UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

For the quarterly period ended March 31, 2017

OR

For the transition period from                      to                     

 

 

 

Indicate by check mark whether the registrant (1) has 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) has been subject to such filing requirements for the past 90 days.     YES  ☒    NO  ☐

Indicate by check mark whether the registrant has 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  ☒    NO  ☐

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

 

If an emerging growth company, indicate by check mark whether Tampa Electric Company has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

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

As of May 9, 2017, 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.

 

 

 

 

 

 

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ACRONYMS

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

 

 

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

 

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 TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

 

 

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

 

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

 

 

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

 

 

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

 

1. Summary of Significant Accounting Policies

See TEC’s 2016 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS.

Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of March 31, 2017 and December 31, 2016, and the results of operations and cash flows for the periods ended March 31, 2017 and 2016. The results of operations for the three months ended March 31, 2017 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2017.

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.

TEC is a wholly owned subsidiary of TECO Energy. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015. Therefore, TEC continues to be a wholly owned subsidiary of TECO Energy and became an indirect wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC.

Revenues

As of March 31, 2017 and December 31, 2016, unbilled revenues of $56 million and $54 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $26 million and $28 million for the three months ended March 31, 2017 and 2016, respectively.

 

 

2. New Accounting Pronouncements

Future Accounting Pronouncements

TEC considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the FASB.  The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s 2016 Annual Report on Form 10-K, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. TEC will adopt this guidance effective January 1, 2018. 

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While TEC does not currently expect the impact to be significant, TEC is continuing to evaluate the impact of the adoption of this standard on its consolidated financial statements. TEC implemented a project plan in 2016, and is in the process of reviewing material revenue streams in line with this plan, with conclusions on the impact on the streams expected in the second and third quarter of 2017. In addition, TEC is evaluating the available adoption methods, the impact of collectibility risk, and disclosure requirements. In the first quarter of 2017, TEC has concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force.

 

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. TEC is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

 

 

3. Regulatory

Base Rates-Tampa Electric

Tampa Electric’s results reflect a stipulation and settlement agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provides for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software beginning on January 1, 2013.

Storm Damage Cost Recovery-Tampa Electric

As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $9 million of storm costs in 2016. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five-month period ended December 31, 2017. Subsequent communications with FPSC staff and signatories to the 2013 stipulation and settlement agreement resulted in a conclusion to withdraw the petition, apply the storm costs to the transmission and delivery storm reserve and seek recovery of storm costs once the reserve is fully depleted. See the table below for the regulatory liability.

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Base Rates-PGS

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and decrease the bottom of the ROE range from 9.75% to 9.25%. The new bottom of the ROE range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020. The top of the ROE range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement.

As part of the settlement, PGS and OPC agreed that at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million will be amortized over a two-year recovery period beginning in 2016. In 2016, PGS recorded $16 million of this amortization expense. This additional amortization expense in 2016 was offset by the decrease in depreciation expense as discussed above with no impact to 2016 earnings. For the three months ended March 31, 2017, PGS recorded $1 million of amortization expense.  

Regulatory Assets and Liabilities

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

Details of the regulatory assets and liabilities are presented in the following table:

 

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4. Income Taxes

Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. Prior to the Merger, TEC was included in the filing of a consolidated federal income tax return with TECO Energy and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements of TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.

The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2013 and forward. The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, TECO Energy is only able to participate in the CAP through its short tax year ending June 30, 2016.

TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 were 38.46% and 36.70%, respectively. The increase in the three-month effective tax rate in 2017 versus the same period in 2016 is primarily due to a decreased AFUDC-equity tax benefit. TEC’s effective tax rates for the three months ended March 31, 2017 and 2016 differ from the statutory rate principally due to the tax benefit related to AFUDC-equity.

As of March 31, 2017, the amount of unrecognized tax benefits was $7 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. As of March 31, 2017, if recognized, $7 million of the unrecognized tax benefits would reduce TEC’s effective tax rate.

 

 

5. Employee Postretirement Benefits

 

TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic expense for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP.

 

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TEC’s portion of the net pension expense for the three months ended March 31, 2017 and 2016, respectively, was $3 million and $3 million for pension benefits, and $1 million and $2 million for other postretirement benefits.  

For the January 1, 2017 measurement, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.160% for pension benefits under its qualified pension plan.  For the January 1, 2017 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.280%.

TECO Energy made contributions of $14 million and $5 million to its qualified pension plan in the three months ended March 31, 2017 and 2016, respectively. TEC’s portion of these contributions was $11 million and $4 million, respectively.

Included in the benefit expenses discussed above, for the three months ended March 31, 2017 and 2016, TEC reclassified $2 million and $2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

 

 

6. Short-Term Debt

Details of the credit facilities and related borrowings are presented in the following table:

At March 31, 2017, 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 March 31, 2017 and December 31, 2016 was 1.72% and 1.49%, respectively.

 

Tampa Electric Company Credit Facility

 

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); (ii) includes a $50 million letter of credit facility; and (iii) made other technical changes.

 

 

 

 

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2017, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,308 million. At December 31, 2016, TEC’s total long-term debt had a carrying amount of $2,163 million and an estimated fair market value of $2,345 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board or by applying estimated credit spreads obtained from a third party to the par value of the security. The fair value of debt securities totaling $57 million is determined using Level 1 measurements; the fair value of the remaining debt securities is determined using Level 2 measurements (see Note 11 for information regarding the fair value hierarchy).

 

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8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. TEC believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously.

Tampa Electric Legal Proceeding

A suit has been filed against Tampa Electric alleging, among other things, wrongful death due to electrocution as a result of coming into contact with a downed power line in July 2016. Discovery is currently ongoing in the case. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition or cash flows.  

PGS Legal Proceeding

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 natural gas service.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, a suit was filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries. The suit against PGS remains pending. No trial date is currently set. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition or cash flows.  

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2017, TEC has estimated its ultimate financial liability to be $30 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

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 currently assessed 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. See Note 3 for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this reserve.

Long-Term Commitments

TEC has commitments for purchased power and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. TEC also has other purchase obligations for long-term service agreements and capital projects.  In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from

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customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at March 31, 2017:

 

 

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At March 31, 2017, TEC was in compliance with all required financial covenants.

 

 

9. Segment Information

 

 

 

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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.

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In November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. The stipulation agreement called for the FPSC to oversee one or more workshops in 2017 to seek a cost-effective way to insure against rising gas prices.  In April 2017, the FPSC decided to hold a hearing in the fall of 2017 to consider whether hedging should resume or be discontinued altogether.

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

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

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of March 31, 2017, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at March 31, 2017 and December 31, 2016 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were $6 million and $17 million derivative assets as of March 31, 2017 and December 31, 2016, respectively. Derivative liabilities were zero as of March 31, 2017 and December 31, 2016. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at March 31, 2017 and December 31, 2016 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at March 31, 2017, net pretax reductions in fuel costs of $6 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2017 and 2016, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended March 31, 2017 and 2016 is less than $1 million. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to November 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of March 31, 2017, are expected to settle during the 2017 and 2018 fiscal years:

 

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of March 31, 2017, 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 standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

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

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

 

 

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

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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 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.