent payments) are expected to be used to repay short-term debt of TECO Energy and for general corporate purposes.  

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 price. The SPA also contains indemnification provisions subject to specified limitations as to time and amount. In addition, the SPA is subject to termination by either party if specified closing conditions are not met by Dec. 31, 2014.

NMPRC Approval of Amendments to the New Mexico Gas Company 2011 Notes

On Feb. 8, 2011, NMGC issued secured notes in an aggregate principal amount of $200 million (NMGC 2011 Notes), maturing Feb. 8, 2021. The NMGC 2011 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933. On July 16, 2014, NMGC received approvals from the noteholders of the NMGC 2011 Notes to release the collateral securing the NMGC 2011 Notes by amending the existing note purchase agreement. The amendments to the note purchase agreement were subject to the approval of the NMPRC and on Oct. 22, 2014, NMGC received the required NMPRC approval of the amendments. On Oct. 30, 2014, the amendments became effective and the collateral securing the NMGC 2014 Notes was released.

 

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TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC and its subsidiaries as of Sept. 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended Sept. 30, 2014 and 2013. The results of operations for the three month and nine month periods ended Sept. 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 39 through 50 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

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

 

 

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

 

 

 

 

 

 

 

 

 

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

Principles of Consolidation and Basis of Presentation

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

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

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

Revenues

As of Sept. 30, 2014 and Dec. 31, 2013, unbilled revenues of $53.3 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $31.7 million and $86.7 million, respectively, for the three and nine months ended Sept. 30, 2014, compared to $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013.

Cash Flows Related to Derivatives and Hedging Activities

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

 

2. New Accounting Pronouncements

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

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

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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.

Going Concern

In August 2014, the FASB issued guidance defining management’s responsibility to decide whether there is substantial doubt about an organization’s ability to continue as a going concern and the related footnote disclosures required. This guidance is effective for TEC beginning in 2017. The company does not expect any significant impact from the adoption of this guidance on its financial statements.

 

3. Regulatory

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

Storm Damage Cost Recovery

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

 

Regulatory Assets and Liabilities

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

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

 

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

 

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

 

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4. Income Taxes

 

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

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2011 and forward.

 

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Sept. 30, 2014 and 2013, respectively, was $3.6 million and $5.4 million for pension benefits, and $2.6 million and $2.5 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2014 and 2013, respectively, was $11.3 million and $16.3 million for pension benefits, and $7.8 million and $7.5 million for other postretirement benefits.

Due to the acquisition of NMGI on Sept. 2, 2014, TECO Energy’s pension plan was remeasured effective that date. For the remeasurement, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.277%. For the Jan. 1, 2014 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 5.096%. Additionally, TECO Energy made contributions of $47.5 million to its pension plan in the nine months ended Sept. 30, 2014. TEC’s portion of the contributions was $38.2 million.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2014, TEC reclassed $2.6 million and $7.8 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

 

6. Short-Term Debt

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

 

At Sept. 30, 2014, 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 Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at Sept. 30, 2014.

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Tampa Electric Company Accounts Receivable Facility

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

On Sept. 30, 2014, TEC amended its $325 million bank credit facility, entering into Amendment No. 2 to its Fourth Amended and Restated Credit Agreement dated as of Dec. 17, 2013, as previously amended.  The amendment modifies the swingline commitments and reallocates commitments among the lenders.  

 

 

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2014, TEC’s total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,330.3 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

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

 

8. Commitments and Contingencies

Legal Contingencies

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

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. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

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

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Davis v. Tampa Electric Company, et. al.

Thirty six year old Scott Davis died from mesothelioma in March 2014.  His estate and his family are suing Tampa Electric as a result.

Mr. Davis 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.  

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

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 Sept. 30, 2014 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 prices.

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

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2014 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 Sept. 30, 2014, TEC was in compliance with all applicable financial covenants.

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9. Segment Information

 

 

 

 

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10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

 

The ending balance in AOCI related to previously settled interest rate swaps at Sept. 30, 2014 is a net loss of $7.3 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

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

 

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

 

Based on the fair value of the instruments at Sept. 30, 2014, net pretax losses of $3.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

 

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The following table presents the effect of hedging instruments on OCI and income for the three months and nine months ended Sept. 30:

 

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

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of Sept. 30, 2014, are expected to settle during the 2014, 2015 and 2016 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 Sept. 30, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

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

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potential impact of nonperformance risk to derivative positions. As of Sept. 30, 2014, substantially all positions with counterparties were net liabilities.

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

 

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. At Sept. 30, 2014 and Dec. 31, 2013, the company did not have any financial assets or liabilities for which disclosures about fair value are required.  

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

 

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

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

 

12. Other Comprehensive Income

 

 

 

 

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13. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $8.1 million and $20.9 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2014, respectively, and $6.5 million and $16.4 million for the three and nine months ended Sept. 30, 2013, respectively.

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

 

 

 

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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 energy sales at the utility companies; economic conditions, both national and international, affecting the Florida or New Mexico economy; 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; the ability of TECO Energy's subsidiaries to operate equipment without undue accidents, breakdowns or failures; and the ability of the purchasers of TECO Coal to obtain adequate financing, for other closing conditions to be satisfied or waived, and close the sale of TECO Coal.  Additional information is contained under "Risk Factors" in TECO Energy, Inc.'s Annual Report on Form 10-K for the period ended Dec. 31, 2013, and as updated in subsequent filings with the SEC.

 

 

New Mexico Gas Co. Acquisition

On Aug. 13, 2014, the New Mexico Public Regulation Commission unanimously approved TECO Energy’s acquisition of New Mexico Gas Co. (NMGC).  The transaction closed on Sept. 2, 2014.  NMGC is expected to deliver seasonally strong financial results for the remainder of 2014 and to be slightly accretive to TECO Energy’s earnings in 2014.  The acquisition is also expected to be accretive to TECO Energy’s full-year earnings in 2015.

With the addition of NMGC‘s more than 513,000 gas customers, TECO Energy utility subsidiaries now serve almost 870,000 regulated gas distribution customers in two states, and more than 1.5 million regulated electric and gas customers in Florida and New Mexico.

The transaction was financed through a combination of $292 million of TECO Energy equity, the assumption of $200 million of existing NMGC debt, the issuance of $270 million of private placement debt at NMGI and NMGC, cash on hand and short-term TECO Energy debt.  

 

Strategic rationale for the acquisition includes:

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Sale of TECO Coal

On Oct. 17, 2014, TECO Energy, Inc. announced that that it has signed an agreement to sell its coal mining subsidiary, TECO Coal and its subsidiaries, to Cambrian Coal Corporation, a member of the Booth Energy Group.  The total sales price of $170 million includes future contingent consideration of $50 million if certain coal benchmark prices reach certain levels over the next five years. The $120 million cash base purchase price is subject to post-closing adjustments.

The sale is expected to close by year end, subject to the purchasers obtaining financing, and other normal closing conditions.  TECO Energy expects to use sale proceeds to repay debt and for general corporate purposes.

As a result of the agreement TECO Coal has been classified as an asset held for sale and its operating results were reported as discontinued operations in the third quarter of 2014.  TECO Energy recorded a non-cash valuation adjustment of approximately $65 million, after tax, to the carrying value of TECO Coal to reflect the sales price. (See the Discontinued Operations section later in this MD&A.)

Operating Results

Three Months Ended Sept. 30, 2014

Third-quarter 2014 net income was $11.1 million, or $0.04 per share, compared with $62.8 million, or $0.29 per share, in the third quarter of 2013. Net income from continuing operations was $73.0 million, or $0.32 per share, in the 2014 third quarter, compared with $64.3 million, or $0.30 per share, for the same period in 2013. Earnings per share reflect approximately $0.02 of dilution from the issuance of 16.7 million shares of TECO Energy common stock early in the third quarter to finance the Sept. 2 acquisition of NMGC.

As a result of the previously announced agreement to sell TECO Coal, those operations have been classified as discontinued operations, which for the quarter include TECO Coal’s operating results, a $64.8 million after-tax impairment charge and consolidated tax adjustments.

Nine Months Ended Sept. 30, 2014

Year-to-date net income was $119.6 million, or $0.54 per share, compared with net income of $155.7 million, or $0.72 per share, in the 2013 period.  Net income from continuing operations was $179.0 million, or $0.81 per share, compared with $153.3 million, or $0.71 per share in the 2013 period.  Year-to-date earnings per share were reduced approximately $0.01 from the dilution discussed above.  These results include $5.7 million of NMGC acquisition and integration costs in 2014, compared with $3.9 million in the 2013 year-to-date period.

The year-to-date $59.4 million loss in discontinued operations includes the operating results from TECO Coal, the impairment charge and tax adjustments discussed above, and a $3.1 million benefit related to the favorable resolution of an indemnification provision associated with the 2012 sale of TECO Guatemala.

Operating Company Results

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

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Tampa Electric Company – Electric Division

Tampa Electric’s net income for the third quarter of 2014 was $79.7 million, compared with $68.7 million for the same period in 2013. Results for the quarter reflected the benefits of the rate case settlement effective Nov. 1, 2013, a 1.6% higher average number of customers, and higher energy sales due to customer growth and favorable summer weather patterns. Results also reflect $0.8 million lower earnings on assets recovered through the Environmental Cost Recovery Clause (ECRC) due to a lower current weighted average cost of capital, which includes the lower return on equity (ROE) from the 2013 rate case settlement. Results reflected higher operations and maintenance expenses, partially offset by lower depreciation expense. Third-quarter net income in 2014 included $2.9 million of Allowance for Funds Used During Construction (AFUDC) equity, which represents allowed equity cost capitalized to construction costs, compared with $1.8 million in the 2013 quarter.

Total degree days in Tampa Electric's service area in the third quarter of 2014 were essentially normal, and unchanged from the 2013 period. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 2.3% in the third quarter of 2014 compared with the same period in 2013, driven by customer growth and August weather that was warmer and drier than normal and 2013, partially offset by September weather that was cooler and wetter than normal. In the 2014 period, pretax base revenues were approximately $23.0 million higher than in 2013, including approximately $15 million of higher revenue as a result of the 2013 rate case settlement. (The quarterly energy sales shown in the following table reflect the energy sales based on the timing of billing cycles, which can vary period to period.) Sales to residential customers increased primarily from customer growth and the weather patterns discussed above. Sales to commercial and non-phosphate industrial customers increased due to the improving economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.  

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost-recovery clauses, was $2.8 million higher than in the 2013 quarter. These results reflect $1.8 million of higher cost to reliably serve customers and operate and maintain the system and $2.2 million higher employee-related costs, including the accrual of performance-based incentive compensation for all employees based on achievement of financial results. These higher costs were partially offset by a $1.2 million benefit from the elimination of the storm damage accrual as a result of the 2013 rate case settlement, and lower pension expense and lower self-insurance reserves. Depreciation and amortization expense decreased $0.3 million in 2014, primarily as a result of normal additions to facilities to reliably serve customers, more than offset by approximately $1.0 million of lower amortization on software due to the change in expected useful life for software included in the 2013 rate case settlement.  

Year-to-date net income was $187.1 million, compared with $151.1 million in the 2013 period, driven primarily by the benefits from the 2013 rate case settlement, 1.7% higher average number of customers, higher energy sales from customer growth, and more favorable weather and a stronger economy, partially offset by higher operations and maintenance and depreciation expenses, and $2.4 million lower earnings on assets recovered through the ECRC. Year-to-date net income in 2014 included $7.3 million of AFUDC equity, compared with $4.3 million in the 2013 period.

Year-to-date total degree days in Tampa Electric's service area were 2% below normal, and essentially unchanged from the prior year-to-date period. Pretax base revenue was almost $62 million higher than in 2013, including approximately $43 million of higher revenue as a result of the 2013 rate case settlement. In the 2014 year-to-date period, total net energy for load was 1.8% higher than the same period in 2013. Higher energy sales were driven by the same factors as the quarterly sales, and winter weather that was colder than in 2013.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $1.0 million in the 2014 year-to-date period reflecting the same factors as in the third quarter. Compared to the 2013 year-to-date period, depreciation and amortization expense increased $2.2 million, reflecting additions to facilities to serve customers, partially offset by approximately $3.0 million of lower amortization on software due to the change in expected useful life for software included in the 2013 rate case settlement.

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A summary of Tampa Electric’s regulated operating statistics for the three and nine months ended Sept. 30, 2014 and 2013 follows:

 

 

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Tampa Electric Company – Natural Gas Division

Peoples Gas System reported net income of $4.8 million for the third quarter, compared with $5.4 million in 2013.  Average customer growth was 1.9% in the quarter, and therm sales to commercial and industrial customers increased as a result of the stronger Florida economy. Third-quarter results in 2014 reflected almost $1.0 million higher non-fuel operations and maintenance expense driven by higher employee-related costs, including the accrual of performance-based incentive compensation for all employees based on achievement of financial results. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers, partially offset by a change in software amortization similar to Tampa Electric’s discussed above.  Sales to power-generation customers and off-system sales decreased due to two power generators not operating and new participants in the off-system sales market.

Peoples Gas reported net income of $26.9 million for the year-to-date period, compared with $27.1 million in the same period in 2013. Results reflect a 1.7% higher average number of customers and higher therm sales to residential and commercial customers due to more-normal winter weather and improving economic conditions. Sales to power generation customers and off-system sales decreased due to the same reasons as in the third quarter.  Non-fuel operations and maintenance expense increased $1.4 million compared to the 2013 period, driven by the same factors as in the third quarter partially offset by a first quarter of 2014 recovery of $1.6 million of costs incurred in connection with a 2010 outage incident.

 

A summary of PGS’s regulated operating statistics for the three and nine months ended Sept. 30, 2014 and 2013 follows:

 

 

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New Mexico Gas Company

NMGC reported a typical seasonal loss of $0.9 million for the month of September, which was the first month of operations as a TECO Energy company.  Compared to September 2013, customer growth was 0.5%, consisting primarily of residential customers.  September weather in New Mexico was slightly milder than normal.

A summary of NMGC’s regulated operating statistics for the three months ended Sept. 30, 2014, reflecting only TECO Energy’s ownership period in the month of September follows:

 

Discontinued Operations – TECO Coal

In September 2014, TECO Energy’s board of directors authorized management to negotiate an agreement to sell TECO Coal, which was signed in October. As a result of this action, TECO Coal was considered to be held for sale as of Sept. 30, 2014 and reported as discontinued operations. A $64.8 million after-tax impairment charge, including a $3.1 million valuation allowance for Kentucky tax benefits, was recorded for TECO Coal in the third quarter of 2014 and reported as a component of the loss from discontinued operations.

Third-quarter results from operations were net income of $0.1 million on sales of 1.3 million tons, compared with a loss of $1.4 million on 1.5 million tons sold in the same period in 2013. In 2014, third-quarter results reflect an average net per-ton selling price, excluding transportation allowances, of $79, almost $3 lower than in 2013. In the third quarter of 2014, the all-in total per-ton cost of sales was $79, compared with almost $84 in the 2013 period.

TECO Coal year-to-date results from operations in 2014 were a loss of $0.7 million on sales of 4.1 million tons, compared with net income of $2.3 million on 4.2 million tons sold in the 2013 period. The 2014 year-to-date average net per-ton selling price was almost $80, compared with almost $86 in 2013. The all-in total per-ton cost of sales was $81, compared with almost $86 in 2013.

Parent & other

The cost from continuing operations for Parent & other in the third quarter of 2014 was $10.6 million, compared with a cost of $9.8 million in the same period in 2013. The non-GAAP cost from continuing operations for Parent & other in 2014 was $9.7 million, compared with a cost of $7.7 million in 2013. Non-GAAP costs in 2014 excluded $0.9 million of costs, net of tax benefits, associated with the acquisition and integration of NMGC, compared with $2.1 million of NMGC-related costs in 2013. The $0.9 million of NMGC-related costs reflect transaction and integration charges of $8.0 million, and favorable consolidated tax adjustments of $7.1 million. Results in 2014 reflect $0.3 million of interest expense for September related to notes at New Mexico Gas Intermediate, the parent of NMGC, in September.  

The 2014 year-to-date cost from continuing operations was $34.1 million, compared with $24.9 million in the 2013 period. The non-GAAP cost from continuing operations for Parent & other was $28.4 million in 2014, which excludes $5.7 million of NMGC acquisition- and integration-related costs, compared with $21.0 million in 2013, which excluded $3.9 million of NMGC acquisition-related costs.  

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2014 Guidance from Continuing Operations

TECO Energy expects to deliver earnings from continuing operations, excluding non-GAAP charges or gains, in a range between $1.00 and $1.05 in 2014, driven by the factors discussed below.

Tampa Electric expects to earn in the upper half of its authorized allowed ROE range of 9.25% to 11.25%, driven by approximately $50 million of higher base revenues in 2014 as a result of its Sept. 2013 rate case settlement agreement. Based on year-to-date experience, it now expects slightly higher average customer growth of 1.6% and total retail energy sales growth about 0.5% lower than customer growth due to lower average customer usage. Operations and maintenance expenses are expected to be lower than 2013 actual amounts due to lower employee-related costs, lower storm-damage expense accruals and lower pension expense driven by higher discount rate assumptions, partially offset by increased expenses 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 above the middle of its allowed ROE range of 9.75% to 11.75% from moderate customer growth, in line with the trends experienced in 2013. It also expects to benefit from continued interest from customers utilizing petroleum and other fuel sources to convert to natural gas due to the attractive economics.

The expectations for both Tampa Electric and Peoples Gas assume normal weather for the remainder of 2014.

NMGC is expected to deliver seasonally strong financial results for the remainder of 2014 and to be slightly accretive to TECO Energy’s earnings in 2014.

Upon closing of the sale of TECO Coal, TECO Energy expects to record an additional adjustment to consolidated deferred taxes of approximately $13 million to $15 million. This non-recurring charge will be reflected in continuing operations. In addition, upon closing of the sale of TECO Coal, TECO Energy expects to record a charge of approximately $7.0 million related to certain liabilities in Discontinued Operations.  

Income Taxes

The provisions for income taxes from continuing operations for the nine-month periods ended Sept. 30, 2014 and 2013 were $98.0 million and $91.4 million, respectively. The provision for income taxes for the nine months ended Sept. 30, 2014 was increased due to TECO Energy’s higher pretax income offset by a favorable state consolidation tax adjustment related to the acquisition of NMGC in the third quarter of 2014.

Liquidity and Capital Resources

The table below sets forth the Sept. 30, 2014 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.

 

 

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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 Sept. 30, 2014, 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 Sept. 30, 2014. Reference is made to the specific agreements and instruments for more details.

 

Significant Financial Covenants

 

Credit Ratings of Senior Unsecured Debt at Sept. 30, 2014

 

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, Tampa Electric and NMGC on credit watch with positive implications, following the announcement of the agreement to sell TECO Coal.

On Jan. 30, 2014, Moody’s upgraded the credit ratings of TECO Energy, TECO Finance and TEC. TECO Energy and TECO Finance senior unsecured debt is rated Baa1, up from Baa2, and TEC’s senior unsecured debt is rated A2, up from A3, all with stable outlooks.

On May 30, 2013, Fitch placed the rating of TECO Energy, TECO Finance and TEC on ratings watch negative following the announcement of our agreement to purchase NMGC. On Oct. 9, 2013, Fitch removed TEC from ratings watch negative and affirmed its ratings. On Aug. 19, 2014, Fitch removed TECO Energy and TECO Finance from ratings watch negative and affirmed its ratings.

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

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

 

Financing of NMGC Acquisition

As previously disclosed, the purchase price for the acquisition of all the capital stock of NMGI, the parent company of NMGC (NMGC Acquisition), was $950 million including the assumption of $200 million of existing NMGC debt.

TECO Energy financed the NMGC Acquisition with $292 million of proceeds from its third quarter equity offering, the issuance of $200 million of debt at NMGI and $70 million of debt at NMGC (see Footnote 7, Long-Term Debt), primarily to replace existing debt, to fund the transaction, costs and expenses, and for general corporate purposes, cash on hand and short-term borrowings.

In July 2014, TECO Energy sold 15.5 million shares of its common stock in a follow-on public offering raising net proceeds of approximately $271 million.  TECO Energy sold the underwriters an additional 1.2 million shares in August 2014 and received approximately $21 million of net proceeds from the sale.

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.

Diesel fuel hedges are used to mitigate the fluctuations in the price of diesel fuel which is a significant component in the cost of coal production at TECO Coal and its subsidiaries.

The valuation methods used to determine fair value are described in Notes 7 and 13 to the TECO Energy, Inc. 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 Sept. 30, 2014, 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 and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013.

In connection with our acquisition of NMGC as discussed in Note 16 to the TECO Energy, Inc. Consolidated Condensed Financial Statements, at September 30, 2014 our consolidated balance sheet included $402 million of goodwill. We have identified NMGC as a separate segment and it is also a reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment. We expect that our future impairment testing of goodwill will be based largely on an income approach for valuation which estimates the discounted future cash flows of operations.  Some of the key quantitative assumptions that will be considered in our future valuations include regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. If negative changes occurred to one or more key assumptions, an impairment charge could result in the future. With the exception of the capital spending rate and regulatory rate design, the key assumptions noted are significantly determined by market factors. When we complete our first impairment assessment of the NMGC goodwill in the fourth quarter of 2014, we expect there to be very little, if any, difference between the determined fair value and the carrying value given the newness of this acquisition.

 

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Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the increase in the average market price component of the company’s outstanding natural gas swaps of approximately 3% from Dec. 31, 2013 to Sept. 30, 2014. For natural gas, the company maintained a similar volume hedged as of Sept. 30, 2014 from Dec. 31, 2013.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine month period ended Sept. 30, 2014:

 

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sept. 30, 2014:

 

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 14.5% of total assets of TECO Energy at Sept. 30, 2014, and 2.4% of TECO Energy’s revenues for the three months ended Sept. 30, 2014. As permitted by SEC guidance for newly acquired businesses, TECO Energy’s management elected to exclude NMGI and NMGC from its evaluation of disclosure controls and procedures and management’s report on changes in internal control over financial reporting in paragraph (b) below from the date of such acquisition through Sept. 30, 2014. 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

 

The following description of risk factors includes any material changes to, and supersedes the description of, risk factors associated with TECO Energy’s business, including the acquisition of NMGC, previously disclosed in Part I, Item 1A of TECO Energy’s 2013 Form 10-K under the heading “Risk Factors” and as updated in subsequent filings with the SEC. The business, financial condition and operating results of TECO Energy can be affected by a number of factors, whether currently known or unknown, including but not limited to those described below, any one or more of which could, directly or indirectly, cause TECO Energy’s actual results of operations and financial condition to vary materially from past, or from anticipated future, results of operations and financial condition. Any of these factors, in whole or in part, could materially and adversely affect TECO Energy’s business, financial condition, results of operations and common stock price.

The following discussion of risk factors contains forward-looking statements. These risk factors may be important to understanding any statement in this Form 10-Q or elsewhere. The following information should be read in conjunction with the condensed consolidated financial statements and related notes in Part I, Item 1, “Financial Statements” and Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q.

Risks Associated With the NMGC Acquisition

We will be subject to business uncertainties during the integration of NMGC that could adversely affect our business and operations.

Based on the completion of the permanent financing for the NMGC acquisition under favorable conditions and NMGC’s expected strong seasonal fourth quarter results, we expect NMGC to be accretive to earnings in the fourth quarter of 2014 and in calendar year 2015. The anticipated accretion to earnings from NMGC during this integration period is based on estimates of synergies from the transaction and growth in the New Mexico economy, which are dependent on local and global economic conditions and other factors, which may materially change, including:

Negative changes in these factors could have an adverse effect on the anticipated benefits of the transaction or our business, financial condition, results of operations or stock price.

We have incurred and will continue to incur significant integration costs in connection with the NMGC acquisition.

We incurred significant transaction costs in connection with the execution and consummation of the NMGC acquisition as well as the financing transactions in connection therewith. In addition, we are in the process of integrating NMGC into TECO Energy following the closing of the NMGC acquisition on Sept. 2, 2014. Although we anticipate achieving synergies in connection with the NMGC acquisition, we also expect to incur costs implementing such cost savings measures. In 2014, through Sept. 30, 2014, we have incurred transaction and integration costs in connection with the NMGC acquisition of approximately $5.7 million. We anticipate that we will incur certain additional non-recurring charges in connection with this integration, including charges associated with integrating process and systems. At this time, we cannot identify the timing, nature and amount of all such charges. Although we believe that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, will offset incremental transaction and integration-related costs over time, this net benefit may not be achieved in the near term, or at all. We have identified some, but not all, of the actions necessary to achieve our anticipated cost and operational savings. Accordingly, the cost and operational savings may not be achievable in our anticipated amount or timeframe or at all.

In order to finance the NMGC acquisition, we incurred additional indebtedness, which could have an adverse effect on our financial health.

We financed the NMGC acquisition with a combination of the proceeds from the July 2014 equity issuance, cash on hand and new debt at NMGC and NMGI, proceeds from which were primarily used to retire certain debt of NMGC and NMGI in connection with the closing of the NMGC acquisition, to fund the acquisition purchase, costs and expenses, and for general corporate purposes. The incurrence of this additional debt may have an adverse effect on our financial condition and may limit our ability to obtain

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financing in the future. Furthermore, the recently completed issuance of our common stock has resulted in additional shares outstanding and may have an adverse effect on the market price of our common stock.

NMGC’s business is subject to many risks, including those attendant to being a regulated gas utility. Some of these risks are similar to those of our existing gas utility, and some are unique to New Mexico; NMGC’s business may be adversely affected by these risks, and additional risks may be identified as we integrate NMGC into TECO Energy.

NMGC is a highly regulated gas utility which could be adversely affected by a number of factors affecting such a business, such as changes in regulation or legislation or decisions by the NMPRC and the impact of environmental laws and regulations that may increase costs or have other adverse effects on the business; the potential for increased costs in natural gas or volatility in such prices which could reduce sales volumes or have other adverse effects on the business; general economic conditions nationally and in New Mexico affecting the market for natural gas; the inability of the company to renew rights-of-way or franchises for its transmission and distribution facilities on acceptable terms, which could increase costs; and weather-related risks to the business, such as warmer-than-normal weather conditions, or other factors such as global warming or climate change, which may result in reduced natural gas sales and lower profitability. Additional risk factors relating to this business may be identified during the integration of NMGC into TECO Energy.

In connection with the NMGC acquisition, we recorded additional goodwill and long-lived assets that could become impaired and adversely impact our financial condition and results from operations.

We assess long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, we may be required to record non-cash impairment charges that could have a material impact on results from operations.

 

Risks Associated With TECO Coal

During the period of ownership prior to the completion of the sale of TECO Coal, we retain the risks of ownership of that business.

Any failure of the pending sale of TECO Coal or at all would likely alter certain aspects of our current business plans and could adversely affect our business and the value of TECO Coal.

On Oct. 17, 2014, TECO Diversified entered into a securities purchase agreement to sell all of its ownership interest in TECO Coal to Cambrian Coal Corp., subject to certain closing conditions, including the purchaser’s obtaining suitable financing, and entering into a specific coal supply agreement. In accordance with the terms of the securities purchase agreement, we expect to realize approximately $120 million in initial proceeds from the sale, plus contingent payments of up to $50 million over the next five years depending on specified coal benchmark prices. There can be no assurances that we will realize any additional proceeds from these potential contingent payments. The sale is expected to close by year-end 2014. If certain closing conditions are not met by Dec. 31, 2014, however, either party may choose not to proceed with the sale.

In anticipation of the pending sale transaction, we have presented the financial results of TECO Coal in this quarterly report as discontinued operations and included a charge of $64.8 million after-tax to write-down the carrying value of TECO Coal to the estimated fair value of the business as of Sept. 30, 2014. In addition, we have committed to a plan to dispose of TECO Coal if the closing conditions contained in the securities purchase agreement, including the financing condition, are satisfied. In the event that the TECO Coal sale transaction is not consummated on the terms contemplated by the securities purchase agreement or at all, certain aspects of our business could be adversely affected.

We previously forecast that TECO Coal results would be earnings breakeven in 2014 but cash flow positive in a weak coal market. The coal markets have continued to weaken in 2014 and it is unlikely that TECO Coal would have improved results in 2015. If the pending sale of TECO Coal is not consummated, TECO Coal’s potentially weaker 2015 financial results would have an adverse effect on TECO Energy’s consolidated financial results and potentially our stock price. In addition, if the sale is not consummated, the value of TECO Coal’s assets might be further impaired, and we may not be able to realize the expected proceeds in a subsequent sale transaction.

 

Below are additional risks associated with TECO Coal, which could impact our results in the event the sale is not completed.

Competition among coal producers in Central Appalachia and other producing regions, and low natural gas prices may adversely affect TECO Coal’s ability to sell steam coal. Low-cost natural gas has allowed utility steam coal users to switch from coal to natural gas to produce electricity, which has reduced the current market price and demand for TECO Coal’s steam coal from domestic utilities. If we continue to own TECO Coal, continued or further declines in natural gas prices and increased competition from lower cost producing areas would keep demand and selling prices low, which would reduce TECO Coal’s financial results, or further reduce the value of its reserves.

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TECO Coal has historically sold about 50% of its production to domestic utilities for use in the generation of power. For over three years, natural gas prices have been dramatically lower than previous averages due to the growth of hydraulic fracturing in the production of natural gas from shale formations. These low natural gas prices have caused utility coal users to switch to lower cost natural gas to generate electricity. Even with the increase in natural gas prices as occurred in the first half of 2014, it remains more cost effective for users of higher cost Central Appalachian coal, which TECO Coal produces, to burn a higher percentage of natural gas for power generation. Lower cost coals from other producing regions of the U.S., such as the Powder River Basin and the Illinois Basin are being utilized by more utilities in lieu of higher cost Central Appalachian coals, further reducing demand.

In the current coal markets, prices for Central Appalachian steam coal are not profitable. Without an increase in the cost of natural gas and an increase in the use of coal for power generation, or a general improvement in coal market conditions, TECO Coal could sign coal sales contracts at lower than break even prices or production could be reduced, and its financial results will be reduced. If these conditions were to persist or decline further, the value of TECO Coal’s reserves could be reduced, which could result in an additional non-cash impairment charge.

Failure to obtain the permits necessary to open new surface mines, or challenges to the validity of existing permits, could reduce earnings from TECO Coal.

Our surface coal mining operations are dependent on permits from the USACE to open new surface mines necessary to maintain or increase production. Since 2008, new permits issued by the USACE under Section 404 of the Clean Water Act for new surface coal mining operations have been challenged in court by various environmental groups, resulting in very few usable permits being issued. Failure to obtain the necessary permits to open new surface mines, which are required to maintain and expand production, could reduce production, cause higher mining costs or require purchasing coal at prices above our cost of production to fulfill contract requirements, which would reduce the earnings expected from TECO Coal.

Challenges to existing permits that disrupt mining operations could result in higher costs if operations are forced to move to other mining sites or if coal is purchased from third parties, which would reduce the earnings expected from TECO Coal.

In 2010, the EPA issued new guidelines related to water quality for Central Appalachian coal surface mining operations that would be conditions of new surface mine permits, which would add significant cost to operations or curtail our surface mining activities and preparation plant operations.

In 2010, the EPA issued new guidance on environmental permitting requirements for Central Appalachian mountaintop removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. In 2011, the EPA made this guidance final. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. In 2012, the United States District Court for the District of Columbia ruled that the EPA had exceeded its statutory authority in establishing the water quality guidance discussed above in the manner in which it was done. Following the outcome of this court decision, pending appeals by the EPA, few, if any, new usable permits have been issued by the USACE. Over time, if new permits are not issued, TECO Coal could incur higher production costs or reduced production from surface mining operations.

TECO Coal’s sales to international customers are subject to risks that could result in losses or increased costs.

TECO Coal is exposed to financial risk through its sales to international customers primarily in Asia. TECO Coal attempts to mitigate this risk through the use of third parties to broker the sales, dollar-denominated contracts, passage of title upon loading in the U.S. port, customer responsibility for the international freight, letters of credit posted by customers for purchase price of the commodity and the transportation to the U.S. port, and the utilization of local agents where appropriate. TECO Coal cannot be assured that these measures will effectively mitigate all international risks, which could have an adverse effect on TECO Coal’s financial conditions.

In 2014, TECO Coal had a higher percentage of its metallurgical coal sales committed to customers in Asia than in recent years, and expects to sell coal to these customers in 2015. Prices for metallurgical coal sales to Asia are subject to being reset on a quarterly basis based on supply and demand in the region. Over the past two years the quarterly prices have been lower due to increased supply from Australia and other suppliers and weakening demand for metallurgical coal from China. Quarterly prices in the second half of 2014 were below levels that made sales to these markets profitable. If these quarterly prices persist TECO Coal’s production and profitability levels could be reduced.

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

If the percentage depletion tax deduction is eliminated for TECO Coal, the effective tax rate for that company would rise from the historical 20% to 25% to the general corporate tax rate of 37%, which would reduce earnings from TECO Coal.

 

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Financing Risks

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

We have substantial indebtedness, which has resulted in fixed charges we are obligated to pay. The level of our indebtedness and restrictive covenants contained in our debt obligations could limit our ability to obtain additional financing.

TECO Energy, TECO Finance, TEC and NMGC must meet certain financial tests as defined in the applicable agreements to use their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. These restrictive covenants could further limit our ability to obtain additional financing.

As of Sept. 30, 2014, we were in compliance with required financial covenants, but we cannot be assured that we will be in compliance with these financial covenants in the future. Our failure to comply with any of these covenants or to meet our payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. We may not have sufficient working capital or liquidity to satisfy our debt obligations in the event of an acceleration of all or a portion of our outstanding obligations.

We also incur obligations in connection with the operations of our subsidiaries and affiliates that do not appear on our balance sheet. These obligations take the form of guarantees, letters of credit and contractual commitments, as described under the “Liquidity, and Capital Resources” section of the “Management’s Discussion & Analysis of Financial Condition & Results of Operations” section of this quarterly report.

Financial market conditions could limit our access to capital and increase our costs of borrowing or refinancing, or have other adverse effects on our results.

TECO Finance and Tampa Electric have debt maturing in 2015 and subsequent years which they may refinance. Future financial market conditions could limit our ability to raise the capital we need and could increase our interest costs, which could reduce earnings.

We enter into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable.

We enter into derivative transactions with counterparties, most of which are financial institutions, to hedge our exposure to commodity price changes. Turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which we have an in-the-money position, we could be unable to collect from such counterparty.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase our pension expense or the required cash contributions to maintain required levels of funding for our plan.

Under calculation requirements of the Pension Protection Act, as of the Jan. 1, 2014, measurement date, the funded percentage of our plan was essentially fully funded. TECO Energy estimates its contributions to range from $5 million to $45 million annually over the next five years. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund our plan in the future.

We estimate that pension expense in 2014 will be lower than in 2013, primarily due to the higher interest rates and pension plan asset growth in 2013. Any future declines in the financial markets or decreases in interest rates, however could, cause pension expense to increase in future years.

Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.

We are forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. We are forecasting capital expenditures at PGS to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe. Forecasted capital expenditures at NMGC will support customer and system reliability and expansion.

If our capital expenditures exceed the forecasted levels, we may need to draw on credit facilities or access the capital markets on unfavorable terms. We cannot be sure that we will be able to obtain additional financing, in which case our financial position could be adversely affected.

Our financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade, and we cannot be assured of any rating improvements in the future.

Our senior unsecured debt is rated as investment grade by S&P at BBB, by Moody’s Investor’s Services (Moody’s) at Baa1, and by Fitch Ratings (Fitch) at BBB. The senior unsecured debt of TEC is rated by S&P at BBB+, by Moody’s at A2 and by Fitch at A-.  The senior unsecured debt of NMGC is rated by S&P at BBB+. A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P and Fitch, and a three notch downgrade by Moody’s, may affect our ability to borrow,

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may change requirements for future collateral or margin postings, and may increase our financing costs, which may decrease our earnings. We may also experience greater interest expense than we may have otherwise if, in future periods, we replace maturing debt with new debt bearing higher interest rates due to any such downgrades. In addition, downgrades could adversely affect our relationships with customers and counterparties.

At current ratings, TEC and NMGC are able to purchase electricity and gas without providing collateral. If the ratings of TEC or NMGC decline to below investment grade, Tampa Electric, PGS or NMGC could be required to post collateral to support their purchases of electricity and gas.

We are a holding company with no business operations of our own and depend on cash flow from our subsidiaries to meet our obligations.

We are a holding company with no business operations of our own or material assets other than the stock of our subsidiaries. Accordingly, all of our operations are conducted by our subsidiaries. As a holding company, we require dividends and other payments from our subsidiaries to meet our cash requirements. If our subsidiaries are unable to pay us dividends or make other cash payments to us, we may be unable to pay dividends or satisfy our obligations.

 

General Business and Operational Risks

General economic conditions may adversely affect our businesses.

Our businesses are affected by general economic conditions. In particular, growth in Tampa Electric’s service area, in Florida and in New Mexico is important to the realization of annual energy sales growth for all of our regulated utilities.

Any weakening of economic conditions could adversely affect our utilities, expected performance and their ability to collect payments from customers.

TECO Coal is also affected by general economic conditions affecting primarily the utility and steel industries, both nationally and internationally. TECO Coal sells metallurgical coal domestically and internationally, and demand for that product has varied due to economic conditions. Continued economic weakness and the resulting lower demand for metallurgical coal in the international markets could reduce TECO Coal’s financial results.

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

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

If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, the earnings could be subject to review by the FPSC which could result in refunds to customers or changes in allowed returns on equity, which could reduce earnings and cash flow.

Changes in the environmental laws and regulations affecting our businesses could increase our costs or curtail our activities.

Our businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on us or require us to curtail some of our businesses’ activities.

Proposed new regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.

In response to a coal ash pond failure in December 2008 at another utility, the EPA proposed new regulations for the management and disposal of CCRs. These proposed rules include two potential approaches. One approach, known as Subtitle C, would categorize CCRs destined for disposal as hazardous wastes. This proposal could be the most significant for Tampa Electric because management and disposal of hazardous wastes is extremely expensive, and waste landfills are currently prohibited in Florida by state law. In addition, the hazardous designation could require improvements to Tampa Electric’s current ash management practices and interim storage and handling facilities for CCRs inside its power stations, even though permanent onsite disposal would not be allowed. The other proposed rule would set minimum standards for the final disposal of CCRs under regulations similar to those in place for municipal non-hazardous solid waste. This proposal would not be as disruptive as the former, since it would allow for the continued operation of ash impoundments on Tampa Electric’s facilities. However it is unclear whether this approach would place additional management requirements on these existing disposal units or cause them to need structural improvements. The EPA’s current schedule would result in a final proposed rule in 2015, although expected litigation would likely delay the rule’s effective date.

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Federal or state regulation of GHG emissions, depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions. While GHG emission regulations have been proposed, both at the federal and state level, none has been passed at this time and, therefore, costs to reduce GHGs are unknown. Presently there is no viable technology to remove CO ₂ post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units. New rules requiring post-combustion CO ₂ removal could require significant investment in what is essentially experimental technology, costly conversion to natural gas fuel, or a premature shut-down of the units, which would result in non-cash write-offs.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but we cannot be assured that the FPSC would grant such recovery.

In a June 25, 2013, memorandum, President Obama directed the EPA to issue new emissions standards for future power plants as well as modified, reconstructed or existing power plants to reduce GHG emissions. The new standards for future power plants were released in the fall of 2013, which essentially mandate that no new coal fired power plants will be constructed in the U.S. On June 2, 2014, the EPA released a comprehensive proposed rule which it calls the “Clean Power Plan,” aiming to cut GHG emissions from existing power plants by 30% from their 2005 levels by 2030, with an interim goal for the period from 2020 through 2029. Under the proposed rule, each state would have to reduce carbon dioxide emissions on a state-wide basis by an amount specified by the EPA; the target amount was determined by the EPA’s view of each state’s options, including: making power plant efficiency upgrades; shifting from coal to natural gas generation; investing in zero- and low-emitting power sources, such as renewable and nuclear energy; and implementing customer energy efficiency programs. Because the 30% reduction target is an average across all states, some states have higher or lower target emission reduction goals under the proposed rule than the average. Based on current emissions, Florida has a higher reduction goal than the average, of 38%. Under the proposed rules, states will have flexibility in designing programs to meet their emission reduction targets, including the four approaches noted above or any other measures they choose to adopt, for example, carbon tax and cap-and-trade. The EPA is scheduled to finalize the rule by June 1, 2015, and states will have until June 30, 2016, to submit plans to implement the finalized rule (subject to extension and EPA approval of the states’ plans). It is unclear whether Florida’s proposed implementation plan will take into consideration emission reductions achieved prior to 2005 or if that baseline year will be changed in the comment process. The 2005 baseline year does not take into consideration the significant reductions in greenhouse gas emissions we achieved prior to 2005 (a reduction of approximately five million tons since 1998). If the 2005 baseline year remains unchanged (which due to our previous reductions in greenhouse gas emissions was our lowest emitting year), it may be more difficult for us to achieve the proposed reductions than other utilities in a cost-effective manner, especially when compared to utilities in other states that have lower emission reduction targets under the proposed rules. It is expected that the rules will be subjected to litigation, which could have a material impact on both the timing and substance of the rules, and, therefore, the outcome of this rule-making process and its impact on our businesses cannot be determined at this time; however, it could result in increased operating costs, decreased operations at Tampa Electric’s coal-fired plants, and decreased profitability at our coal mining and production subsidiary. 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.

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

Among other rules, the EPA has proposed or finalized a number of new rules, including the CAIR/CSAPR and Hazardous Air Pollutants (“HAPS”) Maximum Achievable Control Technology (“MACT”) for emissions into the air, and a number of new rules focused on water use and discharges from power generation facilities.

Together these air-focused rules impose stringent reductions in several pollutants from electric utility steam generators, primarily coal-fired, but including oil-fired as well. If the CSAPR rule is implemented as planned, the EPA has estimated that the implementation of CSAPR would require significant investment in pollution-control equipment for units not already equipped or could result in the retirement of primarily smaller, older coal-fired power stations that do not currently have state-of-the-art air pollution-control equipment already installed. The retirement of these units or switching to other fuels for compliance with this rule is likely to reduce overall demand for coal, which could reduce sales and financial results at TECO Coal.

The EPA’s water-focused rules could limit the supply of water available to our power generating facilities, require the investment of significant capital for new equipment and increase operating costs.

 

 

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A mandatory RPS could add to Tampa Electric’s costs and adversely affect its operating results.

In past sessions of the Florida legislature, an RPS was debated but ultimately not enacted, but an RPS standard could be enacted in the future. In addition, there is the potential that legislation could be proposed in the U.S. Congress to introduce an RPS at the federal level. It remains unclear, however, if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS. Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers through the ECRC.

Tampa Electric, the state of Florida and the nation as a whole are increasingly dependent on natural gas to generate electricity. There may not be adequate infrastructure to deliver adequate quantities of natural gas to meet the expected future demand, and the expected higher demand for natural gas may lead to increasing costs for the commodity.

In Florida and across the United States, utilities are increasingly relying on natural gas for new electric generating plants in response to GHG emissions concerns and attractive natural gas prices. Currently, there is an adequate supply and infrastructure to meet demand for natural gas in Florida and nationally. However, if future supplies are inadequate or if significant new investment is required to install the pipelines necessary to transport the gas, the cost of natural gas could rise. Currently, our electric and gas utilities are allowed to pass the cost for the commodity gas and transportation services through to customers without profit. Changes in regulations could reduce earnings if they required our electric and gas utilities to bear a portion of the increased cost. In addition, increased costs to customers could result in lower sales.

Our businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.

All of our businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by our electric and gas utilities are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS and NMGC, which have a typically short but significant winter peak periods that are dependent on cold weather, are more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can negatively impact results at Tampa Electric and PGS.

NMGC earns all of its positive net income in the first and fourth quarters due to winter weather. Mild winter weather in New Mexico would reduce NMGC’s expected earnings and adversely impact TECO Energy’s earnings.

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

The state of Florida is exposed to extreme weather, including hurricanes, which can cause damage to our facilities and affect our ability to serve customers.

As a company with electric service and natural gas operations in peninsular Florida, we are exposed to extreme weather events, such as hurricanes. Extreme weather conditions can be destructive, causing outages and property damage that require us to incur additional expenses. Extensive customer outages could reduce revenue collections. If warmer temperatures lead to changes in extreme weather events (increased frequency, duration and severity), these expenses could be greater.

While we have storm preparation and recovery plans in place, and Tampa Electric and PGS have historically been granted regulatory approval to recover or defer the majority of significant storm costs incurred, extreme weather still poses risks to our operations and storm cost-recovery petitions may not always be granted or may not be granted in a timely manner. If costs associated with future severe weather events cannot be recovered in a timely manner, or in an amount sufficient to cover actual costs, our financial condition and operating results could be adversely affected.

Commodity price changes may affect the operating costs and competitive positions of our utility businesses.

All of our businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS and NMGC, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of PGS and NMGC relative to electricity, other forms of energy and other gas suppliers.

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

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

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

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

Our computer systems and the infrastructure of our utility companies may be subject to cyber (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or adversely affect our business and financial results and condition.

There have been an increasing number of cyber-attacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, or attachments to e-mails or through persons inside of the organization or through persons with access to systems inside of the organization.

We have security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, we cannot be assured that a cyber-attack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject us to additional regulation, litigation or damage to our reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of our utility companies are designed and operated in such a manner to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting our facilities or the industry in general, could also cause us to incur additional security- and insurance-related costs, and could have adverse effects on our business and financial results and condition.

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

We depend on transmission and distribution facilities owned and operated by other utilities and energy companies to deliver the electricity and natural gas we sell to the wholesale and retail markets, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual and service obligations may be hindered.

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

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

“Comprehensive tax reform” remains a topic of discussion in the U.S. congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of our existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and reduce future cash flow.

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

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

If the sale of TECO Coal is not consummated, we may be required to record additional impairment charges with respect to TECO Coal’s long-lived assets, which could have an adverse effect on results of operations.

 

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Problems with operations could cause us to incur substantial costs.

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

Increased customer use of distributed generation could adversely affect our regulated electric utility business.

In many areas of the country there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s proposed “Clean Power Plan” rule, if enacted as proposed, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule. See “Federal or state regulation of GHG emissions depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.”

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

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

There is competition in wholesale power sales across the country. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are unbundled for all non-residential customers. Because PGS earns margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’s results. However, future structural changes that we cannot predict could adversely affect PGS.

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

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

 

 

 

 

 

79

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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 82 and 83.

 

 

 

80

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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.

 

 

 

 

 

81

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INDEX TO EXHIBITS

 

82

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83