TE Teco Energy, Inc. (delisted)

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2015 Annual Report on Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and 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, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Sept. 30, 2016 and 2015. The results of operations for the three and nine months ended Sept. 30, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

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.

On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on Sept. 4, 2015. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries. See Note 14 for further information.

Revenues

As of Sept. 30, 2016 and Dec. 31, 2015, unbilled revenues of $71.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

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 $32.6 million and $89.2 million for the three and nine months ended Sept. 30, 2016, respectively, compared to $31.7 million and $88.3 million for the three and nine months ended Sept. 30, 2015, respectively.

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

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to and were adopted by the company are described as follows:

Interest – Imputation of Interest

In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest , which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The company adopted this standard in the first quarter of 2016, and Dec. 31, 2015 balances have been retrospectively restated. This change resulted in $27.7 million of debt issuance costs as of Dec. 31, 2015, previously presented as “Deferred charges and other assets”, being reclassified as a deduction from the carrying amount of the related “Long-term debt, less amount due within one year” line item on its Consolidated Condensed Balance Sheet. In accordance with ASU 2015-15 Interest: Imputation of Interest , the company continues to present debt issuance costs related to its letter of credit arrangements and related instruments in “Prepayments and other current assets” on its Consolidated Condensed Balance Sheets.

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Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.   The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met.   The company early adopted in the third quarter of 2016 as permitted.

Compensation – Stock Compensation

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liabilities, and presentation on the statement of cash flows.  The company early adopted as permitted in the first quarter of 2016. Each aspect has an accounting impact and was implemented as follows:

Future Accounting Pronouncements

The company considers the applicability and impact of all ASUs issued by FASB.  The following updates have been issued by FASB but have not yet been adopted by TECO Energy. Any ASUs not included below were assessed and determined to be either not applicable to the company or are not expected to have a material impact on the consolidated financial statements.

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. 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 to. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company will adopt this guidance effective Jan. 1, 2018. The company has developed an implementation plan and is continuing to evaluate the available adoption methods. While the company does not expect the impact to be significant, it is continuing to evaluate the impact of adoption of this standard on its consolidated financial statements and disclosures.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities.  The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures.  This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after Dec. 15, 2017.  

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Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02, Leases. The standard 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 Dec. 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments .  The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. The company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows .  The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed.  This guidance will be effective for the company beginning in 2018, with early adoption permitted, and is required to be applied on a retrospective approach.  The company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirement) 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 to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

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

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

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4. Income Taxes

The effective tax rates for the three months ended Sept. 30, 2016 and 2015 were 19.86% and 39.12%, respectively. The effective tax rate decreased to 34.19% for the nine months ended Sept. 30, 2016 from 39.10% for the same period in 2015.

The decrease in the three-month effective tax rate of 19.26% in 2016 versus the same period in 2015 is primarily due to tax benefits recorded in the third quarter of 2016 for federal R&D credits, lower non-deductible Merger transaction costs and other permanent book-to-tax differences.

The effective tax rate for year-to-date 2016 differed from the U.S. statutory rate of 35% primarily due to the effects of federal R&D credits and the tax benefit related to long-term incentive compensation offset by non-deductible Merger transaction costs (see Notes 2 and 14 for further description). The effective tax rate for year-to-date 2015 differed from the U.S. statutory rate primarily due to tax expense related to long-term incentive compensation shares that vested below target levels.

Effective July 1, 2016 and due to the Merger with Emera, TECO Energy and its subsidiaries are included in a consolidated U.S federal income tax return with EUSHI and its subsidiaries. TECO Energy’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with EUSHI’s tax sharing agreement. To the extent that TECO Energy’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 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2013 and forward. Years 2015 and the short tax year ending June 30, 2016 are currently under examination by the IRS under its Compliance Assurance Program (CAP). Due to the Merger with Emera, the company is only eligible to participate in the CAP through its short tax year ending June 30, 2016. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.  As of Sept. 30, 2016 and Dec. 31, 2015, TECO Energy’s uncertain tax positions were $7.7 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for net operating losses and tax credit carryforwards. The increase was primarily due to an uncertain tax position related to federal R&D tax credits. TECO Energy believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s federal income tax return for the short tax year ending June 30, 2016.  As of Sept. 30, 2016, if recognized, $7.7 million of the unrecognized tax benefits would reduce TECO Energy’s effective tax rate.

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5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

For the Jan. 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan.

As a result of the Merger, TECO Energy remeasured its employee postretirement benefit plans on the Merger effective date, July 1, 2016. As part of the remeasurement, TECO Energy used an above-mean yield curve to determine its discount rate. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year. TECO Energy previously used a bond model matching technique to determine its discount rate. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on the company’s financial statements and provides consistency with Emera’s method for selecting a discount rate. For the July 1, 2016 measurement, TECO Energy used an assumed long-term EROA of 7.00% and a discount rate of 3.72% for pension benefits under its qualified pension plan. For the July 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 3.85%.

As a result of the remeasurement, TECO Energy’s net periodic benefit expense increased by $0.6 million for pension benefits and zero for other postretirement benefits for the three- and nine-months ended Sept. 30, 2016. TECO Energy’s liability for pension benefits increased by $61.7 million and $17.6 million for other postretirement benefits. The associated regulatory asset increased $54.0 million for pension benefits and $14.1 million for other postretirement benefits. Accumulated other comprehensive income decreased $7.7 million for pension benefits and $3.5 million for other postretirement benefits.

TECO Energy made contributions of $37.4 million and $55.0 million to its qualified pension plan for the nine months ended Sept. 30, 2016 and 2015, respectively. Additionally, NMGC made contributions of $2.7 million to its other postretirement benefits plan for the nine months ended Sept. 30, 2016 and 2015.

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For the three and nine months ended Sept. 30, 2016, TECO Energy and its subsidiaries reclassified $0.8 million and $1.8 million, respectively, of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as par t of periodic benefit expense, compared with $0.2 million and $2.4 million for the three and nine months ended Sept. 30, 2015, respectively. In addition, during the three and nine months ended Sept. 30, 2016, the regulated companies reclassified $3.8 milli on and $9.1 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense, compared with $2.6 million and $7.8 million for the three and nine months ended Sept. 30, 2015, respectively.

The settlement cost recognized relates to the settlement of the SERP liability for the TECO Coal participants. An estimated curtailment loss for the SERP of $1.3 million was recognized in the second quarter of 2016 as a result of retirements expected in the third quarter of 2016 as a result of the Merger, which expected retirements occurred in the third quarter of 2016.

The company’s postretirement benefit plans were not explicitly impacted by the Merger. However, TECO Energy expects to recognize a settlement charge related to the SERP of approximately $8.0 million in the first quarter of 2017 due to retirements that have occurred as a result of the Merger.

6. Short-Term Debt

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