Exhibit 99.1
FORM 51-102F4
BUSINESS ACQUISITION REPORT
ITEM 1. | IDENTITY OF COMPANY |
1.1 | Name and Address of Company |
Emera Incorporated (“Emera” or the “Company”)
5151 Terminal Road
Halifax, Nova Scotia B3J 1A1
1.2 | Executive Officer |
The following is the name and business telephone number of an executive officer of Emera who is knowledgeable about the significant acquisition and this report:
Stephen D. Aftanas
Corporate Secretary
(902) 428-6096
ITEM 2. | DETAILS OF ACQUISITION |
2.1 | Nature of Business Acquired |
TECO Energy, Inc. (“TECO Energy”) is a utility holding company headquartered in Tampa, Florida engaged through its subsidiaries in the regulated vertically-integrated electric utility business in Florida and natural gas transmission and distribution business in Florida and New Mexico. TECO Energy’s operating revenue in fiscal 2015 totalled approximately US$2.7 billion and for the three-month period ended March 31, 2016 totalled approximately US$659.5 million. As at March 31, 2016, TECO Energy had total assets of approximately US$9.0 billion. Virtually all of TECO Energy’s operating revenue is from regulated businesses.
TECO Energy was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company (“TEC”). TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, New Mexico Gas Intermediate, Inc. (“NMGI”), owns New Mexico Gas Company, Inc. (“NMGC”). TECO Energy and its subsidiaries had approximately 3,700 employees as of June 30, 2016.
TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provided retail electric service to approximately 730,000 customers in West Central Florida for the three months ended June 30, 2016, and has a net winter system generating capacity of 4,730 MW. Peoples Gas System (“PGS”), the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric
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power generation customers in Florida. With approximately 370,000 customers for the three months ended June 30, 2016, PGS has operations in Florida’s major metropolitan areas and most populous counties including: Miami-Dade, Broward, Palm Beach, Hillsborough and Orange. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2015 was almost 1.8 billion therms.
NMGC, a Delaware corporation and wholly-owned subsidiary of NMGI, was acquired by TECO Energy on September 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico. With approximately 520,000 customers for the three months ended June 30, 2016, NMGC serves approximately 60% of the state’s population in 23 of New Mexico’s 33 counties. NMGC’s largest concentration of customers (approximately 360,000) is in the region known as the Central Rio Grande Corridor, which includes the communities of Albuquerque, Belen, Rio Rancho and Santa Fe.
A detailed description of the business of TECO Energy is set out in Schedule A hereto.
2.2 | Acquisition Date |
Emera completed the Acquisition (as defined below) of all outstanding shares of TECO Energy on July 1, 2016.
2.3 | Consideration |
On July 1, 2016, Emera announced that it had completed the acquisition of all outstanding shares of TECO Energy for approximately US$6.5 billion (the “Acquisition”).
Emera financed the Acquisition through: (i) CDN$728 million (US$560 million) related to the first instalment of 4.00% convertible unsecured subordinated debentures (the “Convertible Debentures”) represented by instalment receipts issued in 2015, CDN$1.56 billion (US$1.2 billion) fixed-to-floating subordinated notes, CDN$500 million (US$384.4 million)in Canadian long term debt and CDN$4.2 billion (US$3.25 billion) in US long term senior unsecured notes; (ii) available cash on hand; and (iii) drawings of CDN$1.4 billion (US$1.1 billion) on the Company’s acquisition credit facility. The outstanding indebtedness under the acquisition credit facilities was subsequently repaid with the net proceeds from the final instalment payment made on August 2, 2016 on the Convertible Debentures represented by instalment receipts. On August 3, 2016, CDN$2,113,285,691 of Convertible Debentures were converted into common shares of Emera (“Common Shares”) at a conversion price of CDN$41.85 per Common Share, being a conversion rate of 23.8949 Common Shares per CDN$1,000 principal amount of Convertible Debentures.
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2.4 | Effect on Financial Position |
Emera does not have any current plans for material changes in its business or the business of TECO Energy which may have a significant effect on the financial performance and financial position of Emera.
2.5 | Prior Valuations |
Not applicable.
2.6 | Parties to the Transactions |
The Acquisition was not a transaction with an informed person, associate or affiliate of Emera (as such terms are defined in National Instrument 51-102 – Continuous Disclosure Obligations).
2.7 | Date of Report |
August 5, 2016.
ITEM 3. | FINANCIAL STATEMENTS AND OTHER INFORMATION |
The following financial statements are included as schedules to this Business Acquisition Report:
Schedule B
Audited consolidated financial statements of TECO Energy as at and for the years ended December 31, 2015 and December 31, 2014, together with the notes thereto and the auditor’s report thereon.
Schedule C
Unaudited consolidated condensed financial statements of TECO Energy as at and for the three months ended March 31, 2016, together with the notes thereto.
Schedule D
Unaudited pro forma consolidated financial statements of Emera as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015.
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Caution Regarding Unaudited Pro Forma Consolidated Financial Statements
This Business Acquisition Report contains the unaudited pro forma consolidated balance sheet as at March 31, 2016 and consolidated statements of earnings of Emera as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, giving effect to the Acquisition. The unaudited pro forma consolidated financial statements have been prepared using certain of Emera’s and TECO Energy’s respective financial statements as more particularly described in the notes to such unaudited pro forma consolidated financial statements. Such unaudited pro forma consolidated financial statements are not intended to be indicative of the results that would actually have occurred, or the results expected in future periods, had the events reflected herein occurred on the dates indicated. Actual amounts recorded upon the finalization of the purchase price allocation under the Acquisition may differ from such unaudited pro forma consolidated financial statements. Since the unaudited pro forma consolidated financial statements have been developed to retroactively show the effect of a transaction that occurred at a later date (even though this was accomplished by following generally accepted practice using reasonable assumptions), there are limitations inherent in the very nature of pro forma data. The data contained in the unaudited pro forma consolidated financial statements represents only a simulation of the potential impact of the Acquisition. Undue reliance should not be placed on such unaudited pro forma consolidated financial statements.
In this Business Acquisition Report, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars. References to “dollars”, “$”, or “CDN$” are to lawful currency of Canada. References to “US$” are to lawful currency of the United States of America.
Special Note Regarding Forward-Looking Statements
This Business Acquisition Report contains forward-looking information which reflects management’s expectations regarding (i) the future growth, results of operations, performance and business prospects and opportunities of the Company, and (ii) the future performance, business prospects and opportunities of TECO Energy and the integration of its electric utility business in Florida and natural gas transmission and distribution in New Mexico with the existing operations of Emera. These expectations may not be appropriate for other purposes. All forward-looking information is given pursuant to the “safe harbour” provisions of applicable Canadian securities legislation. The words “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Although the forward-looking information reflects management’s current beliefs and is based on information currently available to management, there can be no assurance that actual results will be consistent with the forward-looking information. The forward-looking information is subject to significant risks, uncertainties, assumptions and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. A number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. All forward-looking information is provided as of the date of this Business Acquisition Report and qualified in its entirety by the above cautionary statements. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.
SCHEDULE A
THE BUSINESS OF TECO ENERGY
TECO Energy was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of TEC. TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC. TECO Energy and its subsidiaries had approximately 3,700 employees as of June 30, 2016.
TECO Energy’s revenues from continuing operations by regulated subsidiary for the periods presented are as follows:
Revenues(1) from Continuing Operations
Three months ended March 31, 2016 | Year ended December 31, 2015 | Year ended December 31, 2014 | ||||||||||
millions of US dollars | ||||||||||||
Tampa Electric | $ | 424.5 | $ | 2,018.3 | $ | 2,021.0 | ||||||
PGS | 131.2 | 407.5 | 399.6 | |||||||||
NMGC | 106.6 | 316.5 | 137.5 | |||||||||
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Total regulated businesses | 662.3 | 2,742.3 | 2,558.1 | |||||||||
Other | (2.8 | ) | 1.2 | 8.3 | ||||||||
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Total revenues from continuing operations | $ | 659.5 | $ | 2,743.5 | $ | 2,566.4 | ||||||
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Net Income(1) (Loss) from Continuing Operations
Three months ended March 31, 2016 | Year ended December 31, 2015 | Year ended December 31, 2014 | ||||||||||
millions of US dollars | ||||||||||||
Tampa Electric | $ | 50.2 | $ | 241.0 | $ | 224.5 | ||||||
PGS | 13.1 | 35.3 | 35.8 | |||||||||
NMGC | 15.2 | 24.1 | 10.5 | |||||||||
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Total regulated businesses | 78.5 | 300.4 | 270.8 | |||||||||
Other | (4.8 | ) | (59.2 | ) | (64.4 | ) | ||||||
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Net income from continuing operations | $ | 73.7 | $ | 241.2 | $ | 206.4 | ||||||
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(1) | Regulated subsidiary amounts include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements. |
For further information on the financial condition and results of TECO Energy, reference is made to the audited consolidated financial statements of TECO Energy as at December 31, 2015 and 2014, including the consolidated statements of income, comprehensive income, cash flows and capital for each of the years ended December 31, 2015 and 2014, and the unaudited consolidated financial statements of TECO Energy for the three months ended March 31, 2016, each of which is included in this Business Acquisition Report.
Sale of TECO Coal
On September 21, 2015, TECO Diversified, Inc., a wholly-owned subsidiary of TECO Energy, entered into a securities purchase agreement for the sale of TECO Coal LLC (“TECO Coal”) to Cambrian Coal Corp. The securities purchase agreement did not provide for an up-front purchase payment, but provides for contingent payments of up to US$60 million that may be paid in the years up to 2019 depending on specified coal benchmark prices. TECO Energy retains certain deferred tax assets and personnel related liabilities, but all other TECO Coal
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assets and liabilities were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at September 30, 2015, and severance agreements, which were paid in 2015. In addition, TECO Energy retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia. TECO Energy is working with the purchaser and the respective permitting agencies to have all permits transferred to the purchaser.
The securities purchase agreement called for a simultaneous signing and closing, which occurred on September 21, 2015. The closing of this sale essentially completed the process of TECO Energy’s exit from unregulated operations to focus on regulated utility businesses.
As a result of the authorization by TECO Energy’s board of directors authorizing it to enter into negotiations for the sale of TECO Coal, effective in the third quarter of 2014 it was classified as asset held for sale and its results for all periods presented are classified on TECO Energy’s financial statements as discontinued operations. TECO Energy recorded a non-cash valuation adjustment of approximately US$76 million, after tax, to the carrying value of TECO Coal to reflect the sales price specified under a sales agreement entered into in October 2014, and an additional US$51 million impairment charge, including a US$7.7 million charge related to black lung liabilities was recorded in 2015.
Tampa Electric
TEC was incorporated in Florida in 1899 and was reincorporated in 1949. TEC is a public utility operating within the State of Florida. Its Tampa Electric division is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has two electric generating stations in or near Tampa and one electric generating station in southwestern Polk County, Florida.
Tampa Electric had 2,026 employees as of June 30, 2016, of which 819 were represented by the International Brotherhood of Electrical Workers and 151 were represented by the Office and Professional Employees International Union.
In 2015, Tampa Electric’s total operating revenue was derived approximately 52% from residential sales, 30% from commercial sales, 8% from industrial sales and 10% from other sales, including bulk power sales for resale. The sources of operating revenue and MWH sales for the years indicated were as follows:
Operating Revenue
Three months ended March 31, 2016 | Year ended December 31, 2015 | 2014 | ||||||||||
millions of US dollars | ||||||||||||
Residential | $ | 217.4 | $ | 1,040.3 | $ | 1,007.6 | ||||||
Commercial | 132.8 | 608.0 | 602.0 | |||||||||
Industrial-Phosphate | 13.1 | 53.1 | 59.9 | |||||||||
Industrial-Other | 25.5 | 107.1 | 104.6 | |||||||||
Other retail sales of electricity | 39.5 | 177.2 | 181.9 | |||||||||
Deferred and other revenue(1) | (19.4 | ) | ||||||||||
Total retail | 408.9 | 1,985.7 | 1,956.0 | |||||||||
Sales for resale | 1.4 | 3.7 | 13.0 | |||||||||
Other | 14.2 | 28.9 | 52.0 | |||||||||
Total operating revenues | $ | 424.5 | $ | 2,018.3 | $ | 2,021.0 |
(1) | Primarily reflects the timing of environmental and fuel clause recoveries. |
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Megawatt-hour Sales
Three months ended March 31, 2016 | Year ended December 31, 2015 | 2014 | ||||||||||
thousands of MWh | ||||||||||||
Residential | 1,915 | 9,045 | 8,656 | |||||||||
Commercial | 1,388 | 6,301 | 6,142 | |||||||||
Industrial | 461 | 1,870 | 1,901 | |||||||||
Other retail sales of electricity | 401 | 1,791 | 1,827 | |||||||||
Total retail | 4,165 | 19,007 | 18,526 | |||||||||
Sales for resale | 50 | 115 | 259 | |||||||||
Total energy sold | 4,215 | 19,122 | 18,785 |
No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on Tampa Electric. Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric space heating, fewer daylight hours and colder temperatures and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.
Generation
Tampa Electric has three electric generating stations in service, with a December 2015 net winter generating capability of 4,730 megawatts (“MW”). Tampa Electric assets include the Big Bend Power Station (1,632 MW capacity from four coal units and 61 MW from a combustion turbine (“CT”)), the Bayside Power Station (1,839 MW capacity from two natural gas combined cycle units and 244 MW from four CTs) and the Polk Power Station (220 MW capacity from the integrated gasification combined-cycle (“IGCC”) unit and 732 MW from four CTs). In addition, Tampa Electric installed a 1.6 MW solar array at Tampa International Airport (“TIA”) in December 2015.
The Big Bend Power Station coal-fired units went into service from 1970 to 1985, and the CT was installed in 2009. The Polk IGCC unit began commercial operation in 1996, and the four CTs began commercial operation from 2000 to 2007. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004 and Units 3 through 6 were completed in 2009. Both the Phillips Power Station and the City of Tampa Partnership Station were retired in November 2015.
Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,351 mega volts amps. The transmission system consists of approximately 1,302 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,209 pole miles of overhead lines and 5,060 trench miles of underground lines. As of December 31, 2015, there were 747,660 meters in service. All of this property is located in Florida.
All plants and important fixed assets are held in fee simple except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature common to properties of the size and character of those of Tampa Electric.
Tampa Electric has easements or other property rights for rights-of-way (“ROW”) adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such ROW for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.
TEC has a long-term lease for the office building in downtown Tampa, which serves as headquarters for TECO Energy, Tampa Electric and PGS.
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Regulation
Tampa Electric’s retail operations are regulated by the Florida Public Service Commission (“FPSC”), which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.
In general, the FPSC’s pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include operating and maintenance expenses, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate the individual company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes (at a zero cost rate) and an allowed return on equity (“ROE”). Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other interested parties.
Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on September 6, 2013, between Tampa Electric and all of 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: US$57.5 million effective November 1, 2013, an additional US$7.5 million effective November 1, 2014, an additional US$5.0 million effective November 1, 2015, and an additional US$110.0 million effective January 1, 2017 or the date that an expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if US Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is 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 also began using a 15-year amortization period for all computer software retroactive to January 1, 2013. Effective November 1, 2013, Tampa Electric ceased accruing US$8.0 million annually to the FPSC-approved self-insured storm damage reserve.
Tampa Electric is also subject to regulation by the United States Federal Energy Regulatory Commission (“FERC”) in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.
Non-power goods and services transactions between Tampa Electric and its affiliates are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may be disallowed for recovery from Tampa Electric’s retail and wholesale customers, respectively. Given TECO Energy’s acquisition of NMGC, Tampa Electric and TECO Energy jointly requested a waiver from FERC in order for Tampa Electric to continue to supply a de-minimis level of non-power goods and services to its affiliates. TECO Energy separately notified FERC that it would no longer qualify to be considered a single-state holding company under the Public Utility Holding Company Act of 2005 as of January 1, 2015, and thus it had formed a centralized service company, TECO Services, Inc., which would provide other non-power goods and services to Tampa Electric and its affiliates. On December 31, 2014, FERC granted Tampa Electric’s requested waiver without conditions, effective as of January 1, 2015.
On June 30, 2014, the company filed its required triennial market-power analysis in support of the company’s continued ability to effect wholesale market-based rate transactions everywhere, except within Tampa Electric’s balancing-authority area. FERC accepted Tampa Electric’s triennial filing on November 24, 2015.
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Tampa Electric is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters.
Competition
Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Distributed generation could also be a source of competition in the future, but has not been a significant factor to date. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.
Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other investor-owned, municipal and other utilities, as well as co-generators and other unregulated power generators with uncontracted excess capacity. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale markets is affected by the Power Plant Siting Act (“PPSA”), which sets the state’s electric energy and environmental policy, and governs the building of new generation involving steam capacity of 75 MW or more. The PPSA requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.
Tampa Electric is not a major participant in the wholesale market because it uses its lower-cost generation to serve its retail customers rather than the wholesale market.
FPSC rules promote cost-competitiveness in the building of new steam generating capacity by requiring investor owned utilities (“IOUs”), such as Tampa Electric, to issue requests for proposals (“RFPs”) prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 MW. These rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids and provide more stringent standards for the IOUs to recover cost overruns in the event that the self-build option is deemed the most cost-effective.
Fuel
Approximately 52% of Tampa Electric’s generation of electricity for 2015 was natural gas-fired, with coal representing approximately 48%. Tampa Electric used its generating units to meet approximately 94% of the total system load requirements, with the remaining 6% coming from purchased power. Tampa Electric’s average delivered fuel cost per one million British thermal units (“MMBTU”) and average delivered cost per unit of fuel burned have been as follows:
2015 | 2014 | 2013 | 2012 | 2011 | ||||||||||||||||
Average cost per MMBTU | ||||||||||||||||||||
Coal(1) | $ | 3.34 | $ | 3.48 | $ | 3.36 | $ | 3.57 | $ | 3.46 | ||||||||||
Natural Gas(2) | 4.34 | 5.68 | 5.23 | 5.34 | 6.20 | |||||||||||||||
Oil | 22.34 | 0.00 | 24.72 | 23.56 | 21.21 | |||||||||||||||
Composite | 3.78 | 4.16 | 4.00 | 4.19 | 4.38 | |||||||||||||||
Average cost per ton of coal burned | $ | 79.76 | $ | 83.70 | $ | 77.79 | $ | 84.59 | $ | 83.17 |
(1) | Represents the cost of coal and the costs for transportation. |
(2) | Represents the costs of natural gas, transportation, storage, balancing, hedges for the price of natural gas, and fuel losses for delivery to the energy center. |
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In 2015, Tampa Electric’s generating stations burned fuels as follows: Bayside Station burned natural gas; Big Bend Power Station, which has sulfur dioxide (“SO2”) scrubber capabilities and nitrogen oxides (“NOx”) reduction systems, burned a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas; and Polk Power Station burned a blend of low-sulfur coal and petroleum coke (which was gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil.
Coal
Tampa Electric burned approximately 4.0 million tons of coal and petroleum coke during 2015 and estimates that its combined coal and petroleum coke consumption will be about 4.1 million tons in 2016. During 2015, Tampa Electric purchased approximately 67% of its coal under long-term contracts with five suppliers, and approximately 33% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 85% of its coal and petroleum coke requirements in 2016 under long-term contracts with five suppliers and the remaining 15% in the spot market. Tampa Electric has coal transportation agreements with trucking, rail, barge and ocean vessel companies.
Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.
In 2015, approximately 84% of Tampa Electric’s coal supply was deep-mined, approximately 7% was surface-mined and the remaining 9% was petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations. Tampa Electric cannot predict, however, the effect of any future mining laws and regulations.
Natural Gas
As of December 31, 2015, approximately 63% of Tampa Electric’s 1,500,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 78% of its expected gas needs for the April 2016 through October 2016 period. In March 2016, to meet its generation requirements, Tampa Electric issued RFPs to meet its remaining 2016 gas needs and begin contracting for its 2017 gas needs. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.
Oil
Tampa Electric has an agreement in place to purchase low sulfur No. 2 fuel oil for its Big Bend and Polk Power stations. The agreement has pricing that is based on spot indices.
Franchises and Other Rights
Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public ROW as it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public ROW and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.
Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. The City of Temple Terrace reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed. In the absence of such right to purchase caused by non-renewal, Tampa Electric would be able to continue to use public ROW within the municipality based on judicial precedent, subject to reasonable rules and regulations imposed by the municipalities.
Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from September 2017 through August 2043.
Franchise fees expense totaled US$46.5 million in 2015. Franchise fees are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.
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Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use state or county ROW granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.
Capital Expenditures
Tampa Electric’s capital expenditures in 2015 of US$595 million, excluding allowance for funds used during construction debt and equity, included US $215 million for the Polk 2-5 conversion to combined cycle and related transmission system improvements, US$15 million for solar generation projects at TIA and the Big Bend Power Station, US$10 million for the conversion of the Big Bend Power Station boiler ignition system from distillate oil to natural gas, and approximately US$25 million in the first year of its program to replace its Customer Information System with a state-of-the-art Customer Relationship Management and Billing System (“CRMB”). Tampa Electric also spent approximately US$35 million for hurricane storm hardening for both the transmission and distribution systems, and US$20 million for maintenance capital for environmental control equipment and compliance with environmental regulation. Tampa Electric’s 2015 capital expenditures included approximately US$18 million related to environmental compliance and improvement programs, primarily for electrostatic precipitator and scrubber improvements, selective catalytic reduction (“SCR”) catalyst replacements and modifications to coal combustion by-product storage areas at the Big Bend Power Station.
As at December 31, 2015, Tampa Electric expected to spend approximately US$575 million on capital expenditures for 2016. For the transmission and distribution systems, Tampa Electric expects to spend US$210 million in 2016, including approximately US$155 million for normal transmission and distribution system expansion and reliability, and approximately US$40 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of US$130 million include approximately US$20 million for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, approximately US$50 million for generating system reliability in 2016 and advance purchases for 2017 unit outages. The capital expenditure forecast includes US$35 million, included in the New Generation category, for a 23 MW solar array that Tampa Electric will build, own and operate at the Big Bend Power Station. Included in 2016 capital expenditure forecast is US$20 million to complete the CRMB project described above.
In the 2017 to 2020 period, Tampa Electric expects to spend approximately US$500 million annually to support normal system growth and reliability, environmental compliance and improvements to facilities to serve customers. This level of ongoing capital expenditures reflects the costs for materials and contractors, long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These programs and requirements include: approximately US$20 million annually for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, average annual expenditures of more than US$90 million to support generating unit availability and reliability; average annual expenditures of almost US$25 million for environmental compliance; average annual expenditures of more than US$35 million for general infrastructure and facilities; average annual expenditures of approximately US$30 million for transmission and distribution system storm hardening; and approximately US$145 million annually for transmission and distribution system capacity improvements to meet expected stronger customer growth and reliability. Included in this period is average annual capital spending of approximately US$25 million to implement the new technology required to modernize the distribution system and install automated metering equipment that is typically associated with “smart grid” technology.
The capital spending forecast for generation includes approximately US$120 million for modifications to the Polk Unit 1 gassifier to produce a high value by-product. Spending on this project and any other revenue enhancing projects must be justified by an internal economic analysis that demonstrates a net benefit.
Tampa Electric’s capital spending forecast includes final amounts related to the conversion of the Polk Units 2-5 from peaking service to combined cycle with a January 2017 in-service date. Construction commenced in January 2014. The 2016 capital expenditures support the completion of the construction on the power plant and the related transmission system upgrades, start-up testing and precommissioning activities.
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New generation and transmission for the 2017-2019 period includes approximately US$195 million based on the assumption of a simple cycle peaking unit scheduled to be in-service in early 2020, and continued success in developing additional solar generation projects similar to the 2 MW project at TIA. Tampa Electric recognizes that the proposed guidelines for existing fossil fuel-fired electric generating units proposed and established by the United States Environmental Protection Agency (“EPA”) favours generating resources with lower or no carbon emissions. Tampa Electric may meet the need for additional generating capacity in 2020 with a conventional peaking unit or some combination of conventional generation distributed generation and/or renewable resources such as solar.
Peoples Gas System
PGS operates as the gas division of TEC. PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the state of Florida.
Gas is delivered to the PGS system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that served approximately 370,000 customers for the three months ended June 30, 2016. The system includes approximately 12,100 miles of mains and 6,900 miles of service lines.
PGS had 536 employees as of June 30, 2016. A total of 132 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.
Operating Revenue
Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2015 was almost 1.8 billion therms. Of this total throughput, 6% was gas purchased and resold to retail customers by PGS, 85% was third-party supplied gas that was delivered for retail transportation-only customers and 9% was gas sold off-system. Industrial and power generation customers consumed approximately 60% of PGS’s annual therm volume, commercial customers consumed approximately 27%, off-system sales customers consumed 9% and the remaining balance was consumed by residential customers.
While the residential market represents only a small percentage of total therm volume, residential operations comprised about 35% of total revenues.
Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also seen increased interest and development in natural gas vehicles. There are 42 compressed natural gas filling stations connected to the PGS distribution system.
Revenues and therms for PGS for the periods indicated were as follows:
Revenues | Therms | |||||||||||||||||||||||
Three months ended March 31, 2016 | Year ended 2015 | Year ended 2014 | Three months ended March 31, 2016 | Year ended 2015 | Year ended 2014 | |||||||||||||||||||
millions of US dollars | millions of therms | |||||||||||||||||||||||
Residential | $ | 50.5 | $ | 137.0 | $ | 144.1 | 32.9 | 74.9 | 80.8 | |||||||||||||||
Commercial | 42.8 | 138.8 | 139.1 | 141.1 | 470.8 | 460.5 | ||||||||||||||||||
Industrial | 3.3 | 13.0 | 13.1 | 83.5 | 289.0 | 274.3 | ||||||||||||||||||
Off system sales | 12.9 | 49.8 | 39.4 | 53.9 | 166.4 | 84.0 | ||||||||||||||||||
Power generation | 2.1 | 7.2 | 6.8 | 190.6 | 758.3 | 643.5 | ||||||||||||||||||
Other revenues | 16.6 | 50.5 | 48.5 | |||||||||||||||||||||
Total | $ | 128.2 | $ | 396.3 | $ | 391.0 | 502.0 | 1,759.4 | 1,543.1 |
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No significant part of PGS’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on PGS. PGS’s business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.
Distribution System
PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 19,000 miles of pipe, including approximately 12,100 miles of mains and 6,900 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.
PGS’s operations are located in 14 operating divisions throughout Florida. While most of the operations and administrative facilities are owned, a small number are leased.
Regulation
The operations of PGS are regulated by the FPSC separately from the regulation 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 seeks to set rates at a level that provides an opportunity for a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’s weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed ROE. Base rates are determined in FPSC revenue requirements proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.
PGS’s results reflect base rates established in May 2009, when the FPSC approved a base rate increase of US$19.2 million, which became effective on June 18, 2009 and reflects a return on common equity of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of US$560.8 million.
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment (“PGA”) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2015, the FPSC approved PGS’s 2016 PGA cap factor for the period January 2016 through December 2016.
In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm charge for energy conservation and pipeline replacement programs. The conservation charge is intended to permit PGS to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are mandated by Florida law and approved and monitored by the FPSC. PGS is also permitted to earn a return, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. PGS projects to have all cast iron and bare steel pipe removed from its system within seven years. Lastly, the FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.
In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the US Department of Transportation in Parts 191, 192 and 199, Title 49, of the Code of Federal Regulations.
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PGS is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters.
Competition
Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.
In Florida, gas service is unbundled for all non-residential customers. PGS has a NaturalChoice program, offering unbundled transportation service to all non-residential customers, as well as residential customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 23,300 transportation-only customers as of December 31, 2015 out of approximately 37,600 eligible customers.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.
Gas Supplies
PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.
Gas is delivered by the Florida Gas Transmission Company through 69 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville division receives gas delivered by a pipeline company through two gate stations located northwest of Jacksonville. Another pipeline company provides delivery through six gate stations. PGS also has one interconnection with its affiliate pipeline company in Clay County, Florida.
Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.
Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by the FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the PGA clause.
PGS procures natural gas supplies using base-load and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.
Neither PGS nor any of the interconnected interstate pipelines have storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS’s industrial customers are in the categories that are first curtailed in such situations. PGS’s tariff and transportation agreements with these customers give PGS the right to divert these customers’ gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.
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Franchises and Other Rights
PGS holds franchise and other rights with 116 municipalities and districts throughout Florida. These franchises govern the placement of PGS’s facilities on the public ROW as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing PGS’s use of public ROW and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events they are subject to forfeiture.
Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’s property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.
PGS’s franchise agreements have various expiration dates ranging from the present through 2044. PGS expects to negotiate twelve franchises in 2016. Franchise fees expense totaled US$8.8 million in 2015. Franchise fees are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.
Utility operations in areas outside of incorporated municipalities and districts are conducted in each case under one or more permits to use state or county ROW granted by the Florida Department of Transportation or the county commission of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates, and these rights are, therefore, considered perpetual.
Capital Expenditures
During the year ended December 31, 2015, PGS capital expenditures were approximately US$95 million, including approximately US$30 million for maintenance of the existing system, US$55 million to expand the system and support customer growth, and US$10 million for replacement of cast iron and bare steel pipe. PGS did not incur any material capital expenditures to meet environmental requirements, nor, as of December 31, 2015, were any anticipated for the 2016 through 2020 period.
As at December 31, 2015, capital expenditures for PGS were expected to be about US$105 million in 2016 and US$430 million during the 2017 to 2020 period. Included in these amounts is an average of approximately US$65 million annually for projects associated with customer growth and system expansion. The PGS capital expenditure forecast includes amounts related to constructing pipelines in the Northeast Florida area to support new liquefied natural gas terminals for export and fueling vessels that are dependent on project economics. The remainder represents capital expenditures for ongoing renewal, replacement and system safety, including approximately US$12 million annually for the replacement of cast iron and bare steel pipe, which is recovered through a rider clause approved by the FPSC in 2012.
At PGS, higher capital expenditures are focused on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are more expensive on a cost per MMBTU basis. In the current low oil price environment, the economics of converting to natural gas remain attractive for the long term, and natural gas has lower carbon dioxide (“CO2”) emissions than petroleum based fuels that are attractive to users.
New Mexico Gas Company
On September 2, 2014, TECO Energy completed the acquisition of NMGI contemplated by the acquisition agreement dated May 25, 2013 by and among TECO Energy, NMGI and Continental Energy Systems LLC. As a result of that acquisition, TECO Energy acquired all of the capital stock of NMGI. NMGI, which was incorporated in the state of Delaware in 2008, is the parent company of NMGC. The aggregate purchase price was US$950 million, which included the assumption of US$200 million of senior secured notes of NMGC, plus certain working capital adjustments.
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NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in the state of New Mexico. NMGC operates a natural gas distribution system that served approximately 520,000 customers for the three months ended June 30, 2016. The system includes approximately 1,600 miles of transmission pipeline, 10,200 miles of mains and 521,400 service lines. NMGC’s system interconnects with five interstate pipelines.
Operating Revenue
For 2015, the total throughput for NMGC was over 775 million therms. Of this total throughput, 52% was gas purchased and resold to retail customers by NMGC, 42% was third-party supplied gas that was delivered for retail transportation-only customers and 6% was gas sold or transported off-system. Industrial and power generation customers consumed approximately 26% of NMGC’s 2015 annual therm volume, commercial customers consumed approximately 30%, off-system transportation customers consumed 6% and the remaining balance was consumed by residential customers, which represents approximately 38% of total annual therm volume and 72% of NMGC’s total annual revenues.
Revenues and therms for NMGC for the three months ended March 31, 2016 and the year ended December 31, 2015 were as follows:
Revenues | Therms | |||||||||||||||
Three months ended March 31, 2016 | Year ended December 31, 2015 | Three months ended March 31, 2016 | Year ended December 31, 2015 | |||||||||||||
millions of US dollars | millions of therms | |||||||||||||||
Residential | $ | 77.7 | $ | 229.2 | 122.6 | 291.2 | ||||||||||
Commercial | 19.8 | 59.6 | 42.0 | 104.4 | ||||||||||||
Industrial | 0.2 | 1.2 | 0.4 | 2.5 | ||||||||||||
Off system sales | 0.6 | 0.3 | 3.9 | 1.2 | ||||||||||||
On system transportation | 6.6 | 19.1 | 95.1 | 328.7 | ||||||||||||
Off system transportation | 0.2 | 0.9 | 11.1 | 47.2 | ||||||||||||
Other revenues | 1.5 | 6.2 | ||||||||||||||
Total | $ | 106.6 | $ | 316.5 | 275.1 | 775.2 |
No significant part of NMGC’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on NMGC. NMGC’s business is seasonal with much higher volumes and revenues experienced during colder winter months.
Distribution System
NMGC’s distribution system extends throughout the areas it serves in New Mexico and consists of approximately 11,800 miles of pipe, including approximately 1,600 miles of transmission pipeline and 10,200 miles of distribution lines. Mains and service lines are maintained under ROW, franchises or permits.
NMGC’s operations are located in six operating areas throughout New Mexico. While most of the operations and administrative facilities are owned, a small number are leased.
Regulation
The operations of NMGC are regulated by the New Mexico Public Regulation Commission (“NMPRC”). The NMPRC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the NMPRC seeks to set rates at a level that provides an opportunity for a utility such as NMGC to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
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The basic costs of providing natural gas service, other than the costs of purchased gas, gas storage services and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate NMGC’s weighted cost of capital, primarily includes its cost for long-term debt and an allowed ROE. Base rates are determined in NMPRC revenue requirements proceedings which occur at irregular intervals at the initiative of NMGC, the NMPRC or other parties.
In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately US$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 January 31, 2012, revising, among other things, base rates for all service provided on or after February 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately US$21.5 million on a normalized annual basis. The monthly residential customer access fee increased from US$9.59 to US$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 a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017. In addition, under the order, NMGC provided US$2.0 million of pretax credits on customer bills for the first 12-month period post-closing, effective October 1, 2014, and will provide US$4.0 million of pretax credits to customers in each subsequent 12-month period until new base rates are effective, as reported in Note 21 to the TECO Energy consolidated financial statements for the fiscal year ended December 31, 2015, which are included in this Business Acquisition Report.
NMGC recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment clause (“PGAC”). This charge is designed to recover the costs incurred by NMGC for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. 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 gas cost billing factor 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 also has regulatory authority to include a simple interest charge or credit based upon the month-end balance of the PGAC under-recovery or over-recovery of NMGC’s cost of gas. NMGC’s annual PGAC period runs from September 1 to August 31. The NMPRC requires that NMGC file a 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 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 for continued use of the PGAC for another four years. In June 2016, NMGC filed its next PGAC Continuation Filing for the four year period ending December 2020.
In addition to its base rates and PGAC, NMGC’s residential customers and customers utilizing NMGC’s small and medium volume general services also pay a per-therm charge for energy conservation. The conservation charge is intended to permit NMGC to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are approved and monitored by the NMPRC. The NMPRC requires natural gas utilities to offer transportation-only service to all customer classes.
In addition to economic regulation, NMGC is subject to the NMPRC’s safety jurisdiction, pursuant to which the NMPRC regulates the construction, operation and maintenance of NMGC’s distribution system. In general, the NMPRC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the US Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.
NMGC is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters.
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Competition
Although NMGC is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. NMGC has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.
Pursuant to New Mexico statutes and NMPRC rules and regulations, NMGC is required to provide transportation-only services for all customer classes. NMGC receives its base rates for distribution gas delivery services regardless of whether a customer decides to opt for transportation-only service or continue on NMGC’s gas commodity sales service. During the year ended December 31, 2015, NMGC had approximately 4,100 transportation-only end-use customers and approximately 512,000 gas commodity sales service customers. Transportation-only throughput represented 48.5% of total system throughput and 6.3% of total revenue for the year ended December 31, 2015.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other transmission and distribution providers and thereby bypassing NMGC transmission and distribution facilities. In response to this competition, NMGC has developed various programs, including the provision of transportation-only services at discounted rates.
Gas Supplies
NMGC’s service territory is situated between two large natural gas production basins (the San Juan Basin to the northwest of NMGC’s service territory and the Permian Basin to the southeast of NMGC’s service territory). Natural gas is transported from these production basins on major interstate pipelines to NMGC’s intrastate transmission system and then to customers using its distribution system. The San Juan Basin typically supplies 85% of NMGC’s gas supply, with the Permian Basin supplying most of the remaining balance. NMGC also sources gas from the Piceance Basin in western Colorado and the Green River Basin in Wyoming.
NMGC’s transmission and distribution system interconnects with five interstate pipelines owned by various pipeline companies. NMGC has firm pipeline capacity contracts with these pipeline companies. To enhance gas supply and transportation availability, NMGC has an ownership interest in the Blanco Hub, one of the central supply and marketing points in the San Juan Basin. The Blanco Hub interconnects with NMGC’s transmission system as well as major nearby gathering systems and interstate pipelines. To provide for system balancing and peak day supply requirements, NMGC contracts for 3.2 billion cubic feet of underground gas storage capacity and gas storage services in an underground facility in west Texas. This storage facility is connected to two major interstate pipelines that, in turn, connect to NMGC’s transmission and distribution system.
Gas is purchased from various suppliers at market pools and processing plant tailgates from marketers and producers. NMGC has negotiated standard terms and conditions for the purchase of natural gas under the North American Energy Standards Board and the Gas Industry Standards Board forms of agreement. NMGC purchases gas for resale to its jurisdictional gas sales customers in accordance with an annual gas supply plan filed with the NMPRC.
Gas price spikes, which can occur in high demand winter months, have the potential to significantly increase customer bills. To provide a degree of price protection, NMGC utilizes a hedging plan for a portion of the winter gas supply. The gas hedging activity is discussed in more detail in TECO Energy’s consolidated financial statements, which are included in this Business Acquisition Report.
Franchises and Other Rights
Many of NMGC’s transmission and distribution facilities are located on lands that require the grant of ROW or franchises from non-tribal governmental entities, Native American tribes and pueblos, or private landowners. In some cases, renewed ROW or franchises must be submitted to the Federal Bureau of Indian Affairs for approval. For the year ended December 31, 2015, NMGC incurred expenditures for ROW or franchise renewals on Native American tribal and pueblo lands that amounted to US$0.3 million.
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In 2011, the New Mexico legislature passed legislation confirming the validity and enforceability of agreements with public utilities that provide access to public ROW, including expired agreements that have continued to be honored by both the public utility and the local government according to their terms, regardless of the expiration date of the agreements. Accordingly, some of NMGC’s expired ROW or franchises remain in effect by statute, though NMGC expects to enter into negotiations to renew expired ROW or franchises upon request. Based on current renewal experience with ROW and franchises on Native American tribal and pueblo lands, NMGC believes that it is likely those ROW or franchises will be renewed at prices that are significantly higher than historical levels. NMGC does not have condemnation rights on Native American tribal and pueblo lands, and, if it is unsuccessful in renewing some or all of these expiring or expired ROW or franchises, it could be obligated to remove its facilities from, or abandon its facilities on, the property covered by the ROW or franchises and seek alternative locations for its transmission or distribution facilities. With respect to land held by non-tribal governmental entities and privately-held land, however, NMGC may have condemnation rights and, thus, in the case where ROW or franchises cannot be renewed by negotiation, NMGC would likely exercise such rights rather than remove or abandon facilities and find alternative locations for such facilities. Historically, ROW and franchise costs have been recovered in rates charged to customers, and NMGC will continue to seek to recover ROW and franchise costs in future rates charged to customers.
Capital Expenditures
During the year ended December 31, 2015, NMGC capital expenditures of US$50 million included amounts to support customer growth, system reliability, facilities and equipment to safely and reliably operate the system, and investments in computer systems and technology required to successfully integrate NMGC financial and related systems with TECO Energy systems. During the year ended December 31, 2015, NMGC did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2016 through 2020 period.
As at December 31, 2015, the expected 2016 capital expenditure for NMGC were approximately US$80 million, which included approximately US$30 million annually for ongoing renewal, replacement and system safety and approximately US$10 million annually for system expansion to support growth. As at December 31, 2015, the forecast for capital expenditures in 2016 included approximately US$35 million for a transmission pipeline “looping” project to enhance system reliability and capacity for anticipated growth. The forecast beyond 2016 includes approximately US$25 million for software and systems upgrades, which are components of the integration plans with TECO Energy. The NMGC capital spending forecast in 2017 and 2018 include amounts for additional transmission system looping projects to enhance system reliability and capacity. NMGC’s capital expenditure forecasts may increase in future years as marketing, economic development and system expansion plans are further developed in the integration process.
Environmental Compliance
TECO Energy’s businesses have significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, a US federal law related to air pollution (“Clean Air Act”), and material Clean Water Act, a US federal law related to water pollution (“Clean Water Act”) implications and impacts by federal and state legislative initiatives. TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain Superfund (being a fund established to finance a long-term, permanent remedial project in connection with the US federal government’s program to clean up the uncontrolled hazardous waste sites in the United States) (“Superfund”) sites and, through its PGS division, for certain former manufactured gas plant sites. NMGC has not been designated as a PRP and has no former manufactured gas plant sites.
Air Quality Control
Emission Reductions
Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add Best Available Control Technology (“BACT”) emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.
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Tampa Electric, through voluntary negotiations in 1999 with the EPA, the US Department of Justice and the Florida Department of Environmental Protection (“FDEP”), signed a consent decree and consent final judgment, as settlement of federal and state litigation, to dramatically decrease emissions from its power plants. Tampa Electric has fulfilled the obligations of the consent decree, and the court terminated the consent decree on November 22, 2013. Termination of the consent final judgment was completed on May 6, 2015.
The emission-reduction requirements of these agreements resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (the “Bayside Power Station”), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Power Station to help reduce SO2, and installation of SCR systems for NOx reduction on Big Bend Power Station Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC. Cost recovery for the repowering of the Bayside Power Station was accomplished in Tampa Electric’s 2008 rate case.
Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% from 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system-wide reduction of mercury emissions of more than 90% from 1998 levels.
CAIR/CSAPR
As a result of its completed emission reduction actions, Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of the US Environmental Protection Agency’s Clean Air Interstate Rule (“CAIR”). In July 2008, the US Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO2and NOx. The federal appeals court reinstated CAIR in December 2008 on an interim basis. In July 2011, the EPA issued the final CAIR replacement rule, called the US Environmental Protection Agency’s Cross-State Air Pollution Rule (“CSAPR”). The final CSAPR focused on reducing SO2 and NOx in 27 eastern states that contribute to ozone and/or fine particle pollution in other states. Effective January 1, 2015, CSAPR Phase 1 replaced CAIR; Phase 2 of the CSAPR is expected to be implemented in 2017. Compliance with CSAPR, which would be measured at the individual power plant level, would require the addition of scrubbers or SCRs on most coal-fired power plants. In addition, the rule utilized intrastate emissions allowance trading and limited interstate emissions allowance trading to achieve compliance. All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Power Station Unit 1 IGCC unit removes SO2in the gasification process.
On December 30, 2011, the US Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) granted a motion to stay the implementation of CSAPR in all aspects, which had been scheduled to take effect January 1, 2013, and ordered the reinstatement of CAIR pending the outcome of the litigation. On August 21, 2012, the court vacated CSAPR entirely and remanded it back to the EPA while leaving the CAIR in place. On April 29, 2014, the US Supreme Court issued an opinion reversing the August 21, 2012 D.C. Circuit decision that had vacated CSAPR. Following the remand of the case to the D.C. Circuit, the EPA requested that the court lift the CSAPR stay and toll the CSAPR compliance deadlines by three years. On October 23, 2014, the D.C. Circuit granted the EPA’s request. Effective January 1, 2015, CSAPR Phase 1 replaced CAIR. Phase 2 of the CSAPR is expected to be implemented in 2017.
SO2 National Ambient Air Quality Standards (“NAAQS”)
On June 2, 2010, the EPA revised the primary SO2 NAAQS by establishing a new 1-hour standard at a level of 75 parts per billion (ppb). A part of Hillsborough County north of Big Bend Power Station has a monitor that violates the 2010 SO2 NAAQS. Although Big Bend Power Station did not contribute to the violation, it has potential effects on the non-attainment area based on air dispersion modeling evaluations and has committed to accept a more stringent SO2 permit limit to ensure the area achieves compliance with the ambient air standards.
The next phase of the SO2 NAAQS process will address all ambient SO2 exceedances located outside the designated non-attainment areas. Air dispersion modeling or ambient air monitoring will be used to determine impacts to these areas beginning no earlier than 2018 but no later than 2021. Additional SO2 emission reductions may be required depending on the outcome of this process.
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Hazardous Air Pollutants; Maximum Achievable Control Technology; Mercury Air Toxics Standards
The EPA published proposed rules under National Emission Standards for hazardous air pollutants on May 3, 2011, pursuant to a court order. These rules are expected to reduce mercury, acid gases, organics, and certain non-mercury metals emissions and require MACT. The final utility MACT rules, now called MATS, were published in December 2011 with implementation called for in early 2015 with possible extensions to early 2016 or 2017 under certain specific criteria.
On June 29, 2015, the US Supreme Court remanded the EPA’s MATS to the D.C. Circuit for failing to properly consider the cost of compliance. In December 2015, the D.C. Circuit ruled that MATS would remain in effect while the EPA performed further cost benefit analysis, and in March 2016 the US Supreme Court denied a request from 20 states to stay MATS pending the D.C. Circuit’s review. EPA released a revised cost benefit analysis in April 2016.
All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.
Carbon Reductions and GHG
Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO2 by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO2to remain near 1990 levels until the addition of the next base load unit, which is scheduled to be in service in January 2017. Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Power Station coal-fired units resulted in an annual decrease in CO2 emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 30% and 15%, respectively.
Tampa Electric’s power plants currently emit approximately 16 million tons of CO2 per year. Assuming a projected long-term average annual load growth of more than 1.0%, Tampa Electric could emit approximately 16.3 million tons of CO2 (an increase of approximately 2%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet customer demand.
In 2010, the EPA issued its Final Rule on the mandatory reporting of greenhouse gases (“GHGs”), requiring facilities that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on January 1, 2010, with the first annual report due September 28, 2011. Tampa Electric complied with the initial mandatory reporting requirement, in large part through the methods and procedures already utilized, and continues to submit annual reports as required. The rule also required natural gas distribution, underground coal mining facilities, and electric transmission and distribution companies, including PGS, and Tampa Electric, that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on January 1, 2011, with the first annual report due September 28, 2012. Tampa Electric and PGS complied with the reporting requirements and continue to submit annual reports as required.
In December 2009, the EPA published the final Endangerment Finding in the US Federal Register. Although the finding was technically made in the context of GHG emissions from new motor vehicles and did not, in itself, impose any requirements on industry or other entities, the EPA claims that the finding triggered GHG regulation of a variety of sources under the Clean Air Act. Related to utility sources, the EPA’s “tailoring rule”, which addresses the GHG emission threshold triggers that would require permitting review of new and/or major modifications to existing stationary sources of GHG emissions, became effective January 2, 2011. A recent US Supreme Court ruling narrowed the EPA’s authority to implement this rule but the key provisions remain applicable to Tampa Electric. While this rule does not have an immediate impact on Tampa Electric’s ongoing operations, GHG permitting was recently completed for Tampa Electric’s next base load unit, the Polk Power Station Unit 2-5 conversion to combined cycle.
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In June 2013, President Obama announced his Climate Action Plan, a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17% below 2005 levels by 2020. As part of the Climate Action Plan, the President directed the EPA to issue a draft rule for existing power plants by June 1, 2014, to finalize the rule by June 1, 2015, and to require states to submit implementation plans by June 30, 2016. In response to this directive, on June 2, 2014, the EPA released a comprehensive proposed rule to limit GHG emissions from existing power plants. The EPA’s final rule, the guidelines for existing fossil fuel-fired electric generating units proposed and established by the EPA under the authority of Clean Air Act section 111(d) (“Clean Power Plan”), was signed by the Administrator of the EPA on August 3, 2015 and sets emission performance goals that will cut GHG emissions from existing power plants by an average across all states of 32% from their 2005 levels by 2030, with an interim goal for the period from 2022 through 2029. Under the final rule, each state would have to reduce carbon dioxide emissions on a state-wide basis by an amount specified by the EPA adopting either a rate- or mass-based approach; the target amount was determined by the EPA’s view of each state’s options, including: making power plant efficiency upgrades; shifting from coal-fired to natural gas-fired generation; and investing in zero- and low-emitting power sources, such as renewable and nuclear energy. Under the methodology employed by the EPA, Florida has state-specific rate- and mass-based GHG targets that are in the middle of the range of goals the EPA has set for individual states. Based on the state-specific rate-based goal, generation capacity in Florida has an emission reduction goal equal to a 25% reduction from the 2012 baseline for GHG emission rate of affected electricity generating units. States are intended to have a great deal of flexibility in designing programs to meet their emission reduction targets, including the three approaches noted above or any other measures they choose to adopt, for example, energy efficiency programs. The final rule was published in the US Federal Register on October 23, 2015. Under the rule as published, states had until September 2016 to submit initial plans to achieve their target emission reductions (subject to extension and EPA approval of the states’ plans).
On January 21, 2016, the US Court of Appeals for the D.C. Circuit denied requests by 27 states and numerous trade groups for a stay that would have barred the EPA from implementing the carbon regulations for the electricity sector, but indicated that it would expedite the process for considering the lawsuits and would hear oral arguments June 2, 2016. However, on February 9, 2016, the US Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the D.C. Circuit. In a May 16, 2016 order, the D.C. Circuit rescheduled oral argument before the en banc court to September 27, 2016. The timing of the resolution of the legal challenges and the removal of the stay by the US Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018. Prior to the US Supreme Court ruling, Florida had not begun its rulemaking process, and is currently awaiting final resolution of the legal challenges before proceeding with rulemaking. Tampa Electric is evaluating a number of potential compliance scenarios, but until there is consensus in Florida regarding a state plan it will not be possible to develop a final compliance plan. The outcome of this litigation and the rule-making process and its impact on TECO Energy’s businesses is uncertain at this time; however, it could result in increased operating costs, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on how the state plan is developed and implemented, the Clean Power Plan could cause an increase in costs or rates charged to customers, which could curtail sales.
Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through an environmental cost recovery clause, which allows for the recovery of costs associated with certain environmental investment and expenses (“ECRC”). If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills. 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 it is uncertain if the FPSC would grant such recovery. Prior to the conversion of the coal-fired Gannon Power Station to the natural gas-fired Bayside Power Station in 2003, nearly all of Tampa Electric’s generation was from coal. Upon completion of that conversion, the mix shifted with the increased use of natural gas. Coal is expected to continue to represent an important component in Tampa Electric’s fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit 1. Tampa Electric’s solid-fuel energy generation was 48% of its total system output in 2015, compared to being approximately 96% of its output in 2001.
Water Supply and Quality
The EPA’s final rule under section 316(b) of the Clean Water Act became effective in October 2014. This rule was initially proposed by EPA in response to citizens’ lawsuits over perceived impacts to aquatic life resulting from operation of cooling water systems in the US from either impingement (on intake screens) or entrainment (through condensers). Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend Power Station facilities as
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cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms, and Big Bend Power Station units 3 and 4 use proprietary fine-mesh screens, BACT, to further reduce impacts to aquatic organisms. Neither station has historically demonstrated any significant adverse environmental impacts. Polk Power Station is not covered by this rule since it does not operate an intake on waters of the US. Tampa Electric has two ongoing projects (one for Bayside and one for Big Bend Power Station) to negotiate scheduling with the regulating authority and to complete the biological, technical, and financial study elements necessary to comply with the rule. These study elements will ultimately be used by the regulating authority to determine the necessity of cooling water system retrofits for Big Bend and Bayside Power Stations. The full impact of the new regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies.
EPA determined that numeric water quality standards are required in Florida to implement the Clean Water Act. On January 26, 2010, EPA published proposed “Water Quality Standards for the State of Florida’s Lakes and Flowing Waters”. There was a long, litigious path in which EPA and FDEP both proposed criteria. Ultimately, the courts upheld the ruling that the Florida regulations meet the requirements of the Clean Water Act. Both Big Bend and Bayside Power Stations already have allocations allotted by the Nitrogen Management Consortium of the Tampa Bay Estuary Program for total nitrogen, which is the limiting nutrient for Tampa Bay. Other criteria related to streams may still directly affect Polk Power Station’s cooling reservoir discharge to surface water, and may require the station to reduce the amount of nutrients in the cooling reservoir water before discharge.
After the completion of a study into wastewater discharges by the electric utility industry in 2009, the EPA announced its intent to revise the existing steam electric effluent limit guidelines of the EPA (“ELGs”) that place technology-based limits on wastewater discharges. The final EPA rule was published in the US Federal Register November 3, 2015 and became effective January 4, 2016. The ELGs establish limits for wastewater discharges from FGD processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing CCRs, gasification processes, and flue gas mercury controls. For flue gas desulfurization (“FGD”) wastewater, the rule imposed limits for arsenic, mercury, selenium, and nitrate/nitrite which will require the addition of biological treatment at Big Bend Power Station. Both fly ash and bottom ash transport water have been designated as zero discharge wastewaters, with the exception of use as make-up water in FGD scrubbers. Transport water used as make-up will be subject to FGD wastewater limits at the point of discharge. New limits for gasification processes will likely require additional treatment at Polk Power Station. Cost estimates are being developed based on an evaluation of treatment technologies required to meet the pollutant limits. The new guidelines are expected to be incorporated into National Pollutant Discharge Elimination System (NPDES) permit renewals to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023.
EPA Waters of the US
In June 2015, the US Army Corps of Engineers and the EPA issued a rule defining “Waters of the United States” (“WOTUS”) for purposes of federal Clean Water Act jurisdiction. The final rule took effect on August 28, 2015. The rule has the effect of defining the scope of agency jurisdiction under the Clean Water Act very broadly. In August 2015, a federal judge in North Dakota issued an injunction against the implementation of the rule in certain states. In October 2015, the Sixth Circuit Court of Appeals issued a nationwide stay of WOTUS, effectively ending the implementation of the rule in the 37 states that were not subject to the prior injunction. This stay is temporary, pending determination of the court’s jurisdiction over the various challenges to the final rule.
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 manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2016, TEC has estimated its ultimate financial liability to be US$33.9 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 sheet of TECO Energy as at December 31, 2015, which is included in this Business Acquisition Report. 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.
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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 allocated actual percentage share 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.
Coal Combustion Residuals Recycling and Disposal
EPA’s final coal combustion residuals (“CCR”) rule became effective on October 19, 2015, and regulates CCRs as non-hazardous solid waste. The rule explicitly allows for encapsulated beneficial uses of CCRs in commercial and industrial products. However, non-encapsulated uses in agricultural and construction applications are allowable only if they meet new environmental criteria.
The rule contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. Potential capital expenditures that are required to achieve compliance with this rule are not expected to be significant. On February 2, 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. The CCR rule has been challenged by both utility and environmental groups. Legislation has also been proposed in Congress to amend certain provisions of the CCR rule. Pending the outcome of the litigation and/or legislative amendment, the ultimate impacts of the CCR rule on Tampa Electric are uncertain at this time; however, it could curtail Tampa Electric’s ability to market CCRs for beneficial reuse.
Solar Initiatives
In 2015, Tampa Electric announced plans for a 23-MW utility-scale solar photo voltaic project to be installed at Tampa Electric’s Big Bend Station. This is the largest solar project in the Tampa Bay area, consisting of more than 70,000 solar panels on 125 acres of land owned by Tampa Electric. Upon completion, it will have the capacity to power more than 3,500 homes. In 2015, Tampa Electric completed the construction of a 2-MW solar photo voltaic energy installation at TIA, which is Tampa Electric’s first large-scale solar facility. At 2 MW, the solar panels at TIA produce enough electricity to power up to 250 homes. Tampa Electric owns the solar photo voltaic array, and the electricity it produces goes to the grid to benefit all Tampa Electric customers, including the airport. Tampa Electric anticipates developing additional similarly sized small-scale solar photo voltaic installations and we seek opportunities for additional utility-scale installations.
In addition, Tampa Electric has installed 2,135 kilowatts of solar panels to generate electricity from the sun at eight community sites including two schools, Tampa Electric’s Manatee Viewing Center, the Museum of Science and Industry, Tampa’s Lowry Park Zoo, the Florida Aquarium, and LEGOLAND Florida.
In Florida, a constitutional amendment was proposed that would allow the sale of up to 2 MW of power direct to other customers from rooftop solar panels, potentially bypassing the utility. The Florida Supreme Court ruled that the amendment meets constitutional and statutory requirements to appear on the ballot, however supporters were unable to gather and certify the required number of signatures by the deadline to have it placed on the ballot in 2016. Supporters indicate that they plan to try to have the amendment on the ballot in 2018. Legislation has been proposed for consideration in the 2016 Florida legislative session that essentially mirrors the intent of the constitutional amendment.
A second Florida constitutional amendment regarding solar power generation is proposed for the 2016 ballot that would establish a right for consumers to own or lease solar equipment installed on their property to generate
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electricity for their own use. State and local governments would retain the ability to protect consumer rights and public health and safety and ensure that consumers that do not choose to install solar are not required to subsidize the costs of backup power and electric grid access for those that do. The Florida Supreme Court ruled that the amendment meets constitutional and statutory requirements to appear on the ballot. Backers of the proposed amendment have gathered and certified the required number of signatures to have it on the 2016 ballot.
Distributed Generation
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. To date, there has not been a significant amount of distributed generation added to utility systems in Florida. Florida does not have a renewable portfolio standard, and Florida legislation and regulation have minimized social programs and costs in utility rates. However, proposed action by the Florida legislature in 2016 and a potential amendment to the Florida constitution that supporters are seeking to have placed on the ballot in 2018 would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and allow limited sales of electricity by non-utility generators.
Additionally, the EPA’s Clean Power Plan rule, if enacted consistent with the rule published in August 2015, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets. Depending on how the rule is implemented, it could have the effect of increasing TECO Energy’s costs or the rates charged to TECO Energy’s 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. Due to the intermittent availability of renewable resources, utilities must invest in adequate generating resources to meet customer demand at the times that renewable resources are not available. Energy storage technologies, such as batteries, are not yet commercially available to fill this demand. Continued utility investment not supported by increased future energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.
Conservation
Energy conservation is becoming more important in the GHG emissions reduction debate. Tampa Electric supports the FPSC and its efforts to encourage energy efficiency. In 2015, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled the company to meet its required DSM goals, reduce weather-sensitive peak demand and conserve energy. This strategy continues to allow Tampa Electric to delay construction of future generation facilities. Since their inception, the company’s conservation programs have reduced the summer peak demand by 348 MW and the winter peak demand by 740 MW.
In November 2014, the FPSC established new DSM goals for the 10-year period from 2015 to 2024 for all Florida investor-owned electric utilities. In November 2015, Tampa Electric transitioned into the new 2015-2024 DSM plan by discontinuing nine existing DSM programs; creating one new DSM program; modifying twenty-eight existing DSM programs; and retiring the renewable energy systems initiative. This transition supports the approved FPSC goals which are reasonable, beneficial and cost-effective to all customers as required by the Florida Energy Efficiency & Conservation Act. For Tampa Electric, the summer and winter demand goals are 56.9 and 87.4 MWs, respectively, and the energy goal is 144.3 gigawatt-hours over the 10-year period. Establishing these DSM goals for the 10-year period is required every five years. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. In addition, PGS offers conservation programs that enable customers to reduce their energy consumption, with those costs recovered through a clause on the customer’s gas bill.
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Risk Factors Relating to the Post-Acquisition Business and Operations of the Company and TECO Energy
Emera will have a substantial amount of indebtedness which may adversely affect its cash flow and ability to operate its business
After giving effect to the Acquisition, Emera will have a significant amount of debt, including US$4.1 billion of debt of TECO Energy assumed by Emera as a result of the Acquisition. As of March 31, 2016, on a pro forma basis after giving effect to the Acquisition, Emera would have approximately $15.8 billion of total indebtedness outstanding. The change in the capital structure of Emera as a result of the Acquisition could cause credit rating agencies which rate the outstanding debt obligations of Emera to re-evaluate and potentially downgrade the current credit ratings, which could increase Emera’s borrowing costs.
Emera’s historical and pro forma combined financial information may not be representative of the results of Emera following the Acquisition
The pro forma combined financial information included in this Business Acquisition Report has been prepared using the consolidated historical financial statements of Emera and the consolidated historical financial statements of TECO Energy and does not purport to be indicative of the financial information that will result from the operations of Emera on a consolidated basis following the Acquisition. In addition, the pro forma combined financial information included in this Business Acquisition Report is based in part on certain assumptions regarding the Acquisition that Emera currently believes are reasonable. Emera makes no assurances that its current assumptions will prove to be accurate over time. Accordingly, the historical and pro forma financial information included in this Business Acquisition Report does not necessarily represent the results of operations and financial condition had Emera and TECO Energy operated as a combined entity during the periods presented, or of the results of operations and financial condition in the future. The potential for future business success and operating profitability must be considered in light of the risks, uncertainties, expenses and difficulties typically encountered by recently combined companies.
In preparing the pro forma financial information contained in this Business Acquisition Report, Emera has given effect to the Acquisition. While Emera’s management believes that the estimates and assumptions underlying the pro forma financial information are reasonable, such assumptions and estimates may be materially different than Emera’s actual experience following completion of the Acquisition.
Potential undisclosed liabilities associated with the Acquisition
In connection with the Acquisition, there may be liabilities of TECO Energy and its subsidiaries that Emera failed to discover or was unable to quantify prior to the Acquisition. The discovery or quantification of any material liabilities of TECO Energy and its subsidiaries could have a material adverse effect on Emera’s business, financial condition or future prospects.
Emera may be unable to successfully combine the businesses of Emera and TECO Energy to realize the anticipated benefits of the Acquisition
The combination of the businesses of Emera and TECO Energy will require the dedication of substantial effort, time and resources on the part of management which may divert management’s focus and resources from other strategic opportunities and from operational matters during this process. There can be no assurance that management will be able to combine the operations of each of the businesses successfully or achieve any of the benefits that are anticipated as a result of the Acquisition. The extent to which the benefits are realized and the timing of such cannot be assured. Any inability of management to successfully combine the operations of Emera and TECO Energy could have a material adverse effect on Emera’s business, financial condition or results of operations.
Emera may not be successful in retaining the services of key personnel of TECO Energy following the Acquisition
Emera intends to retain key personnel of TECO Energy to continue to manage and operate TECO Energy as a separate operating company. Emera will compete with other potential employers for employees, and it may not be successful in keeping the services of the executives and other employees that it needs to realize the anticipated benefits of the Acquisition. Emera’s failure to retain key personnel to remain as part of the management team of TECO Energy in the period following the Acquisition could have a material adverse effect on the business and operations of TECO Energy and Emera on a consolidated basis.
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Emera is subject to risks associated with its results of operations and financing risks
Management of Emera believes, based on current expectations as to its future performance (which reflects, among other things, the completion of the Acquisition), that the cash flow from its operations and funds available under its unsecured revolving credit facility and its ability to access capital markets will be adequate to enable Emera to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, expected revenue and the costs of planned capital expenditures are only estimates. Moreover, actual cash flows from operations are dependent on regulatory, market and other conditions that are beyond the control of Emera. As such, no assurance can be given that management’s expectations as to future performance will be realized. In addition, management’s expectations as to Emera’s future performance reflect the current state of its information about TECO Energy and its operations and there can be no assurance that such information is correct and complete in all material respects.
After giving effect to the Acquisition, Emera will have a significant amount of debt, including US$4.1 billion of debt of TECO Energy assumed by Emera as a result of the Acquisition. As of March 31, 2016, on an as adjusted pro forma basis after giving effect to the Acquisition, Emera would have approximately $15.8 billion of total indebtedness outstanding. The significant increase in the degree of Emera’s leverage could, among other things, limit Emera’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict Emera’s flexibility and discretion to operate its business; require Emera to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade Emera’s existing credit ratings; expose Emera to increased interest expense on borrowings at variable rates; limit Emera’s ability to adjust to changing market conditions; place Emera at a competitive disadvantage compared to its competitors that have less debt; make Emera vulnerable to any downturn in general economic conditions; and render Emera unable to make expenditures that are important to its future growth strategies.
Emera will need to refinance or reimburse amounts outstanding under Emera’s and TECO Energy’s indebtedness over time. There can be no assurance that any such indebtedness of Emera will be refinanced or that additional financing on commercially reasonable terms will be obtained, if at all.
The ability of Emera to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the financial performance of Emera, debt service obligations, the realization of the anticipated benefits of the Acquisition and working capital and future capital expenditure requirements. In addition, the ability of Emera to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under Emera’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of distributions by Emera and permit acceleration of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the assets of Emera would be sufficient to repay such indebtedness in full. There can also be no assurance that Emera will generate cash flow in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.
TECO Energy has been and may continue to be the target of securities class action suits and derivative suits which could result in substantial costs and divert management attention and resources.
Securities class action suits and derivative suits are often brought against companies who have entered into mergers and acquisition transactions. Following the announcement of the execution of the Merger Agreement with Emera, 12 putative stockholder class actions were filed challenging the transaction. In November 2015, the defendants party to the litigation entered into a Memorandum of Understanding (the “MOU”) with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed merger. As a result of the MOU, TECO Energy made additional disclosures related to the proposed merger in a proxy supplement filed on November 18, 2015. Subsequent to the closing of the acquisition, the parties are expected to enter into a formal settlement agreement in August, which will be filed with the Hillsborough Circuit Court Judge for approval. Additionally, the judge will consider the award of legal fees to the plaintiffs’ lawyers. Defending against these claims, even if meritless, can result in substantial costs to TECO Energy and could divert the attention of TECO Energy’s management.
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National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TECO Energy and its subsidiaries
The business of TECO Energy is concentrated in Florida and New Mexico. While economic conditions in Florida and New Mexico have improved since the worst of the economic downturn in 2008, if they do not continue to improve or if they should worsen, retail customer growth rates may stagnate or decline, and customers’ energy usage may further decline, adversely affecting TECO Energy’s results of operations, net income and cash flows.
A factor in TECO Energy’s customer growth in both Florida and New Mexico is net in migration of new residents, both domestic and non-US. A slowdown in the US economy could reduce the number of new residents and slow customer growth. In addition, New Mexico has significant oil and natural gas production from the San Juan and Permian production basins. The current low oil and natural gas-price environment has reduced drilling activity and oil and natural gas production in some producing regions, which has reduced employment in those industries and industries that serve them. A continuation of these conditions could slow growth in the New Mexico economy, which could reduce earnings and cash flow from NMGC.
Developments in technology could reduce demand for electricity and gas
Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient appliances and equipment. Advances in these, or other technologies, could reduce the cost of producing electricity or transporting gas, or otherwise make the existing generating facilities of Tampa Electric uneconomic. In addition, advances in such technologies could reduce demand for electricity or natural gas, which could negatively impact the results of operations, net income and cash flows of TECO Energy and those of Emera following the Acquisition.
TECO Energy’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations
TECO Energy’s utility businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by its 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 typically have 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. NMGC typically earns all of its net income in the first and fourth quarters, due to winter weather. Mild winter weather could negatively impact results at TECO Energy and those of Emera following the Acquisition.
TECO Energy’s electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition
TECO Energy’s electric and gas utilities operate in highly regulated industries. Their retail operations, 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 TECO Energy’s 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, indicating an overearnings trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged overearnings could result in credits or refunds to customers, which could reduce earnings and cash flow.
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Various factors relating to the integration of NMGC could adversely affect TECO Energy’s business and operations
The anticipated accretion to TECO Energy’s earnings from NMGC during the original three-year integration period was based on estimates of synergies from the transaction and growth in the New Mexico economy, which are dependent on local and global economic conditions, normal weather and other factors, which may materially change, including:
• | TECO Energy’s estimate of NMGC’s expected operating performance after the completion of the transaction may vary significantly from actual results. |
• | Over time, TECO Energy will be making significant capital investments to convert several NMGC computer systems to the systems that TECO Energy uses in Florida. These conversions may not be accomplished on time or on budget, which would increase costs for NMGC. In addition, the time required to convert these systems will cause NMGC to operate the existing systems past the end of their normal lives, which could reduce reliability. |
• | The potential loss of key employees of TECO Energy or NMGC who may be uncertain about their future roles in the TECO Energy / NMGC organization. |
Negative impacts from these factors could have an adverse effect on the anticipated benefits of the Acquisition or TECO Energy’s business, financial condition or results of operations. TECO Energy identified some, but not all, of the actions necessary to achieve its anticipated synergies. Accordingly, the synergies expected from the acquisition of NMGC may not be achievable in its anticipated amount or timeframe or at all.
Changes in the environmental laws and regulations affecting its businesses could increase TECO Energy’s costs or curtail its activities
TECO Energy’s 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 TECO Energy, requiring cost-recovery proceedings and/or requiring it to curtail some of its businesses’ activities.
Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs
The US EPA published a new CCR rule in the US Federal Register on April 17, 2015 setting federal standards for companies that dispose of or store CCRs in onsite landfills and impoundments. The rule went into effect on October 19, 2015 and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. Activities in 2016 will consist primarily of monitoring and testing of the two existing CCR impoundments that are affected by this rule. Potential capital expenditures that may be required to comply with this rule are not expected to be significant. This rule is likely to face continued legal challenges by the utility industry and environmental groups, and legislation is required to fix certain portions of the rule. At this time, the ultimate outcome of any litigation or legislation is uncertain, so that it is not possible to predict the ultimate impact on Tampa Electric. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, TECO Energy cannot be assured that any increased costs associated with the new regulations will be eligible for such treatment.
Federal or state regulation of GHG emissions, depending on how they are enacted and implemented, could increase TECO Energy’s costs or the rates charged to TECO Energy customers, which could curtail sales
Among TECO Energy’s companies, Tampa Electric has the most significant number of stationary sources with air emissions.
Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new state or federal 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 TECO Energy cannot be assured that the FPSC would grant such recovery. Under the Clean Power Plan, each state is responsible for implementing its own regulations to accord to the federal standards. Accordingly, a change in Florida’s
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regulatory landscape could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TECO Energy requiring FPSC cost recovery proceedings and/or requiring it to curtail some of its business activities.
The Clean Power Plan establishes state-specific emission rate and mass-based goals measured against a 2012 baseline. As TECO Energy’s investments in lower-GHG production largely occurred before 2012 and are factored into Florida’s baseline generating capacity, TECO Energy may encounter more difficulty than its competitors in achieving cost-effective GHG emission reductions. Because the ultimate form of Florida’s state plan remains unknown, the increased compliance costs that TECO Energy may face as a result of the Clean Power Plan are currently uncertain.
On February 9, 2016, the US Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the US Court of Appeals for the District of Columbia Circuit. The timing of the resolution of the legal challenges and the removal of the stay by the US Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018.
Potential amendments to the Florida Constitution regarding solar energy could adversely impact Tampa Electric.
In 2015, there was a proposed constitutional ballot initiative for the 2016 election approved by the Florida Supreme Court to promote increased direct sale and use of solar energy to generate electricity which has now been delayed to the 2018 election. There is also a proposed constitutional amendment on the August 2016 primary election ballot that could, if passed by 60% of the voters, lead to lower property taxes on solar technology used in commercial applications, and promote increased direct sale and use of solar energy to generate electricity.
The potential amendment to the Florida constitution in 2018 and the proposed amendment on the August 2016 primary election ballot would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and allow sales of electricity by non-utility generators. Increased use of solar generation and sales by third parties would reduce energy sales and revenues at Tampa Electric. In addition, Tampa Electric could make investments in facilities to serve customers during periods that solar energy is not available that would not be profitable.
NMGC operates high-pressure natural gas transmission pipelines, which involve risks that may result in accidents or otherwise affect its operations
There are a variety of hazards and operating risks inherent in operating high-pressure natural gas transmission pipelines, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by floods, fires and other natural disasters that may cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, known as High Consequence Areas, the level of damage resulting from these risks could be greater. NMGC does not maintain insurance coverage against all of these risks and losses, and any insurance coverage it might maintain may not fully cover damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material adverse effect on TECO Energy’s business, earnings, financial condition and cash flows.
NMGC’s high-pressure transmission pipeline operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase TECO Energy’s cost of operations and affect or limit its business plans
TECO Energy’s pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the US Department of Transportation. These laws and regulations require TECO Energy to comply with a significant set of requirements for the design, construction, maintenance and operation of its pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipelines. The regulations determine the pressures at which its pipelines can operate.
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PHMSA is designing an integrity verification process intended to create standards to verify maximum allowable operating pressure, and to improve and expand pipeline integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. Pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on TECO Energy’s pipelines. Should any of these risks materialize, it may have a material adverse effect on TECO Energy’s operations, earnings, financial condition and cash flows.
Results at TECO Energy’s companies may be affected by changes in customer energy-usage patterns
For the past several years, at Tampa Electric, and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts, economic conditions and improvements in lighting and appliance efficiency.
Forecasts by TECO Energy’s companies are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of TECO Energy’s utilities to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency, economic conditions or other factors.
TECO Energy’s computer systems and the infrastructure of its utility companies are 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 otherwise adversely affect its 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, attachments to e-mails, through persons inside of the organization or through persons with access to systems inside of the organization.
TECO Energy has 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, TECO Energy 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 it to additional regulation, litigation or damage to its reputation.
There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of TECO Energy’s utility companies are designed and operated in a manner intended 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 its facilities or the industry in general, could also cause TECO Energy to incur additional security-and insurance-related costs, and could have adverse effects on its business and financial results and condition.
Potential competitive changes may adversely affect TECO Energy’s regulated electric and gas businesses
There is competition in wholesale power sales across the United States. 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 a number of years. Gas services provided by TECO Energy’s gas utilities are unbundled for all non-residential customers. Because its gas utilities earn margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted TECO Energy’s results. However, future structural changes could adversely affect PGS and NMGC.
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Increased customer use of distributed generation could adversely affect TECO Energy’s regulated electric utility business
In many areas of the United States 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 Clean Power Plan could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule.
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 that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.
The value of TECO Energy’s 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 US 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 TECO Energy’s existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and it would reduce future tax payments received by TECO Energy from its subsidiaries.
TECO Energy relies on some natural gas transmission assets that it does not own or control to deliver natural gas. If transmission is disrupted, or if capacity is inadequate, TECO Energy’s ability to sell and deliver natural gas and supply natural gas to its customers and its electric generating stations may be hindered
TECO Energy depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets, as well as the natural gas it purchases for use in its electric generation facilities. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations could be adversely affected.
Disruption of fuel supply could have an adverse impact on the financial condition of TECO Energy
Tampa Electric, PGS and NMGC depend on third parties to supply fuel, including natural gas and coal. As a result, there are risks of supply interruptions and fuel price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams, pipeline failures or other events could impair the ability to deliver electricity or gas or generate electricity and could adversely affect operations. Further, the loss of coal suppliers or the inability to renew existing coal and natural gas contracts at favourable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TECO Energy and those of Emera following the Acquisition.
Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses
TECO Energy’s businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes in the availability of these commodities could affect the prices charged by suppliers as well as suppliers’ operating costs and the competitive positions 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 of 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.
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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 positions of PGS and NMGC as compared to electricity, other forms of energy and other gas suppliers.
The facilities and operations of TECO Energy could be affected by natural disasters or other catastrophic events
TECO Energy’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures, vandalism, potentially catastrophic events such as the occurrence of a major accident or incident at one of the sites, and other events beyond the control of TECO Energy. The operation of transmission and distribution systems involves certain risks, including gas leaks, fires, explosions, pipeline ruptures and other hazards and risks that may cause unforeseen interruptions, personal injury or property damage. Any such incident could have an adverse effect on TECO Energy and any costs relating to such events may not be recoverable through insurance or recovered in rates. In certain cases, there is potential that such an event may not excuse TECO Energy’s utility subsidiaries from servicing customers as required by their respective tariffs. In addition, TECO Energy may not be able to recover losses resulting from such events through insurance or rates.
The franchise rights held by TECO Energy’s subsidiaries could be lost in the event of a breach by such TECO Energy subsidiary or could expire and not be renewed
TECO Energy’s subsidiaries hold franchise rights that are memorialized in agreements with selected counterparties throughout the subsidiaries’ service areas. In some cases these rights could be lost in the event of a breach of these agreements by such TECO Energy subsidiary. In addition, these agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Selected agreements also contain provisions allowing municipalities to purchase the portion of the applicable utility’s system located within a given municipality’s boundaries under certain conditions.
Tampa Electric, PGS and NMGC may not be able to secure adequate ROW to construct transmission lines, gas interconnection lines and distribution related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers
Tampa Electric, PGS and NMGC rely on federal, state and local governmental agencies and, in particular in New Mexico, cooperation with local Native American tribes and councils to secure right-of-way and siting permits to construct transmission lines, gas interconnection lines and distribution-related facilities. If adequate ROW and siting permits to build new transportation and transmission lines cannot be secured:
• | Tampa Electric, PGS and NMGC may need to remove its facilities, or abandon its facilities on, the property covered by ROW or franchises and seek alternative locations for its transmission or distribution facilities; |
• | Tampa Electric, PGS and NMGC may need to rely on more costly alternatives to provide energy to their customers; |
• | Tampa Electric, PGS and NMGC may not be able to maintain reliability in their service areas; or |
• | Tampa Electric’s, PGS’s and NMGC’s ability to provide electric or gas service to new customers may be negatively impacted. |
Impairment testing of certain long-lived assets could result in impairment charges
TECO Energy assesses 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, TECO Energy may be required to record non-cash impairment charges that could have a material adverse impact on TECO Energy’s financial condition and results from operations. In connection with the NMGC acquisition, TECO Energy recorded additional goodwill and long-lived assets that could become impaired.
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TECO Energy has substantial indebtedness, which could adversely affect its financial condition and financial flexibility
TECO Energy has substantial indebtedness, which has resulted in fixed charges it is obligated to pay. The level of TECO Energy’s indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing.
TECO Energy, TECO Finance, Inc. (“TECO Finance”), TEC, NMGC and NMGI must meet certain financial covenants as defined in the applicable agreements to borrow under their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments.
Although TECO Energy was in compliance with all required financial covenants as of March 31, 2016, it cannot assure compliance with these financial covenants in the future. TECO Energy’s failure to comply with any of these covenants or to meet its 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. TECO Energy may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a portion of its outstanding obligations. If TECO Energy’s cash flows and capital resources are insufficient to fund its debt service obligations, it may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance its indebtedness. TECO Energy’s ability to restructure or refinance its debt will depend on the condition of the capital markets and TECO Energy’s financial condition at such time. Any refinancing of TECO Energy’s debt could be at higher interest rates and may require TECO Energy to comply with more onerous covenants, which could further restrict TECO Energy’s business operations. The terms of existing or future debt instruments may restrict TECO Energy from adopting some of these alternatives.
TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates that do not appear on its balance sheet. Such obligations include guarantees, letters of credit and certain other types of contractual commitments.
Financial market conditions could limit TECO Energy’s access to capital and increase TECO Energy’s costs of borrowing or refinancing, or have other adverse effects on its results
TECO Finance and TEC have debt maturing in 2017 and subsequent years which may need to be refinanced. Future financial market conditions could limit TECO Energy’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings. If TECO Energy is not able to issue new debt, or TECO Energy issues debt at interest rates higher than expected, its financial results or condition could be adversely affected.
TECO Energy enters 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
TECO Energy enters into derivative transactions with counterparties, most of which are financial institutions, to hedge its exposure to commodity price and interest rate changes. Although TECO Energy believes it has appropriate credit policies in place to manage the non-performance risk associated with these transactions, 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 TECO Energy has an in-the-money position, TECO Energy could be unable to collect from such counterparty.
Declines in the financial markets or in interest rates used to determine benefit obligations could increase TECO Energy’s pension expense or the required cash contributions to maintain required levels of funding for its plan
Under calculation requirements of the Pension Protection Act of 2006, as amended, as of the January 1, 2016 measurement date, TECO Energy’s pension plan was essentially fully funded. Under Moving Ahead for Progress in the 21st Century Act, TECO Energy is not required to make additional cash contributions over the next five years; however TECO Energy may make additional cash contributions from time to time. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund its pension plan in the future, and could cause pension expense to increase.
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TECO Energy’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast
In 2016, TECO Energy is 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. TECO Energy is 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 are expected to support customer and system reliability and expansion.
If TECO Energy’s capital expenditures exceed the forecasted levels, it may need to draw on credit facilities or access the capital markets on unfavourable terms. TECO Energy cannot be sure that it will be able to obtain additional financing, in which case its financial position could be adversely affected.
TECO Energy’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade and TECO Energy cannot be assured of any rating improvements in the future
TECO Energy’s senior unsecured debt is rated as investment grade by S&P at ‘BBB’, by Moody’s at ‘Baa2’, and by Fitch at ‘BBB’. The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A3’ 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, Moody’s and Fitch, may affect TECO Energy’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. TECO Energy may also experience greater interest expense than it would have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any downgrades. In addition, downgrades could adversely affect TECO Energy’s 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, as applicable, could be required to post collateral to support their purchases of electricity and gas.
In connection with the sale of TECO Coal to Cambrian, TECO Energy temporarily retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the completion of the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia
These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal’s mining operations. Payments by TECO Energy to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder or TECO Coal or one of the affiliates transferred to Cambrian as part of the sale did not pay the surety company. Pursuant to the TECO Coal purchase agreement for the sale of TECO Coal to Cambrian, Cambrian is obligated to file applications required in connection with the change of ownership and control of TECO Coal and its affiliates with the appropriate governmental entities with respect to the coal mining permits. Pursuant to the terms of the TECO Coal purchase agreement, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond(s) secured by the TECO Energy indemnity for that permit. TECO Energy is working with Cambrian on the process of replacing the bond. However, until the bonds secured by TECO Energy’s indemnity are released, TECO Energy’s indemnity will remain effective.
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SCHEDULE B
AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF TECO ENERGY AS AT
AND FOR THE YEARS ENDED DECEMBER 31, 2015 AND DECEMBER 31, 2014
TECO ENERGY, INC.
Report of Independent Registered Certified Public Accounting Firm
To the Board of Directors and Shareholders of TECO Energy, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, capital and cash flows present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Tampa, Florida
February 26, 2016
B-1
TECO ENERGY, INC.
Consolidated Balance Sheets
Assets (millions) | Dec. 31, 2015 | Dec. 31, 2014 | ||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 23.8 | $ | 25.4 | ||||
Receivables, less allowance for uncollectibles of $2.1 and $2.1 at Dec. 31, 2015 and 2014, respectively | 280.7 | 299.8 | ||||||
Inventories, at average cost | ||||||||
Fuel | 113.4 | 96.4 | ||||||
Materials and supplies | 76.8 | 75.4 | ||||||
Regulatory assets | 44.8 | 53.6 | ||||||
Deferred income taxes | 0.0 | 72.8 | ||||||
Prepayments and other current assets | 30.8 | 22.6 | ||||||
Assets held for sale | 0.0 | 109.6 | ||||||
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Total current assets | 570.3 | 755.6 | ||||||
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Property, plant and equipment | ||||||||
Utility plant in service | ||||||||
Electric | 7,270.3 | 7,094.8 | ||||||
Gas | 2,113.8 | 1,984.6 | ||||||
Construction work in progress | 794.7 | 640.0 | ||||||
Other property | 15.9 | 14.5 | ||||||
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Property, plant and equipment, at original costs | 10,194.7 | 9,733.9 | ||||||
Accumulated depreciation | (2,712.9 | ) | (2,645.7 | ) | ||||
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Total property, plant and equipment, net | 7,481.8 | 7,088.2 | ||||||
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Other assets | ||||||||
Regulatory assets | 395.2 | 348.5 | ||||||
Goodwill | 408.4 | 408.3 | ||||||
Deferred charges and other assets | 77.8 | 36.6 | ||||||
Assets held for sale | 0.0 | 59.8 | ||||||
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Total other assets | 880.9 | 853.2 | ||||||
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Total assets | $ | 8,933.5 | $ | 8,697.0 | ||||
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The accompanying notes are an integral part of the consolidated financial statements.
B-2
TECO ENERGY, INC.
Consolidated Balance Sheets – continued
Liabilities and Capital (millions) | Dec. 31, 2015 | Dec. 31, 2014 | ||||||
Current liabilities | ||||||||
Long-term debt due within one year | $ | 333.3 | $ | 274.5 | ||||
Notes payable | 247.0 | 139.0 | ||||||
Accounts payable | 255.4 | 288.6 | ||||||
Customer deposits | 182.1 | 176.2 | ||||||
Regulatory liabilities | 84.8 | 57.0 | ||||||
Derivative liabilities | 24.1 | 36.6 | ||||||
Interest accrued | 36.2 | 39.9 | ||||||
Taxes accrued | 13.2 | 29.9 | ||||||
Other | 22.6 | 16.8 | ||||||
Liabilities associated with assets held for sale | 0.0 | 39.4 | ||||||
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Total current liabilities | 1,198.7 | 1,097.9 | ||||||
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Other liabilities | ||||||||
Deferred income taxes | 570.7 | 519.2 | ||||||
Investment tax credits | 10.5 | 9.0 | ||||||
Regulatory liabilities | 715.8 | 729.0 | ||||||
Derivative liabilities | 2.1 | 6.1 | ||||||
Deferred credits and other liabilities | 387.4 | 370.9 | ||||||
Liabilities associated with assets held for sale | 0.0 | 65.4 | ||||||
Long-term debt, less amount due within one year | 3,489.2 | 3,324.8 | ||||||
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Total other liabilities | 5,175.8 | 5,024.4 | ||||||
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Commitments and Contingencies (see Note 12) | ||||||||
Capital | ||||||||
Common equity (400.0 million shares authorized; par value $1; 235.3 million and 234.9 million shares outstanding at Dec. 31, 2015 and 2014, respectively) | 235.3 | 234.9 | ||||||
Additional paid in capital | 1,894.5 | 1,875.9 | ||||||
Retained earnings | 441.4 | 479.6 | ||||||
Accumulated other comprehensive loss | (12.2 | ) | (15.7 | ) | ||||
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Total TECO Energy capital | 2,559.0 | 2,574.7 | ||||||
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Total liabilities and capital | $ | 8,933.5 | $ | 8,697.0 | ||||
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The accompanying notes are an integral part of the consolidated financial statements.
B-3
TECO ENERGY, INC.
Consolidated Statements of Income
(millions, except per share amounts) For the years ended Dec. 31, | 2015 | 2014 | 2013 | |||||||||||||
Revenues | ||||||||||||||||
Regulated electric | $ | 2,014.9 | $ | 2,019.9 | $ | 1,949.6 | ||||||||||
Regulated gas | 716.8 | 537.4 | 392.9 | |||||||||||||
Unregulated | 11.8 | 9.1 | 12.6 | |||||||||||||
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Total revenues | 2,743.5 | 2,566.4 | 2,355.1 | |||||||||||||
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Expenses | ||||||||||||||||
Regulated operations and maintenance | ||||||||||||||||
Fuel | 638.6 | 692.3 | 680.2 | |||||||||||||
Purchased power | 78.9 | 71.4 | 64.7 | |||||||||||||
Cost of natural gas sold | 271.6 | 209.7 | 142.2 | |||||||||||||
Other | 613.2 | 547.8 | 524.4 | |||||||||||||
Operation and maintenance other expense | 22.7 | 29.5 | 12.5 | |||||||||||||
Depreciation and amortization | 349.0 | 315.3 | 291.8 | |||||||||||||
Taxes, other than income | 207.4 | 195.0 | 184.7 | |||||||||||||
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Total expenses | 2,181.4 | 2,061.0 | 1,900.5 | |||||||||||||
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Income from operations | 562.1 | 505.4 | 454.6 | |||||||||||||
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Other income (expense) | ||||||||||||||||
Allowance for other funds used during construction | 17.4 | 10.5 | 6.3 | |||||||||||||
Other income | 3.4 | 0.5 | 1.8 | |||||||||||||
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Total other income | 20.8 | 11.0 | 8.1 | |||||||||||||
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Interest charges | ||||||||||||||||
Interest expense | 195.1 | 176.4 | 165.0 | |||||||||||||
Allowance for borrowed funds used during construction | (8.7 | ) | (5.3 | ) | (3.6 | ) | ||||||||||
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Total interest charges | 186.4 | 171.1 | 161.4 | |||||||||||||
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Income from continuing operations before provision for income taxes | 396.5 | 345.3 | 301.3 | |||||||||||||
Provision for income taxes | 155.3 | 138.9 | 112.6 | |||||||||||||
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Net income from continuing operations | 241.2 | 206.4 | 188.7 | |||||||||||||
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Discontinued operations | ||||||||||||||||
Income (loss) from discontinued operations | (106.3 | ) | (125.4 | ) | 5.2 | |||||||||||
Provision (benefit) for income taxes | (38.6 | ) | (49.4 | ) | (3.8 | ) | ||||||||||
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Income (loss) from discontinued operations, net | (67.7 | ) | (76.0 | ) | 9.0 | |||||||||||
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Net income | $ | 173.5 | $ | 130.4 | $ | 197.7 | ||||||||||
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Average common shares outstanding | – Basic | 233.1 | 223.1 | 215.0 | ||||||||||||
– Diluted | 234.5 | 223.7 | 215.5 | |||||||||||||
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Earnings per share from continuing operations | – Basic | $ | 1.03 | $ | 0.92 | $ | 0.88 | |||||||||
– Diluted | $ | 1.03 | $ | 0.92 | $ | 0.88 | ||||||||||
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Earnings per share from discontinued operations | – Basic | $ | (0.29 | ) | $ | (0.34 | ) | $ | 0.04 | |||||||
– Diluted | $ | (0.29 | ) | $ | (0.34 | ) | $ | 0.04 | ||||||||
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Earnings per share | – Basic | $ | 0.74 | $ | 0.58 | $ | 0.92 | |||||||||
– Diluted | $ | 0.74 | $ | 0.58 | $ | 0.92 | ||||||||||
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Dividends paid per common share outstanding | $ | 0.90 | $ | 0.88 | $ | 0.88 | ||||||||||
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Amounts shown include reclassifications to reflect discontinued operations as discussed inNote 19.
The accompanying notes are an integral part of the consolidated financial statements.
B-4
TECO ENERGY, INC.
Consolidated Statements of Comprehensive Income
(millions) For the years ended Dec. 31, | 2015 | 2014 | 2013 | |||||||||
Net income | $ | 173.5 | $ | 130.4 | $ | 197.7 | ||||||
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Other comprehensive income (loss), net of tax | ||||||||||||
Gain on cash flow hedges | 3.5 | 0.7 | 1.4 | |||||||||
Amortization of unrecognized benefit costs and other | 2.1 | (3.0 | ) | 14.8 | ||||||||
Change in benefit obligation due to valuation | (9.8 | ) | 8.0 | 0.0 | ||||||||
Increase in unrecognized postemployment costs | 0.0 | (8.2 | ) | 0.0 | ||||||||
Recognized benefit costs due to settlement | 7.7 | 0.0 | 1.6 | |||||||||
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Other comprehensive income (loss), net of tax | 3.5 | (2.5 | ) | 17.8 | ||||||||
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Comprehensive income | $ | 177.0 | $ | 127.9 | $ | 215.5 | ||||||
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The accompanying notes are an integral part of the consolidated financial statements.
B-5
TECO ENERGY, INC.
Consolidated Statements of Cash Flows
(millions) For the years ended Dec. 31, | 2015 | 2014 | 2013 | |||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 173.5 | $ | 130.4 | $ | 197.7 | ||||||
Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
Depreciation and amortization | 350.2 | 341.9 | 329.5 | |||||||||
Deferred income taxes and investment tax credits | 117.5 | 89.4 | 110.1 | |||||||||
Allowance for other funds used during construction | (17.4 | ) | (10.5 | ) | (6.3 | ) | ||||||
Non-cash stock compensation | 13.1 | 12.7 | 13.5 | |||||||||
Loss (gain) on disposals of business/assets | 13.2 | (0.2 | ) | (1.6 | ) | |||||||
Deferred recovery clauses | 26.4 | (15.2 | ) | (6.2 | ) | |||||||
Asset impairment | 78.6 | 115.9 | 0.0 | |||||||||
Receivables, less allowance for uncollectibles | 36.0 | (36.6 | ) | (4.5 | ) | |||||||
Inventories | (22.6 | ) | 12.8 | 1.1 | ||||||||
Prepayments and other current assets | (8.0 | ) | 2.8 | (2.2 | ) | |||||||
Taxes accrued | (15.9 | ) | 1.1 | 1.4 | ||||||||
Interest accrued | (3.6 | ) | 7.3 | (1.3 | ) | |||||||
Accounts payable | (61.6 | ) | 23.4 | 35.9 | ||||||||
Other | (69.8 | ) | (10.4 | ) | (8.5 | ) | ||||||
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Cash flows from operating activities | 609.6 | 664.8 | 658.6 | |||||||||
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Cash flows from investing activities | ||||||||||||
Capital expenditures | (739.7 | ) | (703.8 | ) | (526.1 | ) | ||||||
Purchase of NMGI, net of cash acquired | 0.0 | (751.5 | ) | 0.0 | ||||||||
Net proceeds from sales of business/assets | 0.0 | 0.2 | 4.3 | |||||||||
Other investments | (0.3 | ) | (7.9 | ) | 0.0 | |||||||
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Cash flows used in investing activities | (740.0 | ) | (1,463.0 | ) | (521.8 | ) | ||||||
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Cash flows from financing activities | ||||||||||||
Dividends paid | (211.7 | ) | (199.2 | ) | (191.2 | ) | ||||||
Proceeds from the sale of common stock | 7.3 | 302.3 | 6.7 | |||||||||
Proceeds from long-term debt issuance | 499.7 | 563.6 | 0.0 | |||||||||
Repayment of long-term debt/Purchase in lieu of redemption | (274.5 | ) | (83.3 | ) | (51.6 | ) | ||||||
Change in short-term debt | 108.0 | 55.0 | 84.0 | |||||||||
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Cash flows from/(used in) financing activities | 128.8 | 638.4 | (152.1 | ) | ||||||||
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Net decrease in cash and cash equivalents | (1.6 | ) | (159.8 | ) | (15.3 | ) | ||||||
Cash and cash equivalents at beginning of the year | 25.4 | 185.2 | 200.5 | |||||||||
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Cash and cash equivalents at end of the year | $ | 23.8 | $ | 25.4 | $ | 185.2 | ||||||
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Supplemental disclosure of cash flow information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest | $ | 179.6 | $ | 161.3 | $ | 161.0 | ||||||
Income taxes paid | $ | 14.5 | $ | 2.9 | $ | 1.8 | ||||||
Supplemental disclosure of non-cash activities | ||||||||||||
Debt assumed in NMGI acquisition | $ | 0.0 | $ | 200.0 | $ | 0.0 | ||||||
Change in accrued capital expenditures | $ | 8.0 | $ | 13.3 | $ | 4.7 |
The accompanying notes are an integral part of the consolidated financial statements.
B-6
TECO ENERGY, INC.
Consolidated Statements of Capital
Accumulated | ||||||||||||||||||||||||
Additional | Other | |||||||||||||||||||||||
Common | Paid in | Retained | Comprehensive | Total | ||||||||||||||||||||
(millions) | Shares | Stock | Capital | Earnings | Income (Loss) | Capital | ||||||||||||||||||
Balance, Dec. 31, 2012 | 216.6 | $ | 216.6 | $ | 1,564.5 | $ | 541.7 | $ | (31.0 | ) | $ | 2,291.8 | ||||||||||||
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Net income | 197.7 | 197.7 | ||||||||||||||||||||||
Other comprehensive income, after tax | 17.8 | 17.8 | ||||||||||||||||||||||
Common stock issued | 0.7 | 0.7 | 5.2 | 5.9 | ||||||||||||||||||||
Cash dividends declared | (191.2 | ) | (191.2 | ) | ||||||||||||||||||||
Stock compensation expense | 13.5 | 13.5 | ||||||||||||||||||||||
Restricted stock—dividends | 1.0 | 0.1 | 1.1 | |||||||||||||||||||||
Tax short fall—stock compensation | (2.9 | ) | (2.9 | ) | ||||||||||||||||||||
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Balance, Dec. 31, 2013 | 217.3 | $ | 217.3 | $ | 1,581.3 | $ | 548.3 | $ | (13.2 | ) | $ | 2,333.7 | ||||||||||||
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Net income | 130.4 | 130.4 | ||||||||||||||||||||||
Other comprehensive income, after tax | (2.5 | ) | (2.5 | ) | ||||||||||||||||||||
Common stock issued | 17.6 | 17.6 | 283.2 | 300.8 | ||||||||||||||||||||
Cash dividends declared | (199.2 | ) | (199.2 | ) | ||||||||||||||||||||
Stock compensation expense | 12.7 | 12.7 | ||||||||||||||||||||||
Restricted stock—dividends | 1.1 | 0.1 | 1.2 | |||||||||||||||||||||
Tax short fall—stock compensation | (2.4 | ) | (2.4 | ) | ||||||||||||||||||||
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Balance, Dec. 31, 2014 | 234.9 | $ | 234.9 | $ | 1,875.9 | $ | 479.6 | $ | (15.7 | ) | $ | 2,574.7 | ||||||||||||
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Net income | 173.5 | 173.5 | ||||||||||||||||||||||
Other comprehensive loss, after tax | 3.5 | 3.5 | ||||||||||||||||||||||
Common stock issued | 0.4 | 0.4 | 4.6 | 5.0 | ||||||||||||||||||||
Cash dividends declared | (211.7 | ) | (211.7 | ) | ||||||||||||||||||||
Stock compensation expense | 13.1 | 13.1 | ||||||||||||||||||||||
Restricted stock—dividends | 1.3 | 1.3 | ||||||||||||||||||||||
Tax short fall—stock compensation | (0.4 | ) | (0.4 | ) | ||||||||||||||||||||
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Balance, Dec. 31, 2015 | 235.3 | $ | 235.3 | $ | 1,894.5 | $ | 441.4 | $ | (12.2 | ) | $ | 2,559.0 | ||||||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
B-7
TECO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
Description of the Business
TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC.
TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida.
NMGC, a Delaware corporation and wholly owned subsidiary of NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico.
On Sept. 21, 2015, TECO Diversified sold all of its ownership interest in TECO Coal. TECO Coal, a Kentucky LLC, had subsidiaries which owned assets in Eastern Kentucky, Tennessee and Virginia. These entities owned mineral rights, owned or operated surface and underground mines and owned interests in coal processing and loading facilities. SeeNote 19 for further information.
On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. SeeNote 21 for further information.
The company’s significant accounting policies are as follows:
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of TECO Energy and its majority-owned subsidiaries. Intercompany balances and intercompany transactions have been eliminated in consolidation.
The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Dec. 31, 2015 (seeNote 21). 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 and TECO Diversified that directly related to TECO Coal and TECO Guatemala (seeNote 19).
For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (seeNote 18).
Through its centralized services company subsidiary, TSI, TECO Energy provides its operating subsidiaries with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to the applicable operating subsidiaries using cost-causative allocation methods. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of total operating revenues, total operating assets and net income as the basis of allocation. TSI has losses related to taxes which are not distributed to affiliate companies. The results of TECO Energy’s corporate operations, consisting of TSI tax losses and non-allocable Parent costs, are included within the “Other” reportable segment (seeNote 14).
Use of Estimates
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.
Cash Equivalents
Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
B-8
Property, Plant and Equipment
Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Tampa Electric, PGS and NMGC, concurrent with a planned major maintenance outage or with new construction, capitalize the cost of adding or replacing retirement units-of-property in conformity with the regulations of FERC, FPSC and NMPRC, as applicable. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.
In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.
Depreciation
Tampa Electric, PGS and NMGC compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:
• | the group remaining life method, approved by the FPSC or NMPRC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; |
• | the amortizable life method, approved by the FPSC or NMPRC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. |
The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 3.6% for 2014 and 3.7% for 2013. Construction work in progress is not depreciated until the asset is completed or placed in service.
On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.
Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:
Asset | Estimated Useful Lives | |||
Building and improvements | 40 years | |||
Office equipment and furniture | 4 - 7 years | |||
Computer software | 3 - 15 years |
Total depreciation expense for the years ended Dec. 31, 2015, 2014 and 2013 was $339.1 million, $307.5 million and $285.6 million, respectively.
Allowance for Funds Used During Construction
AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate Tampa Electric’s AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. Tampa Electric’s rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. NMGC’s rate used to calculate its AFUDC in 2015 and 2014 was 4.41% and 4.92%, respectively. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $26.1 million, $15.8 million and $9.9 million, respectively.
Inventory
TEC and NMGC value materials, supplies and fossil fuel inventory (coal, oil or natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.
B-9
Fuel Inventory (millions) | Dec. 31, 2015 | Dec. 31, 2014 | ||||||
TEC | $ | 105.6 | $ | 85.2 | ||||
NMGC | 7.8 | 11.2 | ||||||
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Total | $ | 113.4 | $ | 96.4 | ||||
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TECO Coal inventories were stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories were stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory was classified within Assets held for sale at Dec. 31, 2014.
Regulatory Assets and Liabilities
Tampa Electric, PGS and NMGC are subject to accounting guidance for the effects of certain types of regulation (seeNote 3 for additional details).
Deferred Income Taxes
TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (seeNote 4 for additional details).
Investment Tax Credits
ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
Goodwill
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Under the accounting guidance for goodwill, goodwill is subject to an annual assessment for impairment at the reporting unit level. SeeNote 20for further detail.
Employee Postretirement Benefits
The company sponsors a defined benefit retirement plan and other postretirement benefits. The measurement of the plans are based on several statistical and other factors, including those that attempt to anticipate future events. SeeNote 5for further detail.
Revenue Recognition
TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
The regulated utilities’ retail businesses and the prices charged to customers are regulated by the FPSC or NMPRC, as applicable. Tampa Electric’s wholesale business is regulated by the FERC. SeeNote 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.
Revenues for energy marketing operations at TECO EnergySource, Inc. are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. Accordingly, for the years ended Dec. 31, 2015, 2014 and 2013, total costs of $3.1 million, $4.3 million and $23.1 million, respectively, consisting primarily of natural gas purchased, were netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income.
B-10
Revenues for TECO Coal shipments, both domestic and international, were recognized when title and risk of loss transfer to the customer. They were included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.
Revenues and Cost Recovery
Revenues include amounts resulting from cost recovery clauses at the regulated utilities (Tampa Electric, PGS and NMGC) which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, gas storage, interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.
Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (seeNote 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $81.1 million and $86.6 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31, 2015, 2014 and 2013, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
Receivables and Allowance for Uncollectible Accounts
Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on the regulated utilities’ collection experience. Circumstances that could affect Tampa Electric’s, PGS’s and NMGC’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
TECO Coal’s receivables, which were classified within Assets held for sale at Dec. 31, 2014, consisted of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts was established based on TECO Coal’s collection experience. Circumstances that could have affected TECO Coal’s estimates of uncollectible receivables included customer credit issues and general economic conditions. Accounts were written off once they were determined to be uncollectible.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts
Tampa Electric and PGS are allowed to recover certain costs on a dollar-for-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 Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, 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 Statement of Income.
TECO Energy’s excise taxes were accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they were not specifically recovered through revenues. Excise taxes paid by the regulated utilities were not material and were expensed when incurred.
Deferred Charges and Other Assets
Deferred charges and other assets consist primarily of a contribution made by the company in order to fully fund its SERP obligation (seeNote 5), unamortized debt issuance costs and assets related to NMGC’s ROW.
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Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.
NMGC’s ROW-Gross assets related to NMGC’s ROW were $41 million at Dec. 31, 2015 and 2014. The related accumulated amortization was $9 million and $8 million at Dec. 31, 2015 and 2014, respectively. The company amortizes costs related to obtaining NMGC’s ROW to “Depreciation and amortization expense” on TECO Energy’s Consolidated Statements of Income.
Deferred Credits and Other Liabilities
Deferred credits and other liabilities primarily include the accrued postretirement and pension liabilities (seeNote 5), MGP environmental remediation liability (seeNote 12), and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively.
Stock-Based Compensation
TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). SeeNote 9 for more information on share-based payments.
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 Statements of Cash Flows.
Reclassifications
Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period.
2. New Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, 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 for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.
Presentation of Debt Issuance Costs
In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015 and Dec. 31, 2014, the company classified $27.7 million and $29.2 million, respectively, of debt issuance costs, which do not include costs for line-of-credit
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arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.
Disclosure of Investments Using Net Asset Value
In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed inNote 5. This standard will be required for the company beginning in 2016. As early adoption is permitted, the company adopted the standard for its 2015 fiscal year and applied the presentation on a retrospective basis for all periods presented in the pension plan assets fair value hierarchy. The guidance did not affect the company’s balance sheets, results of operations or cash flows.
Measurement Period Adjustments in Business Combinations
In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The guidance will not affect the company’s current financial statements. However, the company will assess the potential impact of the guidance on future acquisitions.
Balance Sheet Classification of Deferred Taxes
In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for the company beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, the company adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect the company’s results of operations or cash flows.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. 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, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.
Leases
In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The dual model for income statement classification is maintained under the new guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.
3. Regulatory
Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. 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.
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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.
Base Rates-Tampa Electric
Tampa Electric’s results for the first ten months of 2013 reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.
Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.
This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would 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 rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is 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 retroactive to Jan. 1, 2013.
Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.
Tampa Electric Storm Damage Cost Recovery
Prior to the above-mentioned stipulation and settlement agreement, Tampa Electric was accruing $8.0 million annually to a 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 Dec. 31, 2015 and 2014.
Base Rates-PGS
PGS’s base rates were established in May 2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.
Base Rates-NMGC
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 a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017, as reported inNote 21.
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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.
Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table:
Dec. 31, | Dec. 31, | |||||||
(millions) | 2015 | 2014 | ||||||
Regulatory assets: | ||||||||
Regulatory tax asset(1) | $ | 74.7 | $ | 69.2 | ||||
Cost-recovery clauses - deferred balances(2) | 5.5 | 1.9 | ||||||
Cost-recovery clauses - offsets to derivative liabilities(2) | 26.5 | 43.2 | ||||||
Environmental remediation(3) | 54.0 | 53.1 | ||||||
Postretirement benefits(4) | 240.6 | 194.0 | ||||||
Deferred bond refinancing costs(5) | 6.5 | 7.2 | ||||||
Debt basis adjustment(6) | 17.5 | 20.9 | ||||||
Competitive rate adjustment(2) | 2.6 | 2.8 | ||||||
Other | 12.1 | 9.8 | ||||||
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Total regulatory assets | 440.0 | 402.1 | ||||||
Less: Current portion | 44.8 | 53.6 | ||||||
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Long-term regulatory assets | $ | 395.2 | $ | 348.5 | ||||
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Regulatory liabilities: | ||||||||
Regulatory tax liability | $ | 7.9 | $ | 6.9 | ||||
Cost-recovery clauses(2) | 55.9 | 25.9 | ||||||
Transmission and delivery storm reserve | 56.1 | 56.1 | ||||||
Accumulated reserve—cost of removal(7) | 679.9 | 695.2 | ||||||
Other | 0.8 | 1.9 | ||||||
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Total regulatory liabilities | 800.6 | 786.0 | ||||||
Less: Current portion | 84.8 | 57.0 | ||||||
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Long-term regulatory liabilities | $ | 715.8 | $ | 729.0 | ||||
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(1) | The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. |
(2) | These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. |
(3) | This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. |
(4) | This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. |
(5) | This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. |
(6) | This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. |
(7) | This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. |
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4. Income Taxes
Income Tax Expense
In 2015, 2014 and 2013, TECO Energy recorded net tax provisions from continuing operations of $155.3 million, $138.9 million and $112.6 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes and prior year audits in 2015, 2014 and 2013 were $14.5 million, $2.9 million and $1.8 million, respectively.
Income tax expense consists of the following:
Income Tax Expense (Benefit)
(millions) For the year ended Dec. 31, | 2015 | 2014 | 2013 | |||||||||
Continuing Operations | ||||||||||||
Current income taxes | ||||||||||||
Federal | $ | (0.5 | ) | $ | 0.5 | $ | 2.2 | |||||
State | 0.0 | 0.0 | 0.0 | |||||||||
Deferred income taxes | ||||||||||||
Federal | 133.2 | 111.0 | 98.8 | |||||||||
State | 21.1 | 27.7 | 11.9 | |||||||||
Amortization of investment tax credits | 1.5 | (0.3 | ) | (0.3 | ) | |||||||
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Income tax expense from continuing operations | 155.3 | 138.9 | 112.6 | |||||||||
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Discontinued Operations | ||||||||||||
Current income taxes | ||||||||||||
Federal | 0.0 | 0.0 | 0.0 | |||||||||
State | (0.3 | ) | (0.4 | ) | (3.5 | ) | ||||||
Deferred income taxes | ||||||||||||
Federal | (34.7 | ) | (44.0 | ) | (0.3 | ) | ||||||
State | (3.6 | ) | (5.0 | ) | 0.0 | |||||||
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Income tax expense from discontinued operations | (38.6 | ) | (49.4 | ) | (3.8 | ) | ||||||
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Total income tax expense | $ | 116.7 | $ | 89.5 | $ | 108.8 | ||||||
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During 2015, 2014 and 2013, TECO Energy increased its net operating loss carryforward.
The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:
Effective Income Tax Rate
(millions) For the year ended Dec. 31, | 2015 | 2014 | 2013 | |||||||||
Income tax expense at the federal statutory rate of 35% | $ | 138.8 | $ | 120.9 | $ | 105.5 | ||||||
Increase (decrease) due to: | ||||||||||||
State income tax, net of federal income tax | 13.6 | 17.0 | 7.5 | |||||||||
Valuation allowance | 0.1 | 0.9 | 0.0 | |||||||||
Other | 2.8 | 0.1 | (0.4 | ) | ||||||||
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Total income tax expense from continuing operations | $ | 155.3 | $ | 138.9 | $ | 112.6 | ||||||
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Income tax expense as a percent of income from continuing operations, before income taxes | 39.2 | % | 40.2 | % | 37.4 | % |
For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes. For 2015, the effective tax rate decreased as a result of a lower state consolidated tax adjustment, offset by a tax expense related to stock-based compensation.
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As discussed inNote 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2015 will be realized in future periods.
Deferred Income Taxes
The major components of the company’s deferred tax assets and liabilities recognized are as follows:
(millions) As of Dec. 31, | 2015 | 2014 | ||||||
Deferred tax liabilities(1) | ||||||||
Property related | $ | 1,519.3 | $ | 1,391.3 | ||||
Pension | 86.6 | 62.3 | ||||||
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Total deferred tax liabilities | 1,605.9 | 1,453.6 | ||||||
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Deferred tax assets(1) | ||||||||
Alternative minimum tax credit carryforward | 213.5 | 214.0 | ||||||
Loss and credit carryforwards (2) | 637.5 | 566.7 | ||||||
Other postretirement benefits | 69.5 | 71.5 | ||||||
Other | 117.5 | 159.6 | ||||||
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Total deferred tax assets | 1,038.0 | 1,011.8 | ||||||
Valuation allowance(3) | (2.0 | ) | (4.6 | ) | ||||
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Total deferred tax assets, net of valuation allowance | 1,036.0 | 1,007.2 | ||||||
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Total deferred tax liability, net | 569.9 | 446.4 | ||||||
Less: Current portion of deferred tax asset | 0.0 | (72.8 | ) | |||||
Less: Long term portion of deferred tax asset | (0.8 | ) | 0.0 | |||||
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Long-term portion of deferred tax liability, net | $ | 570.7 | $ | 519.2 | ||||
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(1) | Certain property related assets and liabilities have been netted. |
(2) | As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2015 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $2.6 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized. |
(3) | During 2015, the valuation allowance related to discontinued operations decreased from $3.6 million to $1.0 million. |
At Dec. 31, 2015, the company had cumulative unused federal, Florida and New Mexico NOLs for income tax purposes of $1,728.6 million, $675.2 million and $85.8 million, respectively, expiring at various times between 2025 and 2034, with the majority expiring in 2025. The federal NOL includes $121.6 million of NOLs due to the 2014 acquisition of NMGI. In addition, the company has unused general business credits of $5.8 million expiring between 2026 and 2034. During 2015, the company’s available AMT credit carryforward decreased from $214.0 million to $213.5 million. The AMT credit may be used indefinitely to reduce federal income taxes.
The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.
The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. At Dec. 31, 2014, a $4.6 million valuation allowance had been established for state NOL carryforwards and state deferred tax assets, net of federal tax. During 2015, the valuation allowance decreased by $2.6 million. As a result of the company’s sale of its 100% interest in TECO Coal, the company released a $3.6 million valuation allowance previously recorded in 2014 related to state NOL carryforwards and deferred tax assets, net of federal tax, with a corresponding write off of the gross deferred tax assets since the likelihood that the company will ever utilize those carryforwards is remote. The TECO Coal sale also generated a federal capital loss carryforward deferred tax asset of $1.0 million for which a full valuation allowance has been established due to the uncertainty of recognizing the benefit from this loss, before it expires in 2020.
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Unrecognized Tax Benefits
The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
(millions) | 2015 | 2014 | 2013 | |||||||||
Balance at Jan. 1, | $ | 0.0 | $ | 0.0 | $ | 2.9 | ||||||
Decreases due to expiration of statute of limitations | 0.0 | 0.0 | (2.9 | ) | ||||||||
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Balance at Dec. 31 | $ | 0.0 | $ | 0.0 | $ | 0.0 | ||||||
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The company recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2015, 2014 and 2013, the company recognized $0.0 million, $0.0 million and $(0.9) million, respectively, of pretax charges (benefits) for interest only. Additionally, the company did not have any accrued interest at Dec. 31, 2015 and 2014. No amounts have been recorded for penalties.
The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state and foreign 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. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.
5. Employee Postretirement Benefits
Pension Benefits
TECO Energy has a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.
Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.
TECO Coal participants ceased earning pension benefits on Sept. 21, 2015, the date of TECO Energy’s sale of TECO Coal. As a result of the sale, a curtailment loss in the Retirement Plan was recognized in the fourth quarter of 2014. See curtailment-related line items in tables below.
Other Postretirement Benefits
TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (Other Benefits or Other Postretirement Benefit Plan) for most employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.
MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.
The FASB issued accounting guidance and disclosure requirements related to MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.
B-18
In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2013. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.
Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan.
NMGC has a separate, partially-funded other postretirement benefit plan. It is not presented separately; rather, it is presented with TECO Energy’s plan in the tables and discussion below. Since NMGC is allowed to recover its other postretirement benefit costs through rates, the regulated asset established prior to the acquisition for pre-acquisition-related prior service cost, actuarial loss, and transition obligation was maintained after the acquisition. This regulated asset will be amortized. See “unrecognized costs in regulated asset acquired in business combination” line item in the “Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets” table below.
Effective Jan. 1, 2015, the TECO Coal participants were terminated from the Other Postretirement Benefit Plan. As a result, the other postretirement benefit obligation for TECO Coal was eliminated as of Dec. 31, 2014. See curtailment-related line items in tables below.
Obligations and Funded Status
TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC and NMGC. The results of operations are not impacted.
The following table provides a detail of the change in benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits).
Obligations and Plan Assets | Pension Benefits | Other Benefits | ||||||||||||||
(millions) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Change in benefit obligation | ||||||||||||||||
Net benefit obligation at beginning of year | $ | 728.9 | $ | 666.0 | $ | 201.5 | $ | 208.1 | ||||||||
Service cost | 20.9 | 18.3 | 2.2 | 2.5 | ||||||||||||
Interest cost | 30.3 | 32.0 | 8.2 | 10.8 | ||||||||||||
Plan participants’ contributions | 0.0 | 0.0 | 2.0 | 2.8 | ||||||||||||
Plan amendments | 0.0 | 0.0 | (3.7 | ) | (23.2 | ) | ||||||||||
Actuarial loss (gain) | 5.8 | 48.3 | (0.4 | ) | 1.5 | |||||||||||
Benefits paid | (53.0 | ) | (39.9 | ) | (14.6 | ) | (16.0 | ) | ||||||||
Transfer in due to the effect of business combination | 0.0 | 0.0 | 0.0 | 26.7 | ||||||||||||
Plan curtailment | 0.0 | 4.0 | 0.0 | (11.7 | ) | |||||||||||
Special termination benefit | 0.0 | 0.2 | 0.0 | 0.0 | ||||||||||||
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Net benefit obligation at end of year | $ | 732.9 | $ | 728.9 | $ | 195.2 | $ | 201.5 | ||||||||
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B-19
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 648.0 | $ | 593.0 | $ | 18.8 | $ | 0.0 | ||||||||
Actual return on plan assets | (25.5 | ) | 46.4 | (0.6 | ) | 0.1 | ||||||||||
Employer contributions | 55.0 | 47.5 | 1.5 | (1.0 | ) | |||||||||||
Employer direct benefit payments | 0.9 | 1.0 | 13.5 | 16.0 | ||||||||||||
Plan participants’ contributions | 0.0 | 0.0 | 2.0 | 2.8 | ||||||||||||
Transfer in due to acquisition | 0.0 | 0.0 | 0.0 | 16.9 | ||||||||||||
Benefits paid | (53.0 | ) | (39.9 | ) | (14.6 | ) | (16.0 | ) | ||||||||
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Fair value of plan assets at end of year(1) | $ | 625.4 | $ | 648.0 | $ | 20.6 | 18.8 | |||||||||
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(1) | The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years. |
At Dec. 31, the aggregate financial position for pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:
Funded Status
Pension Benefits | Other Benefits | |||||||||||||||
(millions) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Benefit obligation (PBO/APBO) | $ | 732.9 | $ | 728.9 | $ | 195.2 | $ | 201.5 | ||||||||
Less: Fair value of plan assets | 625.4 | 648.0 | 20.6 | 18.8 | ||||||||||||
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Funded status at end of year | $ | (107.5 | ) | $ | (80.9 | ) | $ | (174.6 | ) | $ | (182.7 | ) | ||||
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The accumulated benefit obligation for all defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.
The amounts recognized in the Consolidated Balance Sheets for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:
Amounts recognized in balance sheet
Pension Benefits | Other Benefits | |||||||||||||||
(millions) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Regulatory assets | $ | 208.2 | $ | 167.4 | $ | 32.4 | $ | 26.6 | ||||||||
Accrued benefit costs and other current liabilities | (10.5 | ) | (4.9 | ) | (10.7 | ) | (10.7 | ) | ||||||||
Deferred credits and other liabilities | (97.0 | ) | (76.0 | ) | (163.9 | ) | (172.0 | ) | ||||||||
Accumulated other comprehensive loss (income), pretax | 55.7 | 36.3 | (41.6 | ) | (34.6 | ) | ||||||||||
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Net amount recognized at end of year | $ | 156.4 | $ | 122.8 | $ | (183.8 | ) | $ | (190.7 | ) | ||||||
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Unrecognized gains and losses and prior service credits and costs are recorded in accumulated other comprehensive income for the non-regulated companies and regulatory assets for the regulated companies. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.
Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets
Pension Benefits | Other Benefits | |||||||||||||||
(millions) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Net actuarial loss | $ | 263.6 | $ | 203.7 | $ | 10.9 | $ | 9.6 | ||||||||
Prior service cost (credit) | 0.3 | 0.0 | (25.0 | ) | (23.6 | ) | ||||||||||
Unrecognized costs in regulated asset acquired in business combination | 0.0 | 0.0 | 4.9 | 6.0 | ||||||||||||
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Amount recognized, pretax | $ | 263.9 | $ | 203.7 | $ | (9.2 | ) | $ | (8.0 | ) | ||||||
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B-20
Assumptions used to determine benefit obligations at Dec. 31:
Pension Benefits | Other Benefits | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Discount rate | 4.688 | % | 4.258 | % | 4.669 | % | 4.211 | % | ||||||||
Rate of compensation increase—weighted | 3.87 | % | 3.87 | % | 2.50 | % | 3.86 | % | ||||||||
Healthcare cost trend rate | ||||||||||||||||
Immediate rate | n/a | n/a | 7.05 | % | 7.09 | % | ||||||||||
Ultimate rate | n/a | n/a | 4.50 | % | 4.57 | % | ||||||||||
Year rate reaches ultimate | n/a | n/a | 2038 | 2025 | ||||||||||||
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A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:
(millions) | 1% Increase | 1% Decrease | ||||||
Effect on postretirement benefit obligation | $ | 9.0 | $ | (7.7 | ) |
The discount rate assumption used to determine the Dec. 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets
Pension Benefits | Other Benefits | |||||||||||||||||||||||
(millions) | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||||||||
Service cost | $ | 20.9 | $ | 18.3 | $ | 18.2 | $ | 2.2 | $ | 2.5 | $ | 2.5 | ||||||||||||
Interest cost | 30.3 | 32.0 | 28.9 | 8.2 | 10.8 | 9.3 | ||||||||||||||||||
Expected return on plan assets | (43.3 | ) | (41.8 | ) | (38.4 | ) | (1.1 | ) | (0.3 | ) | 0.0 | |||||||||||||
Amortization of: | ||||||||||||||||||||||||
Actuarial loss | 15.1 | 13.5 | 20.5 | 0.0 | 0.2 | 1.0 | ||||||||||||||||||
Prior service (benefit) cost | (0.2 | ) | (0.4 | ) | (0.4 | ) | (2.4 | ) | (0.2 | ) | (0.4 | ) | ||||||||||||
Curtailment loss (gain) | 0.0 | 3.9 | 0.0 | 0.0 | (0.2 | ) | 0.0 | |||||||||||||||||
Special termination benefit | 0.0 | 0.2 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||||
Settlement loss | 0.0 | 0.0 | 1.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||||
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Net periodic benefit cost | $ | 22.8 | $ | 25.7 | $ | 29.8 | $ | 6.9 | $ | 12.8 | $ | 12.4 | ||||||||||||
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New prior service cost | $ | 0.0 | $ | 0.0 | $ | 0.0 | $ | (3.7 | ) | $ | (23.6 | ) | $ | 0.0 | ||||||||||
Net loss (gain) arising during the year | 74.5 | 44.1 | (75.7 | ) | 1.3 | (9.9 | ) | (15.6 | ) | |||||||||||||||
Unrecognized costs in regulated asset acquired in business combination | 0.0 | 0.0 | 0.0 | 0.0 | 6.4 | 0.0 | ||||||||||||||||||
Amounts recognized as component of net periodic benefit cost: | ||||||||||||||||||||||||
Amortization of actuarial gain (loss) | (15.1 | ) | (13.5 | ) | (21.5 | ) | 0.0 | (0.2 | ) | (1.0 | ) | |||||||||||||
Amortization of prior service (benefit) cost | 0.2 | 0.4 | 0.4 | 2.4 | 0.2 | 0.3 | ||||||||||||||||||
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Total recognized in OCI and regulatory assets | $ | 59.6 | $ | 31.0 | $ | (96.8 | ) | $ | 0.0 | $ | (27.1 | ) | $ | (16.3 | ) | |||||||||
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Total recognized in net periodic benefit cost, OCI and regulatory assets | $ | 82.4 | $ | 56.7 | $ | (67.0 | ) | $ | 6.9 | $ | (14.3 | ) | $ | (3.9 | ) | |||||||||
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A curtailment loss and special termination benefits were recognized in 2014 for the Retirement Plan due to the expected sale of TECO Coal. The sale was completed in 2015. Additionally, a curtailment gain was recognized for the OPEB plan due to the termination of the TECO Coal plan effective Jan. 1, 2015.
B-21
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $3.5 million and $0.1 million, respectively. The estimated prior service cost for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.5 million.
In addition, the estimated net loss for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $2.1 million prior service cost that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan. Additionally, $1.1 million of NMGC’s pre-acquisition regulated asset will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.
Assumptions used to determine net periodic benefit cost for years ended Dec. 31:
Pension Benefits | Other Benefits | |||||||||||||||||||||||
2015 | 2014 (1) | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||
Discount rate | 4.258 | % | 5.118%/4.277%/4.331 | % | 4.196 | % | 4.211 | % | 5.096 | % | 4.180 | % | ||||||||||||
Expected long-term return on plan assets | 7.00 | % | 7.25%/7.00%/7.00 | % | 7.50 | % | 5.75 | 5.75 | n/a | |||||||||||||||
Rate of compensation increase | 3.87 | % | 3.73 | % | 3.76 | % | 3.86 | % | 3.71 | % | 3.74 | % | ||||||||||||
Healthcare cost trend rate | ||||||||||||||||||||||||
Initial rate | n/a | n/a | n/a | 7.09 | % | 7.25 | % | 7.50 | % | |||||||||||||||
Ultimate rate | n/a | n/a | n/a | 4.57 | % | 4.50 | % | 4.50 | % | |||||||||||||||
Year rate reaches ultimate | n/a | n/a | n/a | 2025 | 2025 | 2025 | ||||||||||||||||||
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(1) | TECO Energy performed a valuation as of Jan. 1, 2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs. |
The discount rate assumption used to determine the 2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.
The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan assets decreased approximately 3.5%.
The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.
A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:
(millions) | 1% Increase | 1% Decrease | ||||||
Effect on periodic cost | $ | 0.4 | $ | (0.3 | ) |
Pension Plan Assets
Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
Actual Allocation, End of Year | ||||||||||||
Asset Category | Target Allocation | 2015 | 2014 | |||||||||
Equity securities | 47%-53 | % | 53 | % | 50 | % | ||||||
Fixed income securities | 47%-53 | % | 47 | % | 50 | % | ||||||
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Total | 100 | % | 100 | % | 100 | % | ||||||
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B-22
The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company will continue to monitor the matching of plan assets with plan liabilities.
The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.
If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.
As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014.
B-23
(millions) | At Fair Value as of Dec. 31, 2015 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Using NAV(1) | Total | ||||||||||||||||
Net cash | ||||||||||||||||||||
Cash | $ | 1.9 | $ | 0.0 | $ | 0.0 | $ | 0.0 | $ | 1.9 | ||||||||||
Accounts receivable | 14.3 | 0.0 | 0.0 | 0.0 | 14.3 | |||||||||||||||
Accounts payable | (27.2 | ) | 0.0 | 0.0 | 0.0 | (27.2 | ) | |||||||||||||
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Total net cash | (11.0 | ) | 0.0 | 0.0 | 0.0 | (11.0 | ) | |||||||||||||
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Cash equivalents | ||||||||||||||||||||
Money markets | 0.0 | 0.2 | 0.0 | 0.0 | 0.2 | |||||||||||||||
Discounted notes | 0.0 | 0.7 | 0.0 | 0.0 | 0.7 | |||||||||||||||
Short-term investment funds (STIFs)(1) | 0.0 | 0.0 | 0.0 | 12.4 | 12.4 | |||||||||||||||
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Total cash equivalents | 0.0 | 0.9 | 0.0 | 12.4 | 13.3 | |||||||||||||||
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Equity securities | ||||||||||||||||||||
Common stocks | 90.9 | 0.0 | 0.0 | 0.0 | 90.9 | |||||||||||||||
American depository receipts (ADRs) | 5.7 | 0.0 | 0.0 | 0.0 | 5.7 | |||||||||||||||
Real estate investment trusts (REITs) | 4.8 | 0.0 | 0.0 | 0.0 | 4.8 | |||||||||||||||
Commingled fund | 0.0 | 53.7 | 0.0 | 0.0 | 53.7 | |||||||||||||||
Mutual funds(1) | 0.0 | 0.0 | 0.0 | 175.6 | 175.6 | |||||||||||||||
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Total equity securities | 101.4 | 53.7 | 0.0 | 175.6 | 330.7 | |||||||||||||||
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Fixed income securities | ||||||||||||||||||||
Municipal bonds | 0.0 | 5.0 | 0.0 | 0.0 | 5.0 | |||||||||||||||
Government bonds | 0.0 | 56.2 | 0.0 | 0.0 | 56.2 | |||||||||||||||
Corporate bonds | 0.0 | 32.2 | 0.0 | 0.0 | 32.2 | |||||||||||||||
Asset backed securities (ABS) | 0.0 | 0.3 | 0.0 | 0.0 | 0.3 | |||||||||||||||
Mortgage-backed securities (MBS), net short sales | 0.0 | 8.7 | 0.0 | 0.0 | 8.7 | |||||||||||||||
Collateralized mortgage obligations (CMOs) | 0.0 | 1.5 | 0.0 | 0.0 | 1.5 | |||||||||||||||
Commingled fund(1) | 0.0 | 0.0 | 0.0 | 117.9 | 117.9 | |||||||||||||||
Mutual fund(1) | 0.0 | 0.0 | 0.0 | 71.3 | 71.3 | |||||||||||||||
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Total fixed income securities | 0.0 | 103.9 | 0.0 | 189.2 | 293.1 | |||||||||||||||
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Derivatives | ||||||||||||||||||||
Swaps | 0.0 | (0.9 | ) | 0.0 | 0.0 | (0.9 | ) | |||||||||||||
Purchased options (swaptions) | 0.0 | 1.1 | 0.0 | 0.0 | 1.1 | |||||||||||||||
Written options (swaptions) | 0.0 | (1.0 | ) | 0.0 | 0.0 | (1.0 | ) | |||||||||||||
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Total derivatives | 0.0 | (0.8 | ) | 0.0 | 0.0 | (0.8 | ) | |||||||||||||
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Miscellaneous | 0.0 | 0.1 | 0.0 | 0.0 | 0.1 | |||||||||||||||
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Total | $ | 90.4 | $ | 157.8 | $ | 0.0 | $ | 377.2 | $ | 625.4 | ||||||||||
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(1) | In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. |
B-24
At Fair Value as of Dec. 31, 2014 | ||||||||||||||||||||
(millions) | Level 1 | Level 2 | Level 3 | Using NAV (1) | Total | |||||||||||||||
Net cash | ||||||||||||||||||||
Cash | $ | 0.4 | $ | 0.0 | $ | 0.0 | $ | 0.0 | $ | 0.4 | ||||||||||
Accounts receivable | 1.4 | 0.0 | �� | 0.0 | 0.0 | 1.4 | ||||||||||||||
Accounts payable | (5.3 | ) | 0.0 | 0.0 | 0.0 | (5.3 | ) | |||||||||||||
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Total net cash | (3.5 | ) | 0.0 | 0.0 | 0.0 | (3.5 | ) | |||||||||||||
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Cash equivalents | ||||||||||||||||||||
Treasury bills (T bills) | 0.0 | 0.2 | 0.0 | 0.0 | 0.2 | |||||||||||||||
Discounted notes | 0.0 | 8.8 | 0.0 | 0.0 | 8.8 | |||||||||||||||
Short-term investment funds (STIFs)(1) | 0.0 | 0.0 | 0.0 | 7.6 | 7.6 | |||||||||||||||
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Total cash equivalents | 0.0 | 9.0 | 0.0 | 7.6 | 16.6 | |||||||||||||||
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Equity securities | ||||||||||||||||||||
Common stocks | 98.0 | 0.0 | 0.0 | 0.0 | 98.0 | |||||||||||||||
American depository receipts (ADRs) | 1.3 | 0.0 | 0.0 | 0.0 | 1.3 | |||||||||||||||
Real estate investment trusts (REITs) | 2.5 | 0.0 | 0.0 | 0.0 | 2.5 | |||||||||||||||
Preferred stock | 0.8 | 0.0 | 0.0 | 0.0 | 0.8 | |||||||||||||||
Commingled fund | 0.0 | 45.6 | 0.0 | 0.0 | 45.6 | |||||||||||||||
Mutual funds(1) | 0.0 | 0.0 | 0.0 | 171.3 | 171.3 | |||||||||||||||
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Total equity securities | 102.6 | 45.6 | 0.0 | 171.3 | 319.5 | |||||||||||||||
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Fixed income securities | ||||||||||||||||||||
Municipal bonds | 0.0 | 6.1 | 0.0 | 0.0 | 6.1 | |||||||||||||||
Government bonds | 0.0 | 47.9 | 0.0 | 0.0 | 47.9 | |||||||||||||||
Corporate bonds | 0.0 | 22.0 | 0.0 | 0.0 | 22.0 | |||||||||||||||
Asset backed securities (ABS) | 0.0 | 0.3 | 0.0 | 0.0 | 0.3 | |||||||||||||||
Mortgage-backed securities (MBS), net short sales | 0.0 | 9.6 | 0.0 | 0.0 | 9.6 | |||||||||||||||
Collateralized mortgage obligations (CMOs) | 0.0 | 2.0 | 0.0 | 0.0 | 2.0 | |||||||||||||||
Commingled fund(1) | 0.0 | 0.0 | 0.0 | 129.2 | 129.2 | |||||||||||||||
Mutual fund(1) | 0.0 | 0.0 | 0.0 | 98.6 | 98.6 | |||||||||||||||
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Total fixed income securities | 0.0 | 87.9 | 0.0 | 227.8 | 315.7 | |||||||||||||||
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Derivatives | ||||||||||||||||||||
Short futures | 0.0 | (0.3 | ) | 0.0 | 0.0 | (0.3 | ) | |||||||||||||
Purchased options (swaptions) | 0.0 | 0.7 | 0.0 | 0.0 | 0.7 | |||||||||||||||
Written options (swaptions) | 0.0 | (0.8 | ) | 0.0 | 0.0 | (0.8 | ) | |||||||||||||
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Total derivatives | 0.0 | (0.4 | ) | 0.0 | 0.0 | (0.4 | ) | |||||||||||||
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Miscellaneous | 0.0 | 0.1 | 0.0 | 0.0 | 0.1 | |||||||||||||||
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Total | $ | 99.1 | $ | 142.2 | $ | 0.0 | $ | 406.7 | $ | 648.0 | ||||||||||
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(1) | In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. |
The following list details the pricing inputs and methodologies used to value the investments in the pension plan:
• | The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. |
• | The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System. The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis. |
• | The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost. |
• | The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. |
B-25
• | Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. |
• | Swaps are valued using benchmark yields, swap curves, and cash flow analyses. |
• | Options are valued using the bid-ask spread and the last price. |
• | The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. |
• | The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV. |
• | The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. |
• | The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month. Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date. |
Additionally, the unqualified SERP had $43.5 million and $0.9 million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.
Other Postretirement Benefit Plan Assets
NMGC’s other postretirement benefits plan had $20.6 million and $18.8 million of assets as of Dec. 31, 2015 and 2014, respectively. The majority of the assets are valued at the cash surrender value of NMGC participant life insurance policies and are considered Level 2 assets. In accordance with NMPRC requirements, NMGC must fund to a trust, on an annual basis, an amount equal to the other postretirement expense allowed in its last base rate case.
Contributions
The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.
WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions were based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.
In August 2014, the President signed into law HAFTA, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.
The qualified pension plan’s actuarial value of assets, including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.
The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $55.0 million and $47.5 million of contributions to this plan in 2015 and 2014, respectively, which met the minimum funding requirements for both 2015 and 2014. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2016 to be $37.4 million and expects to make contributions from 2017 to 2020 in the range of $12.2 to $44.6 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.
B-26
The company made contributions of $43.4 million and $1.2 million to the SERP in 2015 and 2014, respectively. The company’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, the company does not expect to make significant contributions to this plan in 2016.
The company funds its other postretirement benefits periodically to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, the company expects to make contributions of about $14.3 million. This includes $3.6 million that NMGC is required to fund to its trust in accordance with NMPRC requirements. Postretirement benefit levels are substantially unrelated to salary.
Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Expected Benefit Payments
(including projected service and net of employee contributions)
Other | ||||||||
Pension | Postretirement | |||||||
(millions) | Benefits | Benefits | ||||||
2016 | $ | 77.8 | $ | 11.5 | ||||
2017 | 49.5 | 11.9 | ||||||
2018 | 52.7 | 12.5 | ||||||
2019 | 59.2 | 13.0 | ||||||
2020 | 54.9 | 13.3 | ||||||
2021-2025 | 299.1 | 68.6 |
Defined Contribution Plan
The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective Jan. 1, 2015, employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2015, 2014 and 2013, the company and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan.
B-27
6. Short-Term Debt
At Dec. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:
Credit Facilities
Dec. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||
Letters | Letters | |||||||||||||||||||||||
Credit | Borrowings | of Credit | Credit | Borrowings | of Credit | |||||||||||||||||||
(millions) | Facilities | Outstanding (1) | Outstanding | Facilities | Outstanding (1) | Outstanding | ||||||||||||||||||
Tampa Electric Company: | ||||||||||||||||||||||||
5-year facility(2) | $ | 325.0 | $ | 0.0 | $ | 0.5 | $ | 325.0 | $ | 12.0 | $ | 0.6 | ||||||||||||
3-year accounts receivable facility (3) | 150.0 | 61.0 | 0.0 | 150.0 | 46.0 | 0.0 | ||||||||||||||||||
TECO Energy/TECO Finance: | ||||||||||||||||||||||||
5-year facility(2)(4) | 300.0 | 163.0 | 0.0 | 300.0 | 50.0 | 0.0 | ||||||||||||||||||
New Mexico Gas Company: | ||||||||||||||||||||||||
5-year facility(2) | 125.0 | 23.0 | 1.7 | 125.0 | 31.0 | 1.7 | ||||||||||||||||||
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Total | $ | 900.0 | $ | 247.0 | $ | 2.2 | $ | 900.0 | $ | 139.0 | $ | 2.3 | ||||||||||||
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(1) | Borrowings outstanding are reported as notes payable. |
(2) | This 5-year facility matures Dec. 17, 2018. |
(3) | Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. |
(4) | TECO Finance is the borrower and TECO Energy is the guarantor of this facility. |
At Dec. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 1.29% and 1.16%, respectively.
Tampa Electric Company Accounts Receivable Facility
On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as of Dec. 31, 2015. Interest rates on the borrowings are 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 the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. In addition, under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Dec. 31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.
TECO Energy Credit Agreement Assigned to and Assumed by NMGC
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.
B-28
On Sept. 30, 2014, NMGC entered into an amendment of the NMGC Credit Agreement, which reallocated commitments among the lenders and made certain other technical changes.
Amendment of Tampa Electric Company Credit Facility
On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continued to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC 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) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.
On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.
Amendments of TECO Energy/TECO Finance Credit Facility
On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility). The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as guarantor and its wholly-owned subsidiary, TECO Finance, as borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance 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; (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (viii) made other technical changes.
The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. Amendment No. 1 was entered into to accommodate the acquisition of NMGI, as described inNote 21 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closed, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changed the definition of Permitted Liens to permit the acquisition of a significant subsidiary that has outstanding secured debt and made other changes matching the corresponding covenant in the Bridge Facility. TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement on June 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.
On Sept. 30, 2014, the TECO Credit Facility was amended to increase total commitments to $300 million and to reallocate commitments among the lenders.
7. Long-Term Debt
At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,599.3 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.
B-29
TECO Finance is a wholly owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities.
A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.
TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2016 through 2020 and thereafter are as follows:
Long-Term Debt Maturities
Total | ||||||||||||||||||||||||||||
As of Dec. 31, 2015 | Long-Term | |||||||||||||||||||||||||||
(millions) | 2016 | 2017 | 2018 | 2019 | 2020 | Thereafter | Debt | |||||||||||||||||||||
TECO Finance | $ | 250.0 | $ | 300.0 | $ | 250.0 | $ | 0.0 | $ | 300.0 | $ | 0.0 | $ | 1,100.0 | ||||||||||||||
Tampa Electric | 83.3 | 0.0 | 254.2 | 0.0 | 0.0 | 1,666.7 | 2,004.2 | |||||||||||||||||||||
PGS | 0.0 | 0.0 | 50.0 | 0.0 | 0.0 | 211.7 | 261.7 | |||||||||||||||||||||
NMGC | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 270.0 | 270.0 | |||||||||||||||||||||
NMGI | 0.0 | 0.0 | 0.0 | 50.0 | 0.0 | 150.0 | 200.0 | |||||||||||||||||||||
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Total long-term debt maturities | $ | 333.3 | $ | 300.0 | $ | 554.2 | $ | 50.0 | $ | 300.0 | $ | 2,298.4 | $ | 3,835.9 | ||||||||||||||
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Issuance of TECO Finance Floating Rate Notes due 2018
On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018. The 2018 Notes bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness.
The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment of $191 million of TECO Finance notes that matured in May 2015.
Issuance of Tampa Electric Company 4.20% Notes due 2045
On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes). The TEC 2015 Notes were sold at 99.814% 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 $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the TEC 2015 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 the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 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, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
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 before Nov. 15, 2043 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.
B-30
Issuance of New Mexico Gas Intermediate Senior Unsecured Notes
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 2014 Notes) and $150 million aggregate principal amount of 3.64% Series B Senior Unsecured Notes due July 30, 2024 (the NMGI Series B 2014 Notes and, with the NMGI Series A 2014 Notes, the NMGI 2014 Notes). The NMGI 2014 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 $198.4 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI 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 NMGI 2014 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 2014 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 exempt from 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 exempt from 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, the collateral securing the NMGC 2011 Notes was released and other technical changes were made to the NMGC 2011 Notes.
Purchase in Lieu of Redemption of Revenue Refunding Bonds
On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.
On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.
As of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.
B-31
At Dec. 31, 2015 and 2014, TECO Energy had the following long-term debt outstanding:
Long-Term Debt
(millions) | Due | 2015 | 2014 | |||||||||||
TECO Finance | Notes (1)(2) : 6.75%(3) | 2015 | $ | 0.0 | �� | $ | 191.2 | |||||||
4.00%(3) | 2016 | 250.0 | 250.0 | |||||||||||
6.57%(3) | 2017 | 300.0 | 300.0 | |||||||||||
Floating rate notes | 2018 | 250.0 | 0.0 | |||||||||||
5.15%(3) | 2020 | 300.0 | 300.0 | |||||||||||
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Total long-term debt of TECO Finance | 1,100.0 | 1,041.2 | ||||||||||||
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Tampa Electric | Installment contracts payable(4): | |||||||||||||
5.65% Refunding bonds | 2018 | 54.2 | 54.2 | |||||||||||
Variable rate bonds repurchased in 2008 (5) | 2020 | 0.0 | 0.0 | |||||||||||
5.15% Refunding bonds repurchased in 2013(6) | 2025 | 0.0 | 0.0 | |||||||||||
1.5% Term rate bonds repurchased in 2011 (7) | 2030 | 0.0 | 0.0 | |||||||||||
5.0% Refunding bonds repurchased in 2012 (8) | 2034 | 0.0 | 0.0 | |||||||||||
Notes(1)(2) : 6.25% | 2015-2016 | 83.3 | 166.7 | |||||||||||
6.10% | 2018 | 200.0 | 200.0 | |||||||||||
5.40% | 2021 | 231.7 | 231.7 | |||||||||||
2.60% | 2022 | 225.0 | 225.0 | |||||||||||
6.55% | 2036 | 250.0 | 250.0 | |||||||||||
6.15% | 2037 | 190.0 | 190.0 | |||||||||||
4.10% | 2042 | 250.0 | 250.0 | |||||||||||
4.35% | 2044 | 290.0 | 290.0 | |||||||||||
4.20% | 2045 | 230.0 | 0.0 | |||||||||||
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Total long-term debt of Tampa Electric | 2,004.2 | 1,857.6 | ||||||||||||
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PGS | Notes(2)(3) : 6.10% | 2018 | 50.0 | 50.0 | ||||||||||
5.40% | 2021 | 46.7 | 46.7 | |||||||||||
2.60% | 2022 | 25.0 | 25.0 | |||||||||||
6.15% | 2037 | 60.0 | 60.0 | |||||||||||
4.10% | 2042 | 50.0 | 50.0 | |||||||||||
4.35% | 2044 | 10.0 | 10.0 | |||||||||||
4.20% | 2045 | 20.0 | 0.0 | |||||||||||
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Total long-term debt of PGS | 261.7 | 241.7 | ||||||||||||
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NMGI | Notes (2)(3) : 2.71% | 2019 | 50.0 | 50.0 | ||||||||||
3.64% | 2024 | 150.0 | 150.0 | |||||||||||
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Total long-term debt of NMGI | 200.0 | 200.0 | ||||||||||||
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NMGC | Notes (2)(3) : 4.87% | 2021 | 200.0 | 200.0 | ||||||||||
3.54% | 2026 | 70.0 | 70.0 | |||||||||||
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Total long-term debt of NMGC | 270.0 | 270.0 | ||||||||||||
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Total long-term debt of TECO Energy | 3,835.9 | 3,610.5 | ||||||||||||
Unamortized debt discount, net | 14.3 | 18.0 | ||||||||||||
Debt issuance costs | (27.7 | ) | (29.2 | ) | ||||||||||
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Total carrying amount of long-term debt | 3,822.5 | 3,599.3 | ||||||||||||
Less amount due within one year | 333.3 | 274.5 | ||||||||||||
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Total long-term debt | $ | 3,489.2 | $ | 3,324.8 | ||||||||||
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(1) | Guaranteed by TECO Energy. |
(2) | These long-term debt agreements contain various restrictive financial covenants. |
(3) | These securities are subject to redemption in whole or in part, at any time, at the option of the issuer. |
(4) | Tax-exempt securities. |
(5) | In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020. |
B-32
(6) | In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025. |
(7) | In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030. |
(8) | In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034. |
8. Preferred Stock
Preferred stock of TECO Energy – $1 par
10 million shares authorized, none outstanding.
Preference stock (subordinated preferred stock) of Tampa Electric – no par
2.5 million shares authorized, none outstanding.
Preferred stock of Tampa Electric – no par
2.5 million shares authorized, none outstanding.
Preferred stock of Tampa Electric – $100 par
1.5 million shares authorized, none outstanding.
9. Common Stock
Pending Merger with Emera
On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest.
The Merger Agreement with Emera restricts TECO Energy and its subsidiaries, without Emera’s prior written consent, from issuing equity or equity equivalents and from paying quarterly cash dividends in excess of levels agreed upon in the Merger Agreement until the Merger occurs or the Merger Agreement is terminated.
SeeNote 21 for additional information regarding the pending Merger.
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.
Stock-Based Compensation
On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.
B-33
The 2010 Plan amended the 2004 Plan. The amendment reduced the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), removed the cap on shares available for stock grant, placed various limitations on the terms of awards granted under the 2010 Plan, removed the ability to make awards to consultants of the company and reapproved the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.
The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest in amounts ranging between 0% and 150% of the original grant. Beginning in 2015, the total awards for performance-based restricted stock vest based on achievement of earnings growth, with the ability to earn more shares based on total return of TECO Energy common stock compared to a peer group of utility stocks. The 2015 performance-based grants can vest in amounts ranging between 0% and 200% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant. The Merger Agreement with Emera contains provisions regarding the vesting of outstanding grants which would apply upon closing of the Merger.
The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.
The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.
Assumptions | 2015 | 2014 | 2013 | |||||||||
Assumptions applicable to performance-based restricted stock | ||||||||||||
Risk-free interest rate | 0.83 | % | 0.68 | % | 0.41 | % | ||||||
Expected lives (in years) | 3 | 3 | 3 | |||||||||
Expected stock volatility | 14.78 | % | 17.36 | % | 19.04 | % | ||||||
Dividend yield | 3.98 | % | 5.13 | % | 4.83 | % |
In 2015, 2014 and 2013, 0.7 million, 0.8 million and 0.7 million shares of restricted stock were granted, respectively, with weighted-average fair value per share of $22.96, $14.69 and $17.21, respectively. The total fair market value of awards vesting during 2015, 2014 and 2013 was $7.5 million, $3.6 million and $3.5 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2015, there was $13.2 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.
The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.
(millions) | 2015 | 2014 | 2013 | |||||||||
Compensation costs(1) | $ | 13.1 | $ | 12.7 | $ | 13.5 | ||||||
Income tax benefits(1) | 5.1 | 4.9 | 5.2 | |||||||||
Excess tax benefits(2) | 0.0 | 0.4 | 0.0 |
(1) | Reflected on the Consolidated Statements of Income. |
(2) | Reflected as financing activities on the Consolidated Statements of Cash Flows. |
B-34
The aggregate intrinsic value of stock options exercised was $2.9 million, $2.7 million and $2.4 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. Cash received from option exercises under all share-based payment arrangements was $9.4 million, $10.8 million and $6.7 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. The income tax benefit realized from stock option exercises was $1.1 million, $1.0 million and $0.8 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively.
A summary of non-vested shares of restricted stock is shown as follows:
Nonvested Restricted Stock
Time-Based Restricted | Performance-Based | |||||||||||||||
Stock(1) | Restricted Stock(1) | |||||||||||||||
Weighted - | Weighted- | |||||||||||||||
Avg. Grant | Avg. Grant | |||||||||||||||
Number of | Date | Number of | Date | |||||||||||||
Shares | Fair Value | Shares | Fair Value | |||||||||||||
(thousands) | (per share) | (thousands) | (per share) | |||||||||||||
Nonvested balance at Dec. 31, 2014 | 668 | $ | 17.56 | 1,515 | $ | 15.44 | ||||||||||
Granted | 213 | $ | 21.34 | 445 | $ | 23.72 | ||||||||||
Vested | (273 | ) | $ | 17.96 | (626 | ) | $ | 15.94 | ||||||||
Forfeited | (19 | ) | $ | 17.78 | (43 | ) | $ | 16.05 | ||||||||
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Nonvested balance at Dec. 31, 2015 | 589 | $ | 18.74 | 1,291 | $ | 18.06 | ||||||||||
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(1) | The weighted-average remaining contractual term of restricted stock is two years. |
Stock option transactions are summarized as follows:
Stock Options
Weighted-Avg. | Aggregate | |||||||||||||||
Number of | Weighted-Avg. | Remaining | Intrinsic | |||||||||||||
Shares | Option Price | Contractual | Value | |||||||||||||
(thousands) | (per share) | Term (years) | (millions) | |||||||||||||
Outstanding balance at Dec. 31, 2014 | 840 | $ | 16.32 | |||||||||||||
Granted | 0 | $ | 0.00 | |||||||||||||
Exercised | (580 | ) | $ | 16.30 | ||||||||||||
Cancelled | (6 | ) | $ | 18.87 | ||||||||||||
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Outstanding balance at Dec. 31, 2015(1) | 254 | $ | 16.30 | 1 | $ | 2.6 | ||||||||||
Exercisable at Dec. 31, 2015(1) | 254 | $ | 16.30 | 1 | $ | 2.6 | ||||||||||
Available for future grant at Dec. 31, 2015 | 2,429 |
(1) | Option prices are $16.30 per share. |
Direct Stock Purchase and Dividend Reinvestment Plan
In September 2014, the Direct Stock Purchase and Dividend Plan amended and restated the 1992 Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2015, 2014 and 2013, resulting in no increase in shares outstanding.
B-35
10. Other Comprehensive Income
TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2015, 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 benefit plans:
(millions) | Gross | Tax | Net | |||||||||
2015 | ||||||||||||
Unrealized gain (loss) on cash flow hedges | $ | 4.3 | $ | (1.5 | ) | $ | 2.8 | |||||
Reclassification from AOCI to net income(1) | 1.4 | (0.7 | ) | 0.7 | ||||||||
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Gain (Loss) on cash flow hedges | 5.7 | (2.2 | ) | 3.5 | ||||||||
Amortization of unrecognized benefit costs and other(2) | 3.4 | (1.3 | ) | 2.1 | ||||||||
Change in benefit obligation due to valuation(3) | (15.5 | ) | 5.7 | (9.8 | ) | |||||||
Recognized cost due to settlement(4) | 12.1 | (4.4 | ) | 7.7 | ||||||||
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Total other comprehensive income (loss) | $ | 5.7 | $ | (2.2 | ) | $ | 3.5 | |||||
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2014 | ||||||||||||
Unrealized gain (loss) on cash flow hedges | $ | (0.5 | ) | $ | 0.2 | $ | (0.3 | ) | ||||
Reclassification from AOCI to net income(1) | 1.6 | (0.6 | ) | 1.0 | ||||||||
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Gain (Loss) on cash flow hedges | 1.1 | (0.4 | ) | 0.7 | ||||||||
Amortization of unrecognized benefit costs and other(2) | (4.8 | ) | 1.8 | (3.0 | ) | |||||||
Increase in unrecognized postemployment costs(5) | (12.9 | ) | 4.7 | (8.2 | ) | |||||||
Change in benefit obligation due to valuation(6) | 12.6 | (4.6 | ) | 8.0 | ||||||||
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Total other comprehensive income (loss) | $ | (4.0 | ) | $ | 1.5 | $ | (2.5 | ) | ||||
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2013 | ||||||||||||
Unrealized gain (loss) on cash flow hedges | $ | 1.0 | $ | (0.4 | ) | $ | 0.6 | |||||
Reclassification from AOCI to net income(1) | 1.3 | (0.5 | ) | 0.8 | ||||||||
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Gain (Loss) on cash flow hedges | 2.3 | (0.9 | ) | 1.4 | ||||||||
Amortization of unrecognized benefit costs and other(2) | 23.6 | (8.8 | ) | 14.8 | ||||||||
Recognized costs due to settlement | 2.6 | (1.0 | ) | 1.6 | ||||||||
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Total other comprehensive income (loss) | $ | 28.5 | $ | (10.7 | ) | $ | 17.8 | |||||
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(1) | Related to interest rate contracts in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations. |
(2) | Related to postretirement and postemployment benefits. SeeNote 5 for additional information. |
(3) | Related to the transfer of employees and their associated postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI. |
(4) | Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. SeeNote 19for additional information. |
(5) | Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability. |
(6) | Includes an adjustment to eliminate TECO Coal’s OPEB liability. SeeNote 5 for additional information. |
Accumulated Other Comprehensive Loss
(millions) Dec. 31, | 2015 | 2014 | ||||||
Unamortized pension losses and prior service credits(1) | $ | (34.2 | ) | $ | (22.5 | ) | ||
Unamortized other benefit gains, prior service costs and transition obligations(2) | 25.6 | 13.9 | ||||||
Net unrealized losses from cash flow hedges(3) | (3.6 | ) | (7.1 | ) | ||||
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Total accumulated other comprehensive loss | $ | (12.2 | ) | $ | (15.7 | ) | ||
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(1) | Net of tax benefit of $21.5 million and $13.8 million as of Dec. 31, 2015 and 2014, respectively. |
(2) | Net of tax expense of $16.1 million and $8.3 million as of Dec. 31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. SeeNote 5. |
(3) | Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively. |
B-36
11. Earnings Per Share
In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.
The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.
(millions, except per share amounts) | 2015 | 2014 | 2013(1) | |||||||||
Basic earnings per share | ||||||||||||
Net income from continuing operations | $ | 241.2 | $ | 206.4 | $ | 188.7 | ||||||
Amount allocated to nonvested participating shareholders | (0.7 | ) | (0.7 | ) | (0.6 | ) | ||||||
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Income before discontinued operations available to common shareholders—Basic | $ | 240.5 | $ | 205.7 | $ | 188.1 | ||||||
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Income (loss) from discontinued operations | $ | (67.7 | ) | $ | (76.0 | ) | $ | 9.0 | ||||
Amount allocated to nonvested participating shareholders | 0.0 | 0.0 | 0.0 | |||||||||
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Income (loss) from discontinued operations—Basic | $ | (67.7 | ) | $ | (76.0 | ) | $ | 9.0 | ||||
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Net income | $ | 173.5 | $ | 130.4 | $ | 197.7 | ||||||
Amount allocated to nonvested participating shareholders | (0.7 | ) | (0.7 | ) | (0.6 | ) | ||||||
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Net income available to common shareholders—Basic | $ | 172.8 | $ | 129.7 | $ | 197.1 | ||||||
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Average common shares outstanding—Basic | 233.1 | 223.1 | 215.0 | |||||||||
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Earnings per share from continuing operations available to common shareholders—Basic | $ | 1.03 | $ | 0.92 | $ | 0.88 | ||||||
Earnings per share from discontinued operations available to common shareholders—Basic | (0.29 | ) | (0.34 | ) | 0.04 | |||||||
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Earnings per share attributable to TECO Energy available to common shareholders—Basic | $ | 0.74 | $ | 0.58 | $ | 0.92 | ||||||
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Diluted earnings per share | ||||||||||||
Net income from continuing operations | $ | 241.2 | $ | 206.4 | $ | 188.7 | ||||||
Amount allocated to nonvested participating shareholders | (0.7 | ) | (0.7 | ) | (0.6 | ) | ||||||
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Income before discontinued operations available to common shareholders—Diluted | $ | 240.5 | $ | 205.7 | $ | 188.1 | ||||||
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Income (loss) from discontinued operations | $ | (67.7 | ) | $ | (76.0 | ) | $ | 9.0 | ||||
Amount allocated to nonvested participating shareholders | 0.0 | 0.0 | 0.0 | |||||||||
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Income (loss) from discontinued operations available to common shareholders—Diluted | $ | (67.7 | ) | $ | (76.0 | ) | $ | 9.0 | ||||
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Net income | $ | 173.5 | $ | 130.4 | $ | 197.7 | ||||||
Amount allocated to nonvested participating shareholders | (0.7 | ) | (0.7 | ) | (0.6 | ) | ||||||
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Net income available to common shareholders—Diluted | $ | 172.8 | $ | 129.7 | $ | 197.1 | ||||||
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Unadjusted average common shares outstanding—Diluted | 233.1 | 223.1 | 215.0 | |||||||||
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net | 1.4 | 0.6 | 0.5 | |||||||||
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Average common shares outstanding—Diluted | 234.5 | 223.7 | 215.5 | |||||||||
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Earnings per share from continuing operations available to common shareholders—Diluted | $ | 1.03 | $ | 0.92 | $ | 0.88 | ||||||
Earnings per share from discontinued operations available to common shareholders—Diluted | (0.29 | ) | (0.34 | ) | 0.04 | |||||||
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Earnings per share available to common shareholders—Diluted | $ | 0.74 | $ | 0.58 | $ | 0.92 | ||||||
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Anti-dilutive shares | 0.0 | 0.0 | 0.0 | |||||||||
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(1) | All prior periods presented reflect the classification of TECO Coal as discontinued operations (seeNote 19). |
B-37
12. Commitments and Contingencies
Legal Contingencies
From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.
Tampa Electric Legal Proceedings
A 36-year-old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.
A 33-year-old man made contact with a primary line in June 2013, suffering severe burns. He and his wife sued Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence. Plaintiffs’ case against Tampa Electric alleged, among other things, negligence and loss of consortium. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.
Peoples Gas Legal Proceedings
In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in late 2016.
New Mexico Gas Company Legal Proceedings
In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).
In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”
In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Dec. 31, 2015.
In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgement in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgement.
B-38
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, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.
On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.
Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.
While the duration of the annulment proceedings is uncertain, a hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.
Proceedings in connection with the Pending Merger with Emera
Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction. Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger. In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.
The company also received two separate shareholder demand letters from purported shareholders of the company. Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices. One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.
In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger. As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement. Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.
PGS Compliance Matter
In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed. As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.
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 Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 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, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.
B-39
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.
Long-Term Commitments
TECO Energy has commitments for capacity payments and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Other” and “Discontinued Operations” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013 totaled $15.3 million, $13.7 million and $7.6 million, respectively. In addition, the company has other purchase obligations, including Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015:
Capacity | Operating | Net Purchase | ||||||||||||||
(millions) | Payments | Leases(1) | Obligations/Commitments(1) | Total | ||||||||||||
Year ended Dec. 31: | ||||||||||||||||
2016 | $ | 14.6 | $ | 7.7 | $ | 222.5 | $ | 244.8 | ||||||||
2017 | 9.9 | 7.1 | 21.5 | 38.5 | ||||||||||||
2018 | 10.1 | 6.4 | 9.6 | 26.1 | ||||||||||||
2019 | 0.0 | 5.7 | 9.7 | 15.4 | ||||||||||||
2020 | 0.0 | 5.4 | 4.7 | 10.1 | ||||||||||||
Thereafter | 0.0 | 18.6 | 20.0 | 38.6 | ||||||||||||
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Total future minimum payments | $ | 34.6 | $ | 50.9 | $ | 288.0 | $ | 373.5 | ||||||||
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(1) | Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. The table above excludes payment obligations under contractual agreements of Tampa Electric, PGS and NMGC for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses. |
Guarantees and Letters of Credit
TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:
• | Initial recognition and initial measurement of a liability, and/or |
• | Disclosure of specific details of the guarantee. |
Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.
Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
B-40
A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2015 are as follows:
Year of Expiration | Maximum | |||||||||||||||||||
(millions) | After (1) | Theoretical | Liabilities Recognized | |||||||||||||||||
Guarantees for the Benefit of: | 2016 | 2017-2020 | 2020 | Obligation | at Dec. 31, 2015 | |||||||||||||||
TECO Energy | ||||||||||||||||||||
Fuel sales and transportation (2) | $ | 0.0 | $ | 0.0 | $ | 92.9 | $ | 92.9 | $ | 0.0 | ||||||||||
Letters of indemnity - coal mining permits (3) | 90.0 | 0.0 | 0.0 | 90.0 | 0.0 | |||||||||||||||
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$ | 90.0 | $ | 0.0 | $ | 92.9 | $ | 182.9 | $ | 0.0 | |||||||||||
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Year of Expiration | Maximum | |||||||||||||||||||
(millions) | After (1) | Theoretical | Liabilities Recognized | |||||||||||||||||
Letter of Credit for the Benefit of: | 2016 | 2017-2020 | 2020 | Obligation | at Dec. 31, 2015(4) | |||||||||||||||
TEC | $ | 0.0 | $ | 0.0 | $ | 0.5 | $ | 0.5 | $ | 0.1 | ||||||||||
NMGC | $ | 0.0 | $ | 0.0 | $ | 1.7 | $ | 1.7 | $ | 0.0 |
(1) | These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. |
(2) | The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Dec. 31, 2015. SeeNote 16 for additional information. |
(3) | These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal’s mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed inNote 19, TECO Coal was sold on Sept. 21, 2015 to Cambrian. Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities. Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy’s indemnity are released, TECO Energy’s indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained. |
(4) | The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims. |
Financial Covenants
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 Dec. 31, 2015, TECO Energy and its subsidiaries were in compliance with all required financial covenants.
13. Related Party Transactions
The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2015, 2014 and 2013. No material balances were payable as of Dec. 31, 2015 or 2014.
B-41
14. Segment Information
TECO Energy is primarily an electric and gas utility holding company. Its diversified activities have been classified as discontinued operations. 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 segment’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 Financial Statements of TECO Energy, but are included in determining reportable segments.
Tampa Electric provides retail electric utility services to almost 719,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida. NMGC is engaged in the purchase and distribution of natural gas for more than 516,000 residential, commercial, industrial customers in the State of New Mexico.
Tampa | TECO | TECO | ||||||||||||||||||||||||||
(millions) | Electric | PGS | NMGC (4) | Coal(2) | Other (4),(5) | Eliminations (5) | Energy | |||||||||||||||||||||
2015 | ||||||||||||||||||||||||||||
Revenues—external | $ | 2,014.9 | $ | 401.5 | $ | 316.5 | $ | 0.0 | $ | 10.6 | $ | 0.0 | $ | 2,743.5 | ||||||||||||||
Sales to affiliates | 3.4 | 6.0 | 0.0 | 0.0 | 0.1 | (9.5 | ) | 0.0 | ||||||||||||||||||||
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Total revenues | 2,018.3 | 407.5 | 316.5 | 0.0 | 10.7 | (9.5 | ) | 2,743.5 | ||||||||||||||||||||
Depreciation and amortization | 256.7 | 56.8 | 33.8 | 0.0 | 1.7 | 0.0 | 349.0 | |||||||||||||||||||||
Total interest charges(1) | 95.1 | 14.5 | 13.0 | 0.0 | 65.1 | (1.3 | ) | 186.4 | ||||||||||||||||||||
Internally allocated interest(1) | 0.0 | 0.0 | 0.0 | 0.0 | 1.3 | (1.3 | ) | 0.0 | ||||||||||||||||||||
Provision for income taxes | 143.6 | 21.9 | 15.4 | 0.0 | (25.6 | ) | 0.0 | 155.3 | ||||||||||||||||||||
Net income from continuing operations | 241.0 | 35.3 | 24.1 | 0.0 | (59.2 | ) | 0.0 | 241.2 | ||||||||||||||||||||
Discontinued operations, net of tax | 0.0 | 0.0 | 0.0 | (69.6 | ) | 1.9 | 0.0 | (67.7 | ) | |||||||||||||||||||
Net income | 241.0 | 35.3 | 24.1 | (69.6 | ) | (57.3 | ) | 0.0 | 173.5 | |||||||||||||||||||
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Goodwill | 0.0 | 0.0 | 408.4 | 0.0 | 0.0 | 0.0 | 408.4 | |||||||||||||||||||||
Total assets(7) | 7,003.8 | 1,136.1 | 1,229.7 | 0.0 | (3) | 1,945.1 | (2,381.2 | )(6) | 8,933.5 | |||||||||||||||||||
Capital expenditures | 592.6 | 94.0 | 48.7 | 3.7 | 0.7 | 0.0 | 739.7 | |||||||||||||||||||||
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2014 | ||||||||||||||||||||||||||||
Revenues—external | $ | 2,019.9 | $ | 398.5 | $ | 137.5 | $ | 0.0 | $ | 10.5 | $ | 0.0 | $ | 2,566.4 | ||||||||||||||
Sales to affiliates | 1.1 | 1.1 | 0.0 | 0.0 | 0.2 | (2.4 | ) | 0.0 | ||||||||||||||||||||
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Total revenues | 2,021.0 | 399.6 | 137.5 | 0.0 | 10.7 | (2.4 | ) | 2,566.4 | ||||||||||||||||||||
Depreciation and amortization | 248.6 | 54.0 | 11.0 | 0.0 | 1.7 | 0.0 | 315.3 | |||||||||||||||||||||
Total interest charges(1) | 92.8 | 13.8 | 4.2 | 0.0 | 66.1 | (5.8 | ) | 171.1 | ||||||||||||||||||||
Internally allocated interest(1) | 0.0 | 0.0 | 0.0 | 0.0 | 5.8 | (5.8 | ) | 0.0 | ||||||||||||||||||||
Provision for income taxes | 133.2 | 22.7 | 7.1 | 0.0 | (24.1 | ) | 0.0 | 138.9 | ||||||||||||||||||||
Net income from continuing operations | 224.5 | 35.8 | 10.5 | 0.0 | (64.4 | ) | 0.0 | 206.4 | ||||||||||||||||||||
Discontinued operations, net of tax | 0.0 | 0.0 | 0.0 | (82.0 | ) | 6.0 | 0.0 | (76.0 | ) | |||||||||||||||||||
Net income | 224.5 | 35.8 | 10.5 | (82.0 | ) | (58.4 | ) | 0.0 | 130.4 | |||||||||||||||||||
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Goodwill | 0.0 | 0.0 | 408.3 | 0.0 | 0.0 | 0.0 | 408.3 | |||||||||||||||||||||
Total assets(7) | 6,549.7 | 1,081.7 | 1,234.8 | 227.7 | (3) | 1,601.6 | (1,998.5 | )(6) | 8,697.0 | |||||||||||||||||||
Capital expenditures | 582.1 | 88.9 | 18.2 | 14.6 | 0.0 | 0.0 | 703.8 | |||||||||||||||||||||
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2013 | ||||||||||||||||||||||||||||
Revenues—external | $ | 1,949.6 | $ | 392.7 | $ | 0.0 | $ | 0.0 | $ | 12.8 | $ | 0.0 | $ | 2,355.1 | ||||||||||||||
Sales to affiliates | 0.9 | 0.8 | 0.0 | 0.0 | 0.5 | (2.2 | ) | 0.0 | ||||||||||||||||||||
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Total revenues | 1,950.5 | 393.5 | 0.0 | 0.0 | 13.3 | (2.2 | ) | 2,355.1 | ||||||||||||||||||||
Depreciation and amortization | 238.8 | 51.5 | 0.0 | 0.0 | 1.5 | 0.0 | 291.8 | |||||||||||||||||||||
Total interest charges(1) | 91.8 | 13.5 | 0.0 | 0.0 | 63.9 | (7.8 | ) | 161.4 | ||||||||||||||||||||
Internally allocated interest(1) | 0.0 | 0.0 | 0.0 | 0.0 | 7.8 | (7.8 | ) | 0.0 | ||||||||||||||||||||
Provision for income taxes | 116.9 | 21.9 | 0.0 | 0.0 | (26.2 | ) | 0.0 | 112.6 | ||||||||||||||||||||
Net income from continuing operations | 190.9 | 34.7 | 0.0 | 0.0 | (36.9 | ) | 0.0 | 188.7 | ||||||||||||||||||||
Discontinued operations, net of tax | 0.0 | 0.0 | 0.0 | 9.0 | 0.0 | 0.0 | 9.0 | |||||||||||||||||||||
Net income | 190.9 | 34.7 | 0.0 | 9.0 | (36.9 | ) | 0.0 | 197.7 | ||||||||||||||||||||
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Total assets(7) | 6,113.2 | 1,020.1 | 0.0 | 316.3 | (3) | 1,727.6 | (1,755.6 | )(6) | 7,421.6 | |||||||||||||||||||
Capital expenditures | 422.3 | 79.0 | 0.0 | 22.4 | 2.4 | 0.0 | 526.1 | |||||||||||||||||||||
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(1) | Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2015, 2014 and 2013 were at a pretax rate of 6.00%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure. |
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(2) | All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Other, including Parent and TECO Diversified, that directly relate to TECO Coal or TECO Guatemala. SeeNote 19. |
(3) | The carrying value of mineral rights as of Dec. 31, 2015, 2014 and 2013 was $0.0 million, $10.9 million and $12.1 million, respectively. |
(4) | NMGI is included in the Other segment. |
(5) | Certain prior year amounts have been reclassified to conform to current year presentation. |
(6) | Amounts primarily relate to consolidated tax eliminations. |
(7) | Reclassified in accordance with the new accounting pronouncement on presentation of debt issuance costs (seeNote 2). |
15. Asset Retirement Obligations
TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.
When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.
Prior to the sale of TECO Coal on Sept. 21, 2015, TECO Energy had recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations were related to environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2014, these obligations totaled $22.5 million and were classified as Liabilities Associated with Assets Held for Sale on TECO Energy’s Consolidated Balance Sheet.
TECO Energy’s regulated utilities must file depreciation and dismantlement studies periodically and receive approval from the FPSC or NMPRC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.
For Tampa Electric, PGS and NMGC, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2015 and 2014, these obligations totaled $6.8 million and $6.1 million, respectively.
Reconciliation of beginning and ending carrying amount of asset retirement obligations:
Dec. 31, | ||||||||
(millions) | 2015 | 2014 | ||||||
Beginning balance | $ | 6.1 | $ | 28.6 | ||||
Additional liabilities | 0.9 | 0.1 | ||||||
Revisions to estimated cash flows | (0.5 | ) | 0.2 | |||||
Acquisition of NMGC | 0.0 | 0.8 | ||||||
Reclassification to liabilities associated with assets held for sale | 0.0 | (22.5 | ) | |||||
Other(1) | 0.3 | (1.1 | ) | |||||
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Ending balance | $ | 6.8 | $ | 6.1 | ||||
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(1) | 2015 includes $0.3 million accretion recorded as a deferred regulatory asset. 2014 includes $(1.3) million of activity associated with TECO Coal and classified as discontinued operations and $0.2 million accretion recorded as a deferred regulatory asset. |
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16. 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:
• | To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; and |
• | To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates. |
TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.
The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.
The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (seeNote 17). 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 (seeNote 3).
The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Dec. 31, 2015, all of the company’s physical contracts qualify for the NPNS exception.
The derivatives that are designated as cash flow hedges at Dec. 31, 2015 and 2014 are reflected on the company’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.2 and $0.0 million as of Dec. 31, 2015 and 2014, respectively, and are included in “Prepayments and other current assets” on the Consolidated Balance Sheet. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.
All of the derivative asset and liabilities at Dec. 31, 2015 and 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at Dec. 31, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.
The Dec. 31, 2015 and 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented inNote 10.
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 years ended Dec. 31, 2015, 2014 and 2013, 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 years ended Dec. 31, 2015, 2014 and 2013 is presented inNote 10. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in “Interest expense” for TEC and “Income (loss) from discontinued operations” for TECO Coal.
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The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017 fiscal years:
Natural Gas Contracts | ||||||||
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Year | Physical | Financial | ||||||
2016 | 0.0 | 38.4 | ||||||
2017 | 0.0 | 5.1 | ||||||
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Total | 0.0 | 43.5 | ||||||
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The company 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. 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 Dec. 31, 2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.
The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.
The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.
Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.
17. 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. |
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Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:
(A) | Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; |
(B) | Cost approach:Amount that would be required to replace the service capacity of an asset (replacement cost); and |
(C) | Income approach:Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). |
The fair value of financial instruments is determined by using various market data and other valuation techniques.
The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Dec. 31, 2015 and 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Recurring Fair Value Measures
As of Dec. 31, 2015 | ||||||||||||||||
(millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 0.2 | $ | 0.0 | $ | 0.2 | ||||||||
Liabilities | �� | |||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 26.2 | $ | 0.0 | $ | 26.2 | ||||||||
As of Dec. 31, 2014 | ||||||||||||||||
(millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Liabilities | ||||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 42.7 | $ | 0.0 | $ | 42.7 |
The natural gas derivatives are OTC swap and option instruments. Fair values of swaps and options are estimated utilizing the market and income approach, respectively. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap and option positions to determine the fair value (seeNote 16).
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 Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.
SeeNotes 5, 7 and 19for information regarding the fair value of the company’s pension plan investments, long-term debt, and asset impairment charge, respectively.
18. Variable Interest Entities
The determination of a VIE’s 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.
Tampa Electric 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 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric
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has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 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 Balance Sheets, Statements of Income or Cash Flows.
19. Discontinued Operations, Assets Held for Sale and Asset Impairments
TECO Coal
In 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in the fourth quarter of 2013 on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that were recoverable; therefore, no impairment charge was deemed necessary in 2013. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.
In September 2014, the Board of Directors of TECO Energy authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal.
In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value based on the price specified in an agreement of sale entered into in October 2014, which agreement had conditions to closing that were not satisfied, less estimated costs of the transaction. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded, which included the estimated selling costs associated with the transaction completed in September 2015. The fair value measurements were considered Level 2 measurements 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). None of these impairments had cash flow impacts. The asset impairment charges are recorded in the “Income (loss) from discontinued operations” line item in the Consolidated Statements of Income and the “Asset impairment” line item in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2014 and 2015.
On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into the SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian. The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees inNote 12). The company recorded a loss on sale of $10.0 million pretax, which is reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income, primarily to write off an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations previously recorded in AOCI. Transaction-related costs of $12.3 million pretax, comprised of $2.5 million of legal and other consultant costs and $9.8 million of severance and other employee costs, were accrued at June 30, 2015 and reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income. The transaction-related costs were paid in 2015, with the exception of a minor amount of severance payments.
Since the closing of the sale, TECO Energy has not and will not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.
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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:
Assets held for sale | ||||
(millions) | Dec. 31, 2014 | |||
Current assets | $ | 109.6 | ||
Property, plant and equipment, net and other long-term assets | 59.8 | |||
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Total assets held for sale | $ | 169.4 | ||
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Liabilities associated with assets held for sale | ||||
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Current liabilities | $ | 39.4 | ||
Long-term liabilities | 65.4 | |||
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Total liabilities associated with assets held for sale | $ | 104.8 | ||
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TECO Guatemala
In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (seeNote 12). The 2015 charges shown in the table below are legal costs associated with that claim. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.
Combined components of income from discontinued operations
The following table provides selected components of discontinued operations related to TECO Coal and TECO Guatemala:
Components of income from discontinued operations | ||||||||||||
(millions) | 2015 | 2014 | 2013 | |||||||||
Revenues—TECO Coal | $ | 200.4 | $ | 443.6 | $ | 496.2 | ||||||
Income (loss) from operations—TECO Coal | (16.9 | ) | (13.9 | ) | 5.4 | |||||||
Income (loss) from operations—TECO Guatemala | (0.8 | ) | 4.4 | (0.2 | ) | |||||||
Loss on impairment—TECO Coal | (78.6 | ) | (115.9 | ) | 0.0 | |||||||
Loss on sale—TECO Coal | (10.0 | ) | 0.0 | 0.0 | ||||||||
Income (loss) from discontinued operations—TECO Coal | (105.5 | ) | (129.8 | ) | 5.4 | |||||||
Income (loss) from discontinued operations—TECO Guatemala | (0.8 | ) | 4.4 | (0.2 | ) | |||||||
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Income (loss) from discontinued operations | (106.3 | ) | (125.4 | ) | 5.2 | |||||||
Provision (benefit) for income taxes | (38.6 | ) | (49.4 | ) | (3.8 | ) | ||||||
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Income (loss) from discontinued operations, net | $ | (67.7 | ) | $ | (76.0 | ) | $ | 9.0 | ||||
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20. Goodwill
The following table presents the changes in the carrying amount of goodwill for the years ended Dec. 31, 2015, 2014 and 2013.
(millions) | NMGC | Total | ||||||
Balance as of Dec. 31, 2013 | $ | 0.0 | $ | 0.0 | ||||
Acquisition of NMGC | 408.3 | 408.3 | ||||||
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Balance as of Dec. 31, 2014 | 408.3 | 408.3 | ||||||
Measurement period adjustments(1) | 0.1 | 0.1 | ||||||
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Balance as of Dec. 31, 2015 | $ | 408.4 | $ | 408.4 | ||||
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(1) | Due to immateriality, the measurement period adjustment was not applied retrospectively to the opening balance sheet. |
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The goodwill on the company’s balance sheet related to the NMGC segment was recorded upon acquisition of NMGI on Sept. 2, 2014 (seeNote 21). Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. Since NMGC is the lowest level of identifiable cash flows, this is the level at which goodwill is tested. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. TECO Energy reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit.
The fair value for NMGC was determined in the fourth quarter using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of NMGC’s projected cash flows. It includes an estimate of NMGC’s terminal value based on these expected cash flows using the Gordon Growth Formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to EBITDA of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then applied to the last-twelve-months EBITDA of the subject company. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the terminal value.
The company determined the fair value of NMGC exceeds the book value and related goodwill carrying amounts at Dec. 31, 2015 and 2014, resulting in no impairment charge. Adverse changes in assumptions described above could result in a future material impairment of NMGC’s goodwill.
21. Mergers and Acquisitions
Pending Merger with Emera Inc.
On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.
Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.
Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.
The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC, was obtained on Jan. 20, 2016) (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.
The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.
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In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.
TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.
The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.
During the year ended Dec. 31, 2015, TECO Energy incurred approximately $17.0 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.
Acquisition of New Mexico Gas Company
Description of Transaction
On Sept. 2, 2014, the company completed the acquisition of NMGI contemplated by the acquisition agreement 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
On the acquisition date, NMGC, with approximately 720 employees, served 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 served 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
• | A transformative transaction that immediately added more than 513,000 customers in a single state. |
• | Provides an opportunity for TECO Energy’s experienced management team to share marketing expertise to a new and growing service territory, and for both companies to share best practices to support growth. |
• | Diversifies TECO Energy’s operating footprint. |
• | Provides immediate to near-term shareholder and customer benefits through organic growth opportunities. |
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)
B-50
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:
• | freeze rates for NMGC customers until the end of 2017, |
• | credit NMGC customers with a $2 million rate credit to customer bills in 2015, increasing to $4 million per year in 2016 and each year after 2016 until NMGC’s next rate case, |
• | cap job losses in New Mexico at 99 over three years, many of which will be through attrition, |
• | maintain the NMGC name and headquarters in Albuquerque, |
• | support new economic development opportunities designed to attract new businesses to New Mexico through maintaining good service and reasonable customer rates, |
• | maintain or increase NMGC’s current level of community involvement and support, and |
• | own NMGC for at least 10 years. |
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:
Consideration Transferred | ||||
(millions) | ||||
Cash paid to seller | $ | 530.1 | ||
Cash paid to settle long-term debt, including accrued interest and fees | 219.9 | |||
Long-term debt assumed | 200.0 | |||
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Total consideration transferred, excluding cash and working capital adjustments | $ | 950.0 | ||
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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 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 were recorded related to this portion of the goodwill.
B-51
The final purchase price allocation of the acquisition of NMGI and NMGC was as follows:
Purchase Price Allocation | ||||
(millions) | ||||
Current assets(1) | $ | 48.7 | ||
Property, plant and equipment | 616.4 | |||
OPEB regulatory asset | 6.4 | |||
Debt-related regulatory asset | 23.9 | |||
Goodwill | 408.4 | |||
Deferred tax assets | 52.8 | |||
Other assets | 29.3 | |||
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Total assets | $ | 1,185.9 | ||
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Current liabilities | $ | (38.2 | ) | |
Long-term debt fair value adjustment and interest assumed | (22.7 | ) | ||
Cost of removal regulatory liability | (100.6 | ) | ||
Deferred tax liabilities | (60.8 | ) | ||
OPEB liability | (9.8 | ) | ||
Deferred credits and other liabilities | (3.8 | ) | ||
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Total liabilities | $ | (235.9 | ) | |
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| |||
Total purchase price allocation, excluding cash and working capital adjustments | $ | 950.0 | ||
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(1) | Includes accounts receivables with fair value of $18.9 million, gross contract value of $19.6 million, and $0.7 million of contractual receivables not expected to be collected. |
Impact of Acquisition
The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $316.5 million and $137.5 million, respectively. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $19.6 million and $8.2 million, respectively.
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.
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 $8.6 million and $6.2 million for the years ended Dec. 31, 2014 and 2013, respectively.
Pro Forma Impact of Acquisition | For the year ended Dec. 31, | |||||||
(millions, except per share amounts) | 2014 | 2013 | ||||||
Revenues | $ | 2,806.6 | $ | 2,704.0 | ||||
Net income from continuing operations | 223.8 | 216.8 | ||||||
Basic and diluted EPS from continuing operations | 0.96 | 0.93 |
B-52
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 Statement of Income for the years ended Dec. 31, 2015 and 2014.
Transaction and Integration Costs | For the year ended Dec. 31, | |||||||
(millions) | 2015 | 2014 | ||||||
Legal and other consultants | $ | 0.5 | $ | 8.0 | ||||
Bridge loan costs | 0.0 | 3.3 | ||||||
Severance and relocation costs | 1.0 | 2.8 | ||||||
Other costs and tax benefit | 0.4 | (5.5 | ) | |||||
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| |||||
Total accounting charges | $ | 1.9 | $ | 8.6 | ||||
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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 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 substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Dec. 31, 2015 and 2014, the obligations associated with the severance benefits costs were $0.7 million and $2.6 million, respectively.
22. Quarterly Data (unaudited)
Financial data by quarter is as follows:
(millions, except per share amounts) | ||||||||||||||||
Quarter ended | Dec. 31 | Sept. 30 | June 30 | Mar. 31 | ||||||||||||
2015 | ||||||||||||||||
Revenues | $ | 676.1 | $ | 693.8 | $ | 680.6 | $ | 693.0 | ||||||||
Income from operations | 126.0 | 146.6 | 143.3 | 146.2 | ||||||||||||
Net income from continuing operations | 51.0 | 64.9 | 61.5 | 63.8 | ||||||||||||
Net income | 50.5 | 53.2 | 11.8 | 58.0 | ||||||||||||
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| |||||||||
EPS—Basic | ||||||||||||||||
Net income from continuing operations | $ | 0.22 | $ | 0.28 | $ | 0.26 | $ | 0.27 | ||||||||
Net income | 0.21 | 0.23 | 0.05 | 0.25 | ||||||||||||
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EPS—Diluted | ||||||||||||||||
Net income from continuing operations | $ | 0.22 | $ | 0.28 | $ | 0.26 | $ | 0.27 | ||||||||
Net income | 0.21 | 0.23 | 0.05 | 0.25 | ||||||||||||
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Dividends paid per common share outstanding | $ | 0.225 | $ | 0.225 | $ | 0.225 | $ | 0.225 | ||||||||
Quarter ended | Dec. 31 | Sept. 30 | June 30 | Mar. 31 | ||||||||||||
2014 | ||||||||||||||||
Revenues | $ | 695.5 | $ | 687.2 | $ | 605.7 | $ | 578.0 | ||||||||
Income from operations | 112.1 | 145.7 | 132.0 | 115.6 | ||||||||||||
Net income from continuing operations | 27.4 | 73.0 | 57.6 | 48.4 | ||||||||||||
Net income | 10.8 | 11.1 | 58.4 | 50.1 | ||||||||||||
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EPS—Basic | ||||||||||||||||
Net income from continuing operations | $ | 0.11 | $ | 0.32 | $ | 0.27 | $ | 0.22 | ||||||||
Net income | 0.04 | 0.04 | 0.27 | 0.23 | ||||||||||||
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EPS—Diluted | ||||||||||||||||
Net income from continuing operations | $ | 0.11 | $ | 0.32 | $ | 0.27 | $ | 0.22 | ||||||||
Net income | 0.04 | 0.04 | 0.27 | 0.23 | ||||||||||||
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Dividends paid per common share outstanding | $ | 0.220 | $ | 0.220 | $ | 0.220 | $ | 0.220 |
B-53
Amounts shown include reclassifications to reflect discontinued operations as discussed inNote 19.
23. Subsequent Events
Amendment of TECO Energy/TECO Finance Credit Facility
On Feb. 24, 2016, TECO Energy and TECO Finance entered into Amendment No. 3 to its Fourth Amended and Restated Credit Agreement (the TECO Credit Facility) with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders named therein. The amendment provides that the closing of the Merger will not constitute an event of default under the TECO Credit Facility.
TECO Energy/TECO Finance One-Year Term Loan Facility
In February 2016, TECO Energy (as guarantor) and TECO Finance (as borrower) secured commitments for a $400 million one-year term loan facility, the terms of which provide for closing and funding on Mar. 14, 2016. The proceeds of the facility are to be used to repay at maturity the $250 million aggregate principal amount of TECO Finance 4.00% Notes due Mar. 15, 2016, repay a portion of the drawings under the TECO Credit Facility and for general corporate purposes.
B-54
TECO ENERGY, INC.
Consolidated Condensed Balance Sheets
Unaudited
Assets | Mar. 31, | Dec. 31, | ||||||
(millions) | 2016 | 2015 | ||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 46.1 | $ | 23.8 | ||||
Receivables, less allowance for uncollectibles of $2.1 and $2.1 at Mar. 31, 2016 and Dec. 31, 2015, respectively | 240.1 | 280.7 | ||||||
Inventories, at average cost | ||||||||
Fuel | 118.3 | 113.4 | ||||||
Materials and supplies | 77.1 | 76.8 | ||||||
Regulatory assets | 40.2 | 44.8 | ||||||
Prepayments and other current assets | 25.4 | 30.8 | ||||||
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| |||||
Total current assets | 547.2 | 570.3 | ||||||
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Property, plant and equipment | ||||||||
Utility plant in service | ||||||||
Electric | 7,328.3 | 7,270.3 | ||||||
Gas | 2,154.1 | 2,113.8 | ||||||
Construction work in progress | 816.9 | 794.7 | ||||||
Other property | 16.1 | 15.9 | ||||||
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| |||||
Property, plant and equipment, at original costs | 10,315.4 | 10,194.7 | ||||||
Accumulated depreciation | (2,762.4 | ) | (2,712.9 | ) | ||||
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Total property, plant and equipment, net | 7,553.0 | 7,481.8 | ||||||
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| |||||
Other assets | ||||||||
Regulatory assets | 393.4 | 395.2 | ||||||
Goodwill | 408.4 | 408.4 | ||||||
Deferred charges and other assets | 79.1 | 77.8 | ||||||
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Total other assets | 880.9 | 881.4 | ||||||
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| |||||
Total assets | $ | 8,981.1 | $ | 8,933.5 | ||||
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The accompanying notes are an integral part of the consolidated condensed financial statements.
C-1
TECO ENERGY, INC.
Consolidated Condensed Balance Sheets - continued
Unaudited
Liabilities and Capital | Mar. 31, | Dec. 31, | ||||||
(millions) | 2016 | 2015 | ||||||
Current liabilities | ||||||||
Long-term debt due within one year | $ | 83.3 | $ | 333.3 | ||||
Notes payable | 513.0 | 247.0 | ||||||
Accounts payable | 189.5 | 255.4 | ||||||
Customer deposits | 176.7 | 182.1 | ||||||
Regulatory liabilities | 108.4 | 84.8 | ||||||
Derivative liabilities | 22.3 | 24.1 | ||||||
Interest accrued | 54.0 | 36.2 | ||||||
Taxes accrued | 28.2 | 13.2 | ||||||
Other | 25.2 | 22.6 | ||||||
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Total current liabilities | 1,200.6 | 1,198.7 | ||||||
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Other liabilities | ||||||||
Deferred income taxes | 607.0 | 570.7 | ||||||
Investment tax credits | 10.4 | 10.5 | ||||||
Regulatory liabilities | 709.4 | 715.8 | ||||||
Derivative liabilities | 0.8 | 2.1 | ||||||
Deferred credits and other liabilities | 380.9 | 387.5 | ||||||
Long-term debt, less amount due within one year | 3,489.7 | 3,489.2 | ||||||
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Total other liabilities | 5,198.2 | 5,175.8 | ||||||
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Commitments and contingencies (see Note 10) | ||||||||
Capital | ||||||||
Common equity (400.0 million shares authorized; par value $1; 235.5 million and 235.3 million shares outstanding at Mar. 31, 2016 and Dec. 31, 2015, respectively) | 235.5 | 235.3 | ||||||
Additional paid in capital | 1,894.8 | 1,894.5 | ||||||
Retained earnings | 463.5 | 441.4 | ||||||
Accumulated other comprehensive loss | (11.5 | ) | (12.2 | ) | ||||
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Total capital | 2,582.3 | 2,559.0 | ||||||
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Total liabilities and capital | $ | 8,981.1 | $ | 8,933.5 | ||||
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The accompanying notes are an integral part of the consolidated condensed financial statements.
C-2
TECO ENERGY, INC.
Consolidated Condensed Statements of Income
Unaudited
Three months ended Mar. 31, | ||||||||||||
(millions, except per share amounts) | 2016 | 2015 | ||||||||||
Revenues | ||||||||||||
Regulated electric | $ | 423.4 | $ | 449.7 | ||||||||
Regulated gas | 232.9 | 240.2 | ||||||||||
Unregulated | 3.2 | 3.1 | ||||||||||
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Total revenues | 659.5 | 693.0 | ||||||||||
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Expenses | ||||||||||||
Regulated operations and maintenance | ||||||||||||
Fuel | 115.2 | 144.1 | ||||||||||
Purchased power | 14.4 | 17.1 | ||||||||||
Cost of natural gas sold | 96.8 | 103.0 | ||||||||||
Other | 142.3 | 143.7 | ||||||||||
Operation and maintenance other expense | 0.0 | 1.6 | ||||||||||
Depreciation and amortization | 89.8 | 85.5 | ||||||||||
Taxes, other than income | 52.9 | 51.8 | ||||||||||
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Total expenses | 511.4 | 546.8 | ||||||||||
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Income from operations | 148.1 | 146.2 | ||||||||||
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Other income | ||||||||||||
Allowance for other funds used during construction | 5.7 | 3.8 | ||||||||||
Other income, net | 1.5 | 1.6 | ||||||||||
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Total other income | 7.2 | 5.4 | ||||||||||
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Interest charges | ||||||||||||
Interest expense | 48.9 | 49.8 | ||||||||||
Allowance for borrowed funds used during construction | (3.0 | ) | (1.9 | ) | ||||||||
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| |||||||||
Total interest charges | 45.9 | 47.9 | ||||||||||
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| |||||||||
Income from continuing operations before provision for income taxes | 109.4 | 103.7 | ||||||||||
Provision for income taxes | 35.7 | 39.9 | ||||||||||
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| |||||||||
Net income from continuing operations | 73.7 | 63.8 | ||||||||||
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Discontinued operations | ||||||||||||
Income (loss) from discontinued operations | 0.2 | (9.6 | ) | |||||||||
Provision (benefit) from income taxes | 0.1 | (3.8 | ) | |||||||||
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Income (loss) from discontinued operations, net | 0.1 | (5.8 | ) | |||||||||
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Net income | $ | 73.8 | $ | 58.0 | ||||||||
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Average common shares outstanding | – Basic | 234.0 | 232.8 | |||||||||
– Diluted | 235.2 | 233.5 | ||||||||||
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Earnings per share from continuing operations | – Basic | $ | 0.31 | $ | 0.27 | |||||||
– Diluted | $ | 0.31 | $ | 0.27 | ||||||||
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Earnings per share from discontinued operations | – Basic | $ | 0.00 | $ | (0.02 | ) | ||||||
– Diluted | $ | 0.00 | $ | (0.02 | ) | |||||||
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Earnings per share | – Basic | $ | 0.31 | $ | 0.25 | |||||||
– Diluted | $ | 0.31 | $ | 0.25 | ||||||||
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| |||||||||
Dividends paid per common share outstanding | $ | 0.230 | $ | 0.225 |
The accompanying notes are an integral part of the consolidated condensed financial statements.
C-3
TECO ENERGY, INC.
Consolidated Condensed Statements of Comprehensive Income
Unaudited
Three months ended Mar. 31, | ||||||||
(millions) | 2016 | 2015 | ||||||
Net income | $ | 73.8 | $ | 58.0 | ||||
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Other comprehensive income, net of tax | ||||||||
Gain on cash flow hedges | 0.2 | 0.3 | ||||||
Amortization of unrecognized benefit costs | 0.5 | 0.6 | ||||||
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| |||||
Other comprehensive income, net of tax | 0.7 | 0.9 | ||||||
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Comprehensive income | $ | 74.5 | $ | 58.9 | ||||
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The accompanying notes are an integral part of the consolidated condensed financial statements.
C-4
TECO ENERGY, INC.
Consolidated Condensed Statements of Cash Flows
Unaudited
Three months ended Mar. 31, | ||||||||
(millions) | 2016 | 2015 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 73.8 | $ | 58.0 | ||||
Adjustments to reconcile net income to net cash from operating activities: | ||||||||
Depreciation and amortization | 89.8 | 85.9 | ||||||
Deferred income taxes and investment tax credits | 36.1 | 36.0 | ||||||
Allowance for other funds used during construction | (5.7 | ) | (3.8 | ) | ||||
Non-cash stock compensation | 3.0 | 3.9 | ||||||
Deferred recovery clauses | 26.4 | (5.7 | ) | |||||
Receivables, less allowance for uncollectibles | 40.6 | 51.0 | ||||||
Inventories | (5.2 | ) | (15.7 | ) | ||||
Prepayments and other current assets | 2.8 | (10.9 | ) | |||||
Taxes accrued | 18.1 | 1.7 | ||||||
Interest accrued | 17.8 | 17.8 | ||||||
Accounts payable | (59.1 | ) | (63.5 | ) | ||||
Other | (6.8 | ) | (7.7 | ) | ||||
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| |||||
Cash flows from operating activities | 231.6 | 147.0 | ||||||
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| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (168.0 | ) | (156.2 | ) | ||||
Other investing activities | (0.2 | ) | (0.2 | ) | ||||
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| |||||
Cash flows used in investing activities | (168.2 | ) | (156.4 | ) | ||||
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| |||||
Cash flows from financing activities | ||||||||
Dividends and dividend equivalents | (54.3 | ) | (53.0 | ) | ||||
Proceeds from the sale of common stock | 3.9 | 2.8 | ||||||
Repayment of long-term debt/purchase in lieu of redemption | (250.0 | ) | 0.0 | |||||
Net increase (decrease) in short-term debt (maturities of 90 days or less) | (134.0 | ) | 67.0 | |||||
Proceeds from other short-term debt (maturities over 90 days) | 400.0 | 0.0 | ||||||
Other financing activities | (6.7 | ) | 0.0 | |||||
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| |||||
Cash flows from (used in) financing activities | (41.1 | ) | 16.8 | |||||
|
|
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| |||||
Net increase in cash and cash equivalents | 22.3 | 7.4 | ||||||
Cash and cash equivalents at beginning of the period | 23.8 | 25.4 | ||||||
|
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| |||||
Cash and cash equivalents at end of the period | $ | 46.1 | $ | 32.8 | ||||
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| |||||
Supplemental disclosure of non-cash activities | ||||||||
Change in accrued capital expenditures | $ | (6.0 | ) | $ | 11.5 |
The accompanying notes are an integral part of the consolidated condensed financial statements.
C-5
TECO ENERGY, INC.
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 intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 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 Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. SeeNote 16 for further information.
Revenues
As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3 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 prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 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
Presentation of Debt Issuance Costs
In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the company classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.
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Stock Compensation
In March 2016, the FASB issued guidance regarding employee share-based payment accounting. The guidance simplifies 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 liability, and presentation on the statement of cash flows. This guidance will be required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact and was implemented as follows:
• | Income tax consequences – Under the new guidance, the company will no longer recognize excess tax benefits and certain tax deficiencies in additional paid in capital. Instead, the company will recognize all excess tax benefits and tax deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize them. Accordingly, the company recorded a $2.6 million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. In accordance with the new guidance, the company will no longer include excess tax benefits and tax deficiencies in the dilutive EPS calculation on a prospective basis. |
• | Accounting for forfeitures – The company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods. |
• | Classification of awards - The company had no share-based payments classified as liability awards as of Mar. 31, 2016 or Dec. 31, 2015. |
• | Presentation on the statement of cash flows – Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a retrospective basis for all periods presented. Previously, the company presented it as an operating activity. There was an immaterial amount of activity that did not result in an adjustment to the statement of cash flows for the three months ended Mar. 31, 2015. |
Future Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, 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 for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. 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, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.
Leases
In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.
Derivative Contract Novations
In March 2016, the FASB issued guidance clarifying 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 guidance is effective for the company beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on future derivative contract novations, if any.
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3. Regulatory
Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. 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 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 such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.
Regulatory Assets and Liabilities
Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.
Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:
Regulatory Assets and Liabilities
(millions) | Mar. 31, 2016 | Dec. 31, 2015 | ||||||
Regulatory assets: | ||||||||
Regulatory tax asset(1) | $ | 77.1 | $ | 74.7 | ||||
Cost-recovery clauses - deferred balances (2) | 0.1 | 5.5 | ||||||
Cost-recovery clauses - offsets to derivative liabilities(2) | 26.0 | 26.5 | ||||||
Environmental remediation(3) | 54.4 | 54.0 | ||||||
Postretirement benefits(4) | 238.5 | 240.6 | ||||||
Deferred bond refinancing costs(5) | 6.2 | 6.5 | ||||||
Debt basis adjustment(6) | 16.7 | 17.5 | ||||||
Competitive rate adjustment(2) | 2.5 | 2.6 | ||||||
Other | 12.1 | 12.1 | ||||||
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Total regulatory assets | 433.6 | 440.0 | ||||||
Less: Current portion | 40.2 | 44.8 | ||||||
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Long-term regulatory assets | $ | 393.4 | $ | 395.2 | ||||
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Regulatory liabilities: | ||||||||
Regulatory tax liability | $ | 7.6 | $ | 7.9 | ||||
Cost-recovery clauses (2) | 80.0 | 55.9 | ||||||
Transmission and delivery storm reserve | 56.1 | 56.1 | ||||||
Accumulated reserve - cost of removal(7) | 673.6 | 679.9 | ||||||
Other | 0.5 | 0.8 | ||||||
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Total regulatory liabilities | 817.8 | 800.6 | ||||||
Less: Current portion | 108.4 | 84.8 | ||||||
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Long-term regulatory liabilities | $ | 709.4 | $ | 715.8 | ||||
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(1) | The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. |
(2) | These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. |
(3) | This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation. |
C-8
(4) | This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants. |
(5) | This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments. |
(6) | This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument. |
(7) | This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. |
4. Income Taxes
The effective tax rate decreased to 32.63% for the three months ended Mar. 31, 2016 from 38.48% for the same period in 2015 primarily due to the tax benefit related to long-term incentive compensation share vestings (seeNote 2for further description).
The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. 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. TECO Energy does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.
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.
Pension Expense
(millions) | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
Three months ended Mar. 31, | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Components of net periodic benefit expense | ||||||||||||||||
Service cost | $ | 4.4 | $ | 4.5 | $ | 0.5 | $ | 0.6 | ||||||||
Interest cost | 8.1 | 7.4 | 2.2 | 2.0 | ||||||||||||
Expected return on assets | (11.3 | ) | (10.8 | ) | (0.3 | ) | (0.3 | ) | ||||||||
Amortization of: | ||||||||||||||||
Prior service (benefit) cost | 0.0 | (0.1 | ) | (0.6 | ) | (0.6 | ) | |||||||||
Actuarial loss | 3.4 | 3.4 | 0.0 | 0.0 | ||||||||||||
Regulatory asset | 0.0 | 0.0 | 0.2 | 0.3 | ||||||||||||
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Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income | $ | 4.6 | $ | 4.4 | $ | 2.0 | $ | 2.0 | ||||||||
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For the fiscal 2016 plan year, TECO Energy is using 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. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan for the three months ended Mar. 31, 2016 and 2015, respectively.
For the three months ended Mar. 31, 2016 and 2015, TECO Energy and its subsidiaries reclassified $0.8 million of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2016 and 2015, the regulated companies reclassified $2.2 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.
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6. Short-Term Debt
At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:
Credit Facilities
Mar. 31, 2016 | Dec. 31, 2015 | |||||||||||||||||||||||
Letters | Letters | |||||||||||||||||||||||
Credit | Borrowings | of Credit | Credit | Borrowings | of Credit | |||||||||||||||||||
(millions) | Facilities | Outstanding (1) | Outstanding | Facilities | Outstanding (1) | Outstanding | ||||||||||||||||||
Tampa Electric Company: | ||||||||||||||||||||||||
5-year facility(2) | $ | 325.0 | $ | 0.0 | $ | 0.5 | $ | 325.0 | $ | 0.0 | $ | 0.5 | ||||||||||||
3-year accounts receivable facility(3) | 150.0 | 0.0 | 0.0 | 150.0 | 61.0 | 0.0 | ||||||||||||||||||
TECO Energy/TECO Finance: | ||||||||||||||||||||||||
5-year facility(2)(4) | 300.0 | 113.0 | 0.0 | 300.0 | 163.0 | 0.0 | ||||||||||||||||||
1-year term facility(4)(5) | 400.0 | 400.0 | 0.0 | 0.0 | 0.0 | 0.0 | ||||||||||||||||||
New Mexico Gas Company: | ||||||||||||||||||||||||
5-year facility (2) | 125.0 | 0.0 | 1.7 | 125.0 | 23.0 | 1.7 | ||||||||||||||||||
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Total | $ | 1,300.0 | $ | 513.0 | $ | 2.2 | $ | 900.0 | $ | 247.0 | $ | 2.2 | ||||||||||||
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(1) | Borrowings outstanding are reported as notes payable. |
(2) | This 5-year facility matures Dec. 17, 2018. |
(3) | Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018. |
(4) | TECO Finance is the borrower and TECO Energy is the guarantor of this facility. |
(5) | This 1-year facility matures Mar. 14, 2017. |
At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.44% and 1.29%, respectively.
TECO Energy/TECO Finance Credit Facility
On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.
7. Long-Term Debt
Fair Value of Long-Term Debt
At Mar. 31, 2016, total long-term debt had a carrying amount of $3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 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 (seeNote 13 for information regarding the fair value hierarchy).
Purchase in Lieu of Redemption of Revenue Refunding Bonds
On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds) in a term rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.
C-10
As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.
8. Other Comprehensive Income
TECO Energy reported the following OCI for the three months ended Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:
Other Comprehensive Income
Three months ended Mar. 31, | ||||||||||||
(millions) | Gross | Tax | Net | |||||||||
2016 | ||||||||||||
Unrealized gain on cash flow hedges | $ | 0.0 | $ | 0.0 | $ | 0.0 | ||||||
Reclassification from AOCI to net income(1) | 0.3 | (0.1 | ) | 0.2 | ||||||||
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Gain on cash flow hedges | 0.3 | (0.1 | ) | 0.2 | ||||||||
Amortization of unrecognized benefit costs(2) | 0.8 | (0.3 | ) | 0.5 | ||||||||
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Total other comprehensive income | $ | 1.1 | $ | (0.4 | ) | $ | 0.7 | |||||
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2015 | ||||||||||||
Unrealized gain on cash flow hedges | $ | 0.3 | $ | (0.2 | ) | $ | 0.1 | |||||
Reclassification from AOCI to net income(1) | 0.4 | (0.2 | ) | 0.2 | ||||||||
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Gain on cash flow hedges | 0.7 | (0.4 | ) | 0.3 | ||||||||
Amortization of unrecognized benefit costs(2) | 0.9 | (0.3 | ) | 0.6 | ||||||||
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Total other comprehensive income | $ | 1.6 | $ | (0.7 | ) | $ | 0.9 | |||||
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(1) | Related to interest rate contracts recognized in Interest expense. |
(2) | Related to postretirement and postemployment benefits. SeeNote 5for additional information. |
Accumulated Other Comprehensive Loss
(millions) | Mar. 31, 2016 | Dec. 31, 2015 | ||||||
Unamortized pension loss and prior service credit(1) | $ | (33.6 | ) | $ | (34.2 | ) | ||
Unamortized other benefit gains, prior service costs and transition obligations(2) | 25.5 | 25.6 | ||||||
Net unrealized losses from cash flow hedges(3) | (3.4 | ) | (3.6 | ) | ||||
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Total accumulated other comprehensive loss | $ | (11.5 | ) | $ | (12.2 | ) | ||
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(1) | Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. |
(2) | Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. |
(3) | Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. |
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9. Earnings Per Share
For the three months ended Mar. 31, | ||||||||
(millions, except per share amounts) | 2016 | 2015 | ||||||
Basic earnings per share | ||||||||
Net income from continuing operations | $ | 73.7 | $ | 63.8 | ||||
Amount allocated to nonvested participating shareholders | (0.1 | ) | (0.2 | ) | ||||
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Income before discontinued operations available to common shareholders - Basic | $ | 73.6 | $ | 63.6 | ||||
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Income (loss) from discontinued operations, net | $ | 0.1 | $ | (5.8 | ) | |||
Amount allocated to nonvested participating shareholders | 0.0 | 0.0 | ||||||
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Income (loss) from discontinued operations available to common shareholders - Basic | $ | 0.1 | $ | (5.8 | ) | |||
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Net income | $ | 73.8 | $ | 58.0 | ||||
Amount allocated to nonvested participating shareholders | (0.1 | ) | (0.2 | ) | ||||
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Net income available to common shareholders - Basic | $ | 73.7 | $ | 57.8 | ||||
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Average common shares outstanding - Basic | 234.0 | 232.8 | ||||||
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Earnings per share from continuing operations available to common shareholders - Basic | $ | 0.31 | $ | 0.27 | ||||
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Earnings per share from discontinued operations available to common shareholders - Basic | 0.0 | $ | (0.02 | ) | ||||
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Earnings per share available to common shareholders - Basic | $ | 0.31 | $ | 0.25 | ||||
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Diluted earnings per share | ||||||||
Net income from continuing operations | $ | 73.7 | $ | 63.8 | ||||
Amount allocated to nonvested participating shareholders | (0.1 | ) | (0.2 | ) | ||||
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Income before discontinued operations available to common shareholders - Diluted | $ | 73.6 | $ | 63.6 | ||||
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Income (loss) from discontinued operations, net | $ | 0.1 | $ | (5.8 | ) | |||
Amount allocated to nonvested participating shareholders | 0.0 | 0.0 | ||||||
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Income (loss) from discontinued operations available to common shareholders - Diluted | $ | 0.1 | $ | (5.8 | ) | |||
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Net income | $ | 73.8 | $ | 58.0 | ||||
Amount allocated to nonvested participating shareholders | (0.1 | ) | (0.2 | ) | ||||
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Net income available to common shareholders - Diluted | $ | 73.7 | $ | 57.8 | ||||
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Unadjusted average common shares outstanding - Diluted | 234.0 | 232.8 | ||||||
Assumed conversion of stock options, unvested restricted stock, unvested RSUs and contingent performance shares, net | 1.2 | 0.7 | ||||||
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Average common shares outstanding - Diluted | 235.2 | 233.5 | ||||||
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Earnings per share from continuing operations available to common shareholders - Diluted | $ | 0.31 | $ | 0.27 | ||||
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Earnings per share from discontinued operations available to common shareholders - Diluted | 0.0 | $ | (0.02 | ) | ||||
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Earnings per share available to common shareholders - Diluted | $ | 0.31 | $ | 0.25 | ||||
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Anti-dilutive shares | 0.2 | 0.1 | ||||||
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10. Commitments and Contingencies
Legal Contingencies
From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.
Peoples Gas Legal Proceedings
In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.
New Mexico Gas Company Legal Proceedings
In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).
In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”
In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Mar. 31, 2016.
In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.
Proceedings in connection with the Pending Merger with Emera
Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction. Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger. In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.
The company also received two separate shareholder demand letters from purported shareholders of the company. Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices. One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.
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In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger. As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement. Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.
Claim in connection with the Sale of TECO Coal
As discussed inNote 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. On Mar. 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting breach of certain representations, and fraud and willful misconduct in connection therewith, of the SPA.
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, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.
On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.
Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.
On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to TGH. As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.
PGS Compliance Matter
In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed. As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.
Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 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, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.
The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
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In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.
Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.
Guarantees and Letters of Credit
A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows:
(millions) | After (1) | Maximum Theoretical | Liabilities Recognized | |||||||||||||||||
Guarantees for the Benefit of: | 2016 | 2017-2020 | 2020 | Obligation | at Mar. 31, 2016 | |||||||||||||||
TECO Energy | ||||||||||||||||||||
Fuel sales and transportation(2) | $ | 0.0 | $ | 0.0 | $ | 92.9 | $ | 92.9 | $ | 0.0 | ||||||||||
Letters of indemnity - coal mining permits(3) | 89.4 | 0.0 | 0.0 | 89.4 | 0.0 | |||||||||||||||
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$ | 89.4 | $ | 0.0 | $ | 92.9 | $ | 182.3 | $ | 0.0 | |||||||||||
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(millions) Letters of Credit for the Benefit of: | 2016 | 2017-2020 | After (1) 2020 | Maximum Theoretical Obligation | Liabilities Recognized at Mar. 31, 2016(4) | |||||||||||||||
TEC | $ | 0.0 | $ | 0.0 | $ | 0.5 | $ | 0.5 | $ | 0.1 | ||||||||||
NMGC | 0.0 | 0.0 | 1.7 | 1.7 | 0.0 | |||||||||||||||
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$ | 0.0 | $ | 0.0 | $ | 2.2 | $ | 2.2 | $ | 0.1 | |||||||||||
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(1) | These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020. |
(2) | The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Mar. 31, 2016. SeeNote 12 for additional information. |
(3) | These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal’s mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed inNote 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities. Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy’s indemnity are released, TECO Energy’s indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained. |
(4) | The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims. |
Financial Covenants
In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.
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11. Segment Information
TECO Energy is an electric and gas utility holding company with diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.
Three months ended Mar. 31, | Tampa Electric | PGS | NMGC(2) | TECO Coal (1) | Other(2) (3) | Eliminations (3) | TECO Energy | |||||||||||||||||||||
2016 | ||||||||||||||||||||||||||||
Revenues - external | $ | 423.4 | $ | 126.8 | $ | 106.6 | $ | 0.0 | $ | 2.7 | $ | 0.0 | $ | 659.5 | ||||||||||||||
Sales to affiliates | 1.1 | 4.4 | 0.0 | 0.0 | 0.0 | (5.5 | ) | 0.0 | ||||||||||||||||||||
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Total revenues | 424.5 | 131.2 | 106.6 | 0.0 | 2.7 | (5.5 | ) | 659.5 | ||||||||||||||||||||
Depreciation and amortization | 66.1 | 14.8 | 8.4 | 0.0 | 0.5 | 0.0 | 89.8 | |||||||||||||||||||||
Total interest charges | 23.8 | 3.7 | 3.0 | 0.0 | 15.6 | (0.2 | ) | 45.9 | ||||||||||||||||||||
Internally allocated interest | 0.0 | 0.0 | 0.0 | 0.0 | 0.2 | (0.2 | ) | 0.0 | ||||||||||||||||||||
Provision (benefit) for income taxes | 27.8 | 8.9 | 9.7 | 0.0 | �� | (10.7 | ) | 0.0 | 35.7 | |||||||||||||||||||
Net income (loss) from continuing operations | 50.2 | 13.1 | 15.2 | 0.0 | (4.8 | ) | 0.0 | 73.7 | ||||||||||||||||||||
Income (loss) from discontinued operations, net(1) | 0.0 | 0.0 | 0.0 | 0.0 | 0.1 | 0.0 | 0.1 | |||||||||||||||||||||
Net income (loss) | $ | 50.2 | $ | 13.1 | $ | 15.2 | $ | 0.0 | $ | (4.7 | ) | $ | 0.0 | $ | 73.8 | |||||||||||||
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Revenues - external | $ | 449.8 | $ | 121.7 | $ | 119.0 | $ | 0.0 | $ | 2.5 | $ | 0.0 | $ | 693.0 | ||||||||||||||
Sales to affiliates | 0.8 | 1.2 | 0.0 | 0.0 | 0.0 | (2.0 | ) | 0.0 | ||||||||||||||||||||
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Total revenues | 450.6 | 122.9 | 119.0 | 0.0 | 2.5 | (2.0 | ) | 693.0 | ||||||||||||||||||||
Depreciation and amortization | 62.9 | 13.9 | 8.4 | 0.0 | 0.3 | 0.0 | 85.5 | |||||||||||||||||||||
Total interest charges | 23.5 | 3.5 | 3.3 | 0.0 | 17.9 | (0.3 | ) | 47.9 | ||||||||||||||||||||
Internally allocated interest | 0.0 | 0.0 | 0.0 | 0.0 | 0.3 | (0.3 | ) | 0.0 | ||||||||||||||||||||
Provision (benefit) for income taxes | 27.4 | 9.2 | 9.0 | 0.0 | (5.7 | ) | 0.0 | 39.9 | ||||||||||||||||||||
Net income (loss) from continuing operations | 48.2 | 14.6 | 13.9 | 0.0 | (12.9 | ) | 0.0 | 63.8 | ||||||||||||||||||||
Income (loss) from discontinued operations, net(1) | 0.0 | 0.0 | 0.0 | (6.0 | ) | 0.2 | 0.0 | (5.8 | ) | |||||||||||||||||||
Net income (loss) | $ | 48.2 | $ | 14.6 | $ | 13.9 | $ | (6.0 | ) | $ | (12.7 | ) | $ | 0.0 | $ | 58.0 | ||||||||||||
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At Mar. 31, 2016 | ||||||||||||||||||||||||||||
Total assets | $ | 6,988.2 | $ | 1,147.0 | $ | 1,210.9 | $ | 0.0 | $ | 1,982.1 | $ | (2,347.1 | )(4) | $ | 8,981.1 | |||||||||||||
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At Dec. 31, 2015 | ||||||||||||||||||||||||||||
Total assets(3) | $ | 7,003.8 | $ | 1,136.1 | $ | 1,229.7 | $ | 0.0 | $ | 1,945.1 | $ | (2,381.2 | )(4) | 8,933.5 | ||||||||||||||
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(1) | All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. SeeNote 15. |
(2) | NMGI is included in the Other segment. |
(3) | Certain prior year amounts have been reclassified to conform to current year presentation. |
(4) | Amounts primarily relate to intercompany advances and consolidated tax eliminations. |
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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:
• | To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; |
• | To optimize the utilization of NMGC’s physical natural gas storage capacity, and |
• | To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates. |
TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.
The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.
The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (seeNote 13). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.
The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase and sale of natural gas for the benefit of its regulated companies’ ratepayers. 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 (seeNote 3).
The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Mar. 31, 2016, all of the company’s physical contracts qualify for the NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity.
The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 million and $0.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative liabilities totaled $23.1 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.
All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.
The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented inNote 8.
For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2016 and 2015 is presented inNote 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.
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The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:
Derivative Volumes | Natural Gas Contracts | |||||||
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2016 | 0.0 | 25.1 | ||||||
2017 | 0.0 | 9.9 | ||||||
2018 | 0.0 | 0.7 | ||||||
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The company 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. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.
It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Mar. 31, 2016, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.
The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.
The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.
Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.
13. Fair Value Measurements
Items Measured at Fair Value on a Recurring Basis
Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
Level 1: | Observable inputs, such as quoted prices in active markets; | |
Level 2: | Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and | |
Level 3: | Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. |
C-18
Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:
(A) | Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; |
(B) | Cost approach:Amount that would be required to replace the service capacity of an asset (replacement cost); and |
(C) | Income approach:Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). |
The fair value of financial instruments is determined by using various market data and other valuation techniques.
The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. 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.
Recurring Fair Value Measures
As of Mar. 31, 2016 | ||||||||||||||||
(millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Liabilities | ||||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 23.1 | $ | 0.0 | $ | 23.1 | ||||||||
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(millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 0.2 | $ | 0.0 | $ | 0.2 | ||||||||
Liabilities | ||||||||||||||||
Natural gas derivatives | $ | 0.0 | $ | 26.2 | $ | 0.0 | $ | 26.2 |
The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are estimated utilizing the income approach. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap, forward and option positions to determine the fair value (seeNote 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 Mar. 31, 2016, 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
The determination of a VIE’s 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.
Tampa Electric 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 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.
C-19
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 and Asset Impairments
TECO Coal
On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian. The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees inNote 10). The SPA contained customary representations, warranties and covenants (seeNote 10for description of a claim related to the SPA). The income shown for the first quarter of 2016 in the table below reflects a refund of prepaid costs.
Since the closing of the sale, TECO Energy does not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.
TECO Guatemala
In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (seeNote 10). The charges shown in the table below are legal costs associated with that claim.
Combined Components of Discontinued Operations
The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:
Components of income from discontinued operations
Three months ended | ||||||||
Mar. 31, | ||||||||
(millions) | 2016 | 2015 | ||||||
Revenues—TECO Coal | $ | 0.0 | $ | 72.7 | ||||
Loss from operations—TECO Coal | 0.0 | (9.5 | ) | |||||
Loss from operations—TECO Guatemala | 0.0 | (0.1 | ) | |||||
Income (loss) from discontinued operations—TECO Coal | 0.2 | (9.5 | ) | |||||
Loss from discontinued operations—TECO Guatemala | 0.0 | (0.1 | ) | |||||
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| |||||
Income (loss) from discontinued operations | 0.2 | (9.6 | ) | |||||
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Provision (benefit) for income taxes | 0.1 | (3.8 | ) | |||||
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Income (loss) from discontinued operations, net | $ | 0.1 | $ | (5.8 | ) | |||
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16. Mergers and Acquisitions
Pending Merger with Emera Inc.
On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.
Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.
Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.
C-20
The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.
On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction. In the stipulation, the parties state that they believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its acquisition of NMGC, invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs. The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.
The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.
In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.
TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.
Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.
During the three months ended Mar. 31, 2016, TECO Energy incurred approximately $0.1 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.
C-21
EMERA INCORPORATED
Unaudited Pro Forma Consolidated
Financial Statements
As at and for the three months ended March 31, 2016 and for the year
ended December 31, 2015
D-1
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma consolidated financial information is presented to illustrate the estimated effects of the acquisition (the “Acquisition”) by Emera Incorporated (“Emera” or the “Company”) of TECO Energy Inc. and its subsidiaries (collectively, “TECO Energy”) under the acquisition method of accounting. The unaudited pro forma consolidated balance sheet gives effect to the Acquisition as if it had closed on March 31, 2016. The unaudited pro forma consolidated statements of earnings for the year ended December 31, 2015 and the three months ended March 31, 2016 give effect to the Acquisition as if it had closed on January 1, 2015.
The unaudited pro forma consolidated financial statements are presented for illustrative purposes only. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable in the circumstances, as described in the notes to the unaudited pro forma consolidated financial statements.
The unaudited pro forma consolidated financial statements are based on TECO Energy’s consolidated financial statements as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015. For more information regarding the foreign exchange translation from U.S. Dollars to Canadian Dollars for TECO Energy’s financial statements see “—Notes to the Unaudited Pro Forma Consolidated Financial Statements—Note 3(j): Foreign Exchange Translation.” TECO Coal was sold in 2015 and as a result, the operating results of the TECO Coal segment are reported as discontinued operations.
The pro forma information presented, including allocation of purchase price, is based on preliminary estimates of fair values of assets acquired and liabilities assumed, available information and assumptions and may be revised as additional information becomes available. The actual adjustments to the consolidated financial statements upon the closing of the Acquisition will depend on a number of factors, including additional information available and the net assets of TECO Energy as of the closing date of the Acquisition. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material. For example, the final purchase price allocation is dependent on, among other things, the finalization of asset and liability valuations. A final determination of these fair values will reflect an independent third-party valuation. This final valuation will be based on the actual net tangible and intangible assets and liabilities of TECO Energy that exist as of the closing date of the Acquisition. Any final adjustment may change the allocation of purchase price, which could affect the fair value assigned to the assets and liabilities and could result in a change to the unaudited pro forma consolidated financial statements, including a change to goodwill.
D-2
EMERA INCORPORATED
PRO FORMA CONSOLIDATED BALANCE SHEET
AS AT MARCH 31, 2016
(UNAUDITED)
(In millions of Canadian dollars)
Emera | TECO Energy | Note | Proforma Adjustments | Proforma Consolidated Balance Sheet | ||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets | ||||||||||||||||||||
Cash and cash equivalents | $ | 1,000 | $ | 60 | 3 | [b] | ($ | 8,423 | ) | |||||||||||
3 | [c] | $ | 1,457 | |||||||||||||||||
3 | [c] | ($ | 44 | ) | ||||||||||||||||
3 | [c] | ($ | 42 | ) | ||||||||||||||||
3 | [d] | $ | 6,576 | |||||||||||||||||
3 | [d] | ($ | 118 | ) | ||||||||||||||||
3 | [e] | ($ | 141 | ) | $ | 323 | ||||||||||||||
Restricted cash | $ | 22 | $ | 22 | ||||||||||||||||
Receivables, net | $ | 610 | $ | 311 | $ | 922 | ||||||||||||||
Income taxes receivable | $ | 16 | $ | 16 | ||||||||||||||||
Inventory | $ | 261 | $ | 253 | $ | 514 | ||||||||||||||
Derivative instruments | $ | 92 | $ | 92 | ||||||||||||||||
Regulatory assets | $ | 78 | $ | 52 | $ | 130 | ||||||||||||||
Prepaid expenses | $ | 40 | $ | 33 | $ | 73 | ||||||||||||||
Due from related parties | $ | 2 | $ | 2 | ||||||||||||||||
Other current assets | $ | 168 | $ | 168 | ||||||||||||||||
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|
| |||||||||||||
Total current assets | $ | 2,289 | $ | 709 | ($ | 736 | ) | $ | 2,263 | |||||||||||
Property, plant and equipment, net of accumulated depreciation | $ | 6,015 | $ | 9,797 | $ | 15,812 | ||||||||||||||
Other assets | ||||||||||||||||||||
Income taxes receivable | $ | 48 | $ | 48 | ||||||||||||||||
Deferred income taxes | $ | 47 | 3 | [c] | $ | 28 | ||||||||||||||
3 | [c] | $ | 14 | |||||||||||||||||
3 | [e] | $ | 24 | $ | 113 | |||||||||||||||
Derivative instruments | $ | 85 | $ | 85 | ||||||||||||||||
Pension and post-retirement asset | $ | 9 | $ | 9 | ||||||||||||||||
Regulatory assets | $ | 619 | $ | 510 | $ | 1,129 | ||||||||||||||
Net investment in direct financing lease | $ | 479 | $ | 479 | ||||||||||||||||
Investments subject to significant influence | $ | 1,210 | $ | 1,210 | ||||||||||||||||
Available-for-sale investments | $ | 106 | $ | 106 | ||||||||||||||||
Goodwill | $ | 248 | $ | 530 | 3 | [b] | ($ | 530 | ) | |||||||||||
3 | [b] | $ | 5,660 | $ | 5,908 | |||||||||||||||
Intangibles, net of accumulated amortization | $ | 191 | $ | 191 | ||||||||||||||||
Due from related parties | $ | 3 | $ | 3 | ||||||||||||||||
Other long-term assets | $ | 100 | $ | 103 | $ | 203 | ||||||||||||||
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Total other assets | $ | 3,144 | $ | 1,143 | $ | 5,196 | $ | 9,483 | ||||||||||||
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| |||||||||||||
$ | 11,449 | $ | 11,649 | $ | 4,460 | $ | 27,558 | |||||||||||||
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LIABILITIES AND SHAREHOLDERS EQUITY | ||||||||||||||||||||
Current liabilities | ||||||||||||||||||||
Short-term debt | $ | 10 | $ | 665 | $ | 676 | ||||||||||||||
Current portion of long-term debt | $ | 273 | $ | 108 | $ | 381 | ||||||||||||||
Accounts payable | $ | 372 | $ | 475 | $ | 846 | ||||||||||||||
Income taxes payable | $ | 9 | $ | 37 | $ | 45 | ||||||||||||||
Convertible Debentures represented by instalment receipts | $ | 682 | 3 | [c] | ($ | 682 | ) | |||||||||||||
Derivative instruments | $ | 148 | $ | 29 | $ | 177 | ||||||||||||||
Regulatory liabilities | $ | 75 | $ | 141 | $ | 216 | ||||||||||||||
Pension and post-retirement liabilities | $ | 7 | $ | 27 | $ | 34 | ||||||||||||||
Due to related party | $ | 2 | $ | 0 | $ | 2 | ||||||||||||||
Other current liabilities | $ | 183 | $ | 75 | $ | 258 | ||||||||||||||
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Total current liabilities | $ | 1,760 | $ | 1,557 | ($ | 682 | ) | $ | 2,635 | |||||||||||
Long-term liabilities | ||||||||||||||||||||
Long-term debt | $ | 3,714 | $ | 4,526 | ||||||||||||||||
3 | [d] | $ | 6,458 | |||||||||||||||||
3 | [b] | $ | 57 | $ | 14,756 | |||||||||||||||
Deferred income taxes | $ | 794 | $ | 787 | $ | 1,581 | ||||||||||||||
Derivative instruments | $ | 79 | $ | 1 | $ | 80 | ||||||||||||||
Regulatory liabilities | $ | 221 | $ | 920 | $ | 1,141 | ||||||||||||||
Asset retirement obligations | $ | 116 | $ | 0 | $ | 116 | ||||||||||||||
Pension and post-retirement liabilities | $ | 296 | $ | 360 | $ | 656 | ||||||||||||||
Other long-term liabilities | $ | 272 | $ | 147 | $ | 420 | ||||||||||||||
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Total long-term liabilities | $ | 5,492 | $ | 6,743 | $ | 6,515 | $ | 18,750 | ||||||||||||
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Shareholder’s Equity | ||||||||||||||||||||
Common stock | $ | 2,199 | $ | 305 | 3 | [g] | ($ | 305 | ) | |||||||||||
3 | [c] | $ | 2,185 | |||||||||||||||||
3 | [c] | ($ | 62 | ) | $ | 4,322 | ||||||||||||||
Cumulative preferred stock | $ | 710 | $ | 710 | ||||||||||||||||
Contributed surplus | $ | 35 | $ | 2,458 | 3 | [g] | ($ | 2,458 | ) | $ | 35 | |||||||||
Accumulated other comprehensive loss | $ | 6 | ($ | 15 | ) | 3 | [g] | $ | 15 | $ | 6 | |||||||||
Retained earnings | $ | 1,142 | $ | 601 | 3 | [g] | ($ | 601 | ) | |||||||||||
3 | [e] | ($ | 141 | ) | ||||||||||||||||
3 | [e] | $ | 24 | |||||||||||||||||
3 | [c] | ($ | 42 | ) | ||||||||||||||||
3 | [c] | $ | 14 | $ | 996 | |||||||||||||||
Total Emera Incorporated equity | $ | 4,092 | $ | 3,350 | ($ | 1,373 | ) | $ | 6,068 | |||||||||||
Non-controlling interest in subsidiaries | $ | 105 | $ | 0 | $ | 105 | ||||||||||||||
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Total equity | $ | 4,197 | $ | 3,350 | ($ | 1,373 | ) | $ | 6,173 | |||||||||||
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Total liabilities and equity | $ | 11,449 | $ | 11,649 | $ | 4,460 | $ | 27,558 | ||||||||||||
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See the accompanying notes to the unaudited pro forma consolidated financial statements
D-3
EMERA INCORPORATED
PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS
FOR THE THREE MONTHS END MARCH 31, 2016
(UNAUDITED)
(In millions of Canadian dollars, except for per share amounts)
Emera | TECO Energy | Note | Proforma Adjustments | Proforma Consolidated Statement of Earnings | ||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Regulated | $ | 587 | $ | 902 | $ | 1,489 | ||||||||||||||
Non-regulated | $ | 290 | $ | 4 | $ | 295 | ||||||||||||||
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Total Operating Revenues | $ | 877 | $ | 907 | $ | 1,784 | ||||||||||||||
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Operating Expenses | ||||||||||||||||||||
Regulated fuel for generation and purchased power [1] | $ | 198 | $ | 507 | $ | 705 | ||||||||||||||
Regulated fuel adjustment mechanism and fixed cost deferrals | $ | 18 | $ | 18 | ||||||||||||||||
Non-regulated fuel for generation and purchased power | $ | 110 | $ | 110 | ||||||||||||||||
Non-regulated direct costs | $ | 2 | $ | 2 | ||||||||||||||||
Operating, maintenance and general | $ | 176 | $ | 175 | ||||||||||||||||
Provincial, state and municipal taxes | $ | 16 | $ | 73 | $ | 89 | ||||||||||||||
Depreciation and amortization | $ | 88 | $ | 123 | $ | 211 | ||||||||||||||
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Total Operating Expenses | $ | 607 | $ | 703 | $ | 1,310 | ||||||||||||||
Income from operations | $ | 270 | $ | 204 | $ | 474 | ||||||||||||||
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Other income (expenses) | ($ | 113 | ) | $ | 10 | 3 | [i] | $ | 140 | $ | 36 | |||||||||
Interest expense, net | $ | 75 | $ | 63 | 3 | [i] | ($ | 4 | ) | |||||||||||
3 | [i] | ($ | 22 | ) | ||||||||||||||||
3 | [i] | $ | 1 | |||||||||||||||||
3 | [d] | $ | 73 | |||||||||||||||||
3 | [d] | $ | 3 | $ | 189 | |||||||||||||||
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| |||||||||||||
Income before provision for income taxes | $ | 82 | $ | 150 | $ | 89 | $ | 321 | ||||||||||||
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Income tax expense (recovery) | $ | 27 | $ | 49 | 3 | [i] | $ | 8 | ||||||||||||
3 | [i] | $ | 18 | |||||||||||||||||
3 | [d] | ($ | 26 | ) | $ | 76 | ||||||||||||||
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Net income from continuing operations | $ | 55 | $ | 101 | $ | 89 | $ | 245 | ||||||||||||
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Discontinued Operations | ||||||||||||||||||||
Income (loss) from discontinued operations | $ | 0 | $ | 0 | ||||||||||||||||
Provision (benefit) for income taxes | $ | 0 | $ | 0 | ||||||||||||||||
Income (loss) from discontinued operations, net | $ | 0 | $ | 0 | ||||||||||||||||
Non-controlling interest in subsidiaries | $ | 4 | $ | 4 | ||||||||||||||||
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Net income of Emera Incorporated | $ | 51 | $ | 101 | $ | 89 | $ | 242 | ||||||||||||
Preferred stock dividends | $ | 7 | $ | 7 | ||||||||||||||||
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Net income attributable to common shareholders | $ | 44 | $ | 101 | $ | 89 | $ | 235 | ||||||||||||
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Adjusted Net income attributable to common shareholders [2] | $ | 120 | $ | 101 | $ | 89 | $ | 311 | ||||||||||||
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Weighted average shares of common stock outstanding (in millions) | ||||||||||||||||||||
Basic | $ | 148.70 | 3 | [h] | $ | 52.21 | $ | 200.91 | ||||||||||||
Diluted | $ | 149.30 | 3 | [h] | $ | 52.21 | $ | 201.51 | ||||||||||||
Earnings per common share | ||||||||||||||||||||
Basic | $ | 0.30 | $ | 1.17 | ||||||||||||||||
Diluted | $ | 0.30 | $ | 1.17 | ||||||||||||||||
Adjusted Net Income per common share [2] | ||||||||||||||||||||
Basic | $ | 0.81 | $ | 1.55 | ||||||||||||||||
Diluted | $ | 0.81 | $ | 1.54 | ||||||||||||||||
Earnings per common share excluding discontinued operations | ||||||||||||||||||||
Basic | $ | 0.30 | $ | 1.17 | ||||||||||||||||
Diluted | $ | 0.30 | $ | 1.16 | ||||||||||||||||
Dividends per common share declared | $ | 0.48 |
[1] The TECO Energy Inc. statement of earnings includes maintenance costs in regulated fuel for generation and purchased power and the cost of gas sold by the regulated gas distribution companies.
[2] Adjusted Net Income and Adjusted Net Income per common share are non-U.S. GAAP measures, adjusting for the earnings effect of Emera’s mark-to-market adjustments. These non-U.S. GAAP measures are not recognized measures under U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP.
See the accompanying notes to the unaudited pro forma consolidated financial statements
D-4
EMERA INCORPORATED
PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS
FOR THE YEAR ENDED DECEMBER 31, 2015
(UNAUDITED)
(In millions of Canadian dollars, except for per share amounts)
Emera | TECO Energy | Note | Proforma Adjustments | Proforma Consolidated Statement of Earnings | ||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Regulated | $ | 2,193 | $ | 3,493 | $ | 5,686 | ||||||||||||||
Non-regulated | $ | 596 | $ | 15 | $ | 611 | ||||||||||||||
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| |||||||||||||
Total Operating Revenues | $ | 2,789 | $ | 3,508 | $ | 6,298 | ||||||||||||||
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Operating Expenses | ||||||||||||||||||||
Regulated fuel for generation and purchased power [1] | $ | 815 | $ | 2,049 | $ | 2,863 | ||||||||||||||
Regulated fuel adjustment mechanism and fixed cost deferrals | $ | 42 | $ | 42 | ||||||||||||||||
Non-regulated fuel for generation and purchased power | $ | 336 | $ | 336 | ||||||||||||||||
Non-regulated direct costs | $ | 20 | $ | 20 | ||||||||||||||||
Operating, maintenance and general | $ | 667 | $ | 29 | 3 | [i] | ($ | 13 | ) | |||||||||||
3 | [i] | ($ | 22 | ) | $ | 661 | ||||||||||||||
Provincial, state and municipal taxes | $ | 64 | $ | 265 | $ | 329 | ||||||||||||||
Depreciation and amortization | $ | 340 | $ | 446 | $ | 786 | ||||||||||||||
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Total Operating Expenses | $ | 2,282 | $ | 2,790 | ($ | 35 | ) | $ | 5,036 | |||||||||||
Income from operations | $ | 508 | $ | 719 | $ | 35 | $ | 1,261 | ||||||||||||
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Income from equity investments | $ | 109 | $ | 109 | ||||||||||||||||
Other income (expenses) | $ | 141 | $ | 27 | 3 | [i] | ($ | 119 | ) | $ | 49 | |||||||||
Interest expense, net | $ | 213 | $ | 238 | 3 | [i] | ($ | 40 | ) | |||||||||||
3 | [i] | ($ | 23 | ) | ||||||||||||||||
3 | [d] | $ | 271 | |||||||||||||||||
3 | [e] | $ | 12 | $ | 672 | |||||||||||||||
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Income before provision for income taxes | $ | 545 | $ | 507 | ($ | 305 | ) | $ | 747 | |||||||||||
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Income tax expense (recovery) | $ | 92 | $ | 199 | 3 | [i] | $ | 23 | ||||||||||||
3 | [i] | ($ | 18 | ) | ||||||||||||||||
3 | [i] | $ | 5 | |||||||||||||||||
3 | [d] | ($ | 97 | ) | ||||||||||||||||
$ | 203 | |||||||||||||||||||
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Net income from continuing operations | $ | 452 | $ | 308 | ($ | 216 | ) | $ | 544 | |||||||||||
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Discontinued Operations | ||||||||||||||||||||
Income (loss) from discontinued operations | ($ | 136 | ) | ($ | 136 | ) | ||||||||||||||
Provision (benefit) for income taxes | ($ | 49 | ) | ($ | 49 | ) | ||||||||||||||
Income (loss) from discontinued operations, net | ($ | 87 | ) | ($ | 87 | ) | ||||||||||||||
Non-controlling interest in subsidiaries | $ | 25 | $ | 0 | $ | 25 | ||||||||||||||
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Net income of Emera Incorporated | $ | 428 | $ | 222 | ($ | 216 | ) | $ | 433 | |||||||||||
Preferred stock dividends | $ | 30 | $ | 0 | $ | 0 | $ | 30 | ||||||||||||
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Net income attributable to common shareholders | $ | 397 | $ | 222 | ($ | 216 | ) | $ | 403 | |||||||||||
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Adjusted Net income attributable to common shareholders [2] | $ | 330 | $ | 222 | ($ | 216 | ) | $ | 335 | |||||||||||
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Weighted average shares of common stock outstanding (in millions) | ||||||||||||||||||||
Basic | $ | 145.80 | 3 | [h] | $ | 52.21 | $ | 198.01 | ||||||||||||
Diluted | $ | 146.40 | 3 | [h] | $ | 52.21 | $ | 198.61 | ||||||||||||
Earnings per common share | ||||||||||||||||||||
Basic | $ | 2.72 | $ | 2.03 | ||||||||||||||||
Diluted | $ | 2.71 | $ | 2.03 | ||||||||||||||||
Adjusted Net Income per common share [2] | ||||||||||||||||||||
Basic | $ | 2.26 | $ | 1.69 | ||||||||||||||||
Diluted | $ | 2.25 | $ | 1.69 | ||||||||||||||||
Earnings per common share excluding discontinued operations | ||||||||||||||||||||
Basic | $ | 2.72 | $ | 2.47 | ||||||||||||||||
Diluted | $ | 2.71 | $ | 2.46 | ||||||||||||||||
Dividends per common share declared | $ | 1.66 |
[1] | The TECO Energy Inc. statement of earnings includes maintenance costs in regulated fuel for generation and purchased power and the cost of gas sold by the regulated gas distribution companies. |
[2] | Adjusted Net Income and Adjusted Net Income per common share are non-U.S. GAAP measures, adjusting for the earnings effect of Emera’s mark-to-market adjustments. These non-U.S. GAAP measures are not recognized measures under U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. |
See the accompanying notes to the unaudited pro forma consolidated financial statements
D-5
EMERA INCORPORATED
Notes to Unaudited Pro Forma Consolidated Financial Statements
As at and for the three months ended March 31, 2016 and for the year ended December 31, 2015
(in millions of Canadian dollars, unless otherwise stated)
1. | BASIS OF PRESENTATION |
The accompanying unaudited pro forma consolidated financial information is presented to illustrate the estimated effects of the acquisition (the “Acquisition”) by Emera Incorporated (“Emera” or the “Company”) of TECO Energy Inc. and its subsidiaries (collectively, “TECO Energy”) as described in the Business Acquisition Report (the “BAR”) dated August 5, 2016. The accompanying unaudited pro forma consolidated financial statements have been prepared by management of Emera and are derived from the unaudited and audited consolidated financial statements of Emera as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively, and the unaudited and audited consolidated financial statements of TECO Energy (refer to footnote 3(j) below for further consideration of the foreign exchange translation) as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively.
The accompanying unaudited pro forma consolidated financial statements utilize accounting policies that are consistent with those disclosed in Emera’s and TECO Energy’s audited consolidated financial statements and were prepared in accordance with U.S. accounting principles.
The Acquisition has been accounted for using the acquisition method. The purchase price is primarily based upon the regulated assets and liabilities at the date of closing. Based on the purchase price calculation as detailed in the Acquisition Agreement, the estimated net purchase price for the equity of TECO Energy is approximately Cdn$8.4 billion. See “—Note 3(b): Allocation of the Estimate Net Purchase Price.”
The accompanying unaudited pro forma consolidated balance sheet and unaudited pro forma consolidated statements of earnings reflect the Acquisition as if it had closed on March 31, 2016 and January 1, 2015, respectively. The accompanying unaudited pro forma consolidated financial statements may not be indicative of the results that would have been achieved if the transactions reflected therein had been completed on the dates indicated or the results which may be obtained in the future. For instance, the actual purchase price allocation will reflect the fair value, at the purchase date, of the assets acquired and liabilities assumed based upon Emera’s estimation of such assets and liabilities following the closing of the Acquisition and, accordingly, the final purchase price allocation, as it relates principally to goodwill, may differ materially from the preliminary allocation reflected herein.
The accompanying unaudited pro forma consolidated financial statements should be read in conjunction with the description of the transaction described in the BAR; the audited and unaudited consolidated financial statements of TECO Energy, including the notes thereto, included in the BAR, and the audited and unaudited consolidated financial statements of Emera, including the notes thereto, available on the System for Electronic Document Analysis and Retrieval.
The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effect directly attributable to the Acquisition. In addition, the unaudited pro forma consolidated financial statements do not reflect any of the synergies or cost reductions that may result from the Acquisition and do not include any restructuring costs or other one-time charges that may be incurred. These pro forma adjustments are based on currently available financial information and certain estimates and assumptions. The actual adjustments to the consolidated financial statements will depend on a number of factors. Therefore, it is expected that the actual adjustments will differ from the pro forma adjustments, and the differences may be material.
D-6
2. | DESCRIPTION OF TRANSACTIONS |
Pursuant to the Acquisition Agreement among Emera, Emera US Inc., a direct wholly-owned subsidiary of Emera US Holdings Inc. and TECO Energy, Emera indirectly purchased all of the outstanding common shares of TECO Energy for US$27.55 per share. The estimated net purchase price, including (i) payment for unexercised stock options and performance shares and restricted stock units with the applicable number of shares included in the share count used in the purchase price calculation; and (ii) estimated acquisition costs of Cdn$130 million after tax, was approximately Cdn$8.6 billion. Emera has also assumed TECO Energy’s consolidated debt, which was approximately Cdn$5.4 billion as at March 31, 2016 as described herein.
Emera has arranged two committed debt bridge facilities: (i) a US$4.3 billion bridge facility repayable in full on the first anniversary following its advance, (ii) a US$2.2 billion bridge facility repayable in full on the first anniversary following its advance, which, together with US$3.25 billion in senior unsecured notes, US$1.2 billion unsecured, fixed-to-floating subordinated notes and Cdn $500 million senior unsecured notes (the “Acquisition Capital Markets Transactions”), existing cash and other sources available to Emera, an existing Revolving Facility and the Convertible Debentures, have fully funded the net purchase price and thereby ensure sufficient liquidity to close the Acquisition.
The accompanying unaudited pro forma consolidated financial statements assume that the Acquisition was financed through the net proceeds from the Acquisition Capital Markets Transactions, the Convertible Debentures and cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering). The first instalment of Cdn$728 million relating to the Convertible Debenture offering was paid on closing of the Convertible Debenture offering in 2015 and is reflected in Emera’s financial statements as a liability.
The accompanying unaudited pro forma consolidated financial statements: (i) reflect the Acquisition Capital Markets Transactions and applicable issuance and financing costs (see “Note 3(d): Acquisition Capital Markets Transactions”), and (ii) assume that all cash for the Convertible Debentures has been received and immediately converted into Common Shares at the assumed closing date of the Acquisition (see “Note 3(c): Common Share Issuance”). Therefore, the accompanying unaudited pro forma consolidated statements of earnings do not recognize any additional interest costs associated with the Convertible Debentures. Interest on the Convertible Debentures is expected to be Cdn$87 million. The accompanying unaudited pro forma financial statements also assume that the Acquisition Credit Facilities and Revolving Facility will not be required to be drawn for closing of the Acquisition.
3. | PRO FORMA ASSUMPTIONS AND ADJUSTMENTS |
(a) | Purchase Price and Financing Structure |
The following is the estimated net purchase price, estimated net funding requirements and assumed financing structure for the Acquisition. These estimates have been reflected in the accompanying unaudited pro forma consolidated financial statements.
Estimated Net Purchase Price | ||||
Unadjusted purchase price | $ | 13,779 | ||
Estimated acquisition costs (Note 3(e)) | 130 | |||
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Estimated net purchase price, before assumed debt | 13,909 | |||
Assumed debt of TECO Energy | (5,356 | ) | ||
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Estimated net purchase price | $ | 8,553 | ||
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Estimated Net Funding Requirements | ||||
Estimated net purchase price excluding debt assumed | $ | 8,553 | ||
Assumed debt of TECO Energy | 5,356 | |||
Convertible Debenture issuance costs (Note 3(c)) | 90 | |||
Acquisition Capital Market Transactions issuance costs (Note 3 (d)) | 118 | |||
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Estimated net funding requirements | $ | 14,117 | ||
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Assumed Financing Structure | ||||
Assumed debt of TECO Energy | $ | 5,356 | ||
Convertible Debenture issuance (Note 3(c)) | 2,185 | |||
Acquisition Capital Market Transactions (Note 3(d)) | 6,576 | |||
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$ | 14,117 | |||
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D-7
(b) | Allocation of Estimated Net Purchase Price |
The estimated net purchase price has been allocated to the estimated fair values of TECO Energy net assets and liabilities as at March 31, 2016 in accordance with the acquisition method, as follows:
TECO Energy | Fair Value and Other Adjustments | Net Total | ||||||||||
In millions of Canadian dollars | ||||||||||||
Assets Acquired | ||||||||||||
Cash and cash equivalents | $ | 60 | — | $ | 60 | |||||||
Receivables, net | 311 | — | 311 | |||||||||
Inventory | 253 | — | 253 | |||||||||
Regulatory assets | 52 | — | 52 | |||||||||
Prepaid expenses | 33 | — | 33 | |||||||||
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Total Current Assets | 709 | — | 709 | |||||||||
Property, plant and equipment | 9,797 | — | 9,797 | |||||||||
Regulatory assets | 510 | — | 510 | |||||||||
Goodwill | 530 | (530 | ) | 0 | ||||||||
Other long-term assets | 103 | — | 103 | |||||||||
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$ | 11,649 | $ | (530 | ) | $ | 11,119 | ||||||
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Liabilities Assumed | ||||||||||||
Short-term debt | $ | 665 | — | $ | 665 | |||||||
Current portion of long-term debt | 108 | — | 108 | |||||||||
Accounts payable | 476 | — | 476 | |||||||||
Income taxes payable | 37 | — | 37 | |||||||||
Derivative instruments | 29 | — | 29 | |||||||||
Regulatory liabilities | 141 | — | 141 | |||||||||
Pension and post-retirement liabilities | 27 | — | 27 | |||||||||
Other current liabilities | 75 | — | 75 | |||||||||
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Total Current Liabilities | 1,558 | — | 1,558 | |||||||||
Long-term debt. | 4,526 | 57 | 4,583 | |||||||||
Deferred income taxes | 787 | — | 787 | |||||||||
Derivative instruments | 1 | — | 1 | |||||||||
Regulatory liabilities | 920 | — | 920 | |||||||||
Pension and post-retirement liabilities | 360 | — | 360 | |||||||||
Other long-term liabilities | 147 | — | 147 | |||||||||
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$ | 8,299 | 57 | $ | 8,356 | ||||||||
Net assets at fair value, as at March 31, 2016 | $ | 2,763 | ||||||||||
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Estimated net purchase price, before assumed debt and acquisition costs | $ | 8 ,423 | ||||||||||
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Goodwill | $ | 5,660 | ||||||||||
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TECO Energy is a utility holding company headquartered in Tampa, Florida engaged primarily through its subsidiaries in the regulated vertically- integrated electric utility business in Florida and natural gas transmission and distribution business in Florida and New Mexico. The determination of earnings is based on regulated rates of return that are applied to rate bases and does not change with a change of ownership. “Rate bases” includes jurisdictional rate base, in some cases assets earning a return through clauses and riders, and construction work in progress.
The excess of the estimated net purchase price of the Acquisition, before assumed debt and acquisition costs, over the assumed fair value of net assets acquired from TECO Energy is classified as goodwill on the accompanying unaudited pro forma consolidated balance sheet.
The fair value adjustment on long-term debt relates to non-regulated financing.
D-8
(c) | Common Share Issuance |
In 2015, to finance a portion Acquisition, Emera completed the sale of Cdn$2.185 billion principal amount of 4% convertible unsecured subordinated debentures. These Convertible Debentures were sold on an instalment basis, with one-third paid on closing of the offering, and the remaining payable following satisfaction of conditions precedent to the closing of the Acquisition. For the purposes of these unaudited pro forma consolidated financial statements, the remaining Cdn$1.457 billion relating to the Final Instalment has been received and the Convertible Debentures are assumed to have been fully converted to common shares.
Underwriting costs of Cdn$90 million, of which Cdn$46 million were netted against the proceeds from the first instalment, have been recognized as a deduction from the carrying amount of the equity issued and will result in a corresponding deferred income tax asset of approximately Cdn$28 million based on Emera’s Canadian statutory income tax rate of 31%.
Actual interest costs of Cdn$23 million (Cdn$16 million after-tax) in the year ended December 31, 2015 and Cdn$22 million (Cdn$15 million after-tax) in the three months ended March 31, 2016 incurred on the Convertible Debentures have been removed from Interest Expense, Net as a pro forma adjustment as these costs are directly attributed to the Acquisition and are non-recurring in nature (note 3(i)). The remaining Cdn$42 million (Cdn$28 million after-tax) required to be paid on the Convertible Debentures has been recorded as an adjustment to retained earnings as they are directly attributed to the Acquisition and are non-recurring in nature.
D-9
(d) | Acquisition Capital Markets Transactions |
In June 2016, the Acquisition Capital Markets Transactions raised approximately Cdn$6.6 billion for purposes of financing a portion of the Acquisition. The Acquisition Capital Market transactions are detailed as follows:
i. | US $3.25 billion senior unsecured notes bear interest semi-annually, in arrears, on June 15 and December 15 of each year, commencing on December 15, 2016. The U.S. notes were issued at the following maturities and rates: |
• | $500,000,000 USD 3 year, 2.150 per cent due 2019 |
• | $750,000,000 USD, 6 year 2.700 per cent due 2021 |
• | $750,000,000 USD, 10 year 3.550 per cent due 2026 |
• | $1,250,000,000 USD, 30 year 4.750 per cent due 2046 |
ii. | US $1.2 billion unsecured, fixed-to-floating subordinated notes will mature on June 15, 2076. Emera will pay interest on the notes at a fixed rate of 6.75 per cent per year in equal semi-annual installments on June 15 and December 15 of each year until June 15, 2026. Starting June 15, 2026, and on every quarter thereafter that the notes are outstanding (the “Interest Reset Date”) until their maturity on June 15, 2076, the interest rate on the notes will be reset. |
Beginning on June 15, 2026, and on every Interest Reset Date until June 15, 2046, the notes will be reset at an interest rate of the three month LIBOR plus 5.44 per cent, payable in arrears. Beginning on June 15, 2046, and on every Interest Reset Date until June 15, 2076, the notes will be reset at an interest rate of the three month LIBOR plus 6.19 per cent, payable in arrears.
Emera may elect, at its sole option, to defer the interest payable on the notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent Interest Payment Date, until paid.
iii. | Cdn $500 million senior unsecured notes were issued with a seven-year term to maturity and bear interest at a rate of 2.90 per cent. The notes will bear interest semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2016. |
The blended interest rate is estimated at 4.2% which would result in incremental interest for the year ended December 31, 2015 and the three months ended March 31, 2016 of Cdn$271 million and Cdn$73 million, respectively. Incremental interest would result in corresponding deferred income tax benefits of Cdn$97 million and Cdn$26 million, respectively based on Emera’s blended U.S. and Canadian income tax rate of 36%.
Estimated issuance costs of Cdn$118 million have been netted against the issuances, and amortized over the term (ten years) of the debt.
D-10
(e) | Acquisition Costs |
Acquisition costs are estimated at approximately Cdn$154 million pre-tax (Cdn$130 million after tax) of which Cdn$12 million was incurred in 2015. Acquisition costs include estimated investment banking, accounting, tax, legal, customer benefits negotiated in the settlement to finalize the New Mexico Public Regulation Commission regulatory approval process and other non-financing costs associated with the completion of the Acquisition. These costs have been included as a pro forma adjustment to retained earnings as opposed to being reflected in the unaudited pro forma consolidated statements of earnings of Emera on the basis that these expenses are directly incremental to the Acquisition and are non-recurring in nature.
(f) | Income Taxes |
Income taxes applicable to the pro forma adjustments are calculated at Emera’s average tax rates of 31% (Canadian rate) and 39% (U.S. rate).
The deferred income tax asset and liability is the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities. Deferred income tax assets and liabilities are measured at the tax rates expected to apply when these differences reverse. For the purpose of the accompanying unaudited pro forma consolidated financial statements, average deferred income tax rates of 31% (Canadian rate), 39% (U.S. rate) and 36% (blended U.S. and Canadian rate) have been used.
(g) | TECO Energy Historical Shareholders’ Equity |
The historical shareholders’ equity of TECO Energy, which includes retained earnings, accumulated other comprehensive income and common shares, is eliminated as a result of the Acquisition.
(h) | Earnings per Common Share |
The calculation of the pro forma earnings per Common Share for the year ended December 31, 2015 and for the three months ended March 31, 2016 reflects the assumed issuance of approximately 52.2 million of Common Shares upon conversion of the Convertible Debentures at a net conversion price of Cdn$41.85, as if the issuance had taken place as at January 1, 2015.
D-11
(i) | Normalizing Adjustments for Acquisition Costs |
Mark-to- market pre-tax gains of Cdn$119 million for the year ended December 31, 2015 and pre-tax losses of Cdn$140 million for the three months ended March 31, 2016 (Cdn$101 million after tax gain and Cdn$121 million after tax loss respectively) related to the translation of the Convertible Debenture US$ cash balance and the mark to market adjustments from foreign exchange forward contracts, which are economically hedging the proceeds from the Final Instalment of the Convertible Debentures, have been removed from other income (expenses) as opposed to being reflected in the unaudited pro forma consolidated statements of earnings on the basis that these amounts are directly incremental to the Acquisition and are non-recurring in nature.
Acquisition related costs of Cdn$22 million (Cdn$17 million after tax) incurred by TECO Energy in the year ended December 31, 2015 have been removed from Operating, Maintenance and General Expense as a pro forma adjustment as these costs are directly incremental to the Acquisition and are non-recurring in nature (US$17 million before tax and US$13 million after tax).
Acquisition related costs of Cdn$75 million (Cdn$53 million after tax) incurred by Emera in the year ended December 31, 2015 and Cdn$25 million (Cdn$17 million after tax) incurred in the three months ended March 31, 2016 have been removed from the income statement as a pro forma adjustment as these costs are directly incremental to the Acquisition and are non-recurring in nature. These costs include actual interest on the Convertible Debentures of Cdn$23 million in the year ended December 31, 2015 and Cdn$22 million in the three months ended March 31, 2016 offset by interest earned on the first instalment proceeds of Cdn$1 million, and bridge fees on
Acquisition Credit Facilities of Cdn$40 million in the year ended December 31, 2015 and Cdn$4 million for the three months ended March 31, 2016 removed from Interest Expense and Cdn$13 million in acquisition costs incurred in the year ended December 31, 2015 removed from operating, maintenance and general expense.
(j) | Foreign Exchange Translation |
The assets and liabilities of TECO Energy, which has a U.S. dollar functional currency, are translated at the exchange rate in effect as at the unaudited pro forma consolidated balance sheet date of March 31, 2016. Revenues and expenses of TECO Energy’s operations are translated at the weighted average exchange rate in effect during the reporting period. The following exchange rates were utilized for the unaudited pro forma consolidated financial statements:
Balance Sheet (U.S. dollars to Canadian dollars)
Month-end rate—March 31, 2016: 1.2971
Income Statement (U.S. dollars to Canadian dollars)
Weighted average rate—January 1, 2015 to December 31, 2015: 1.2788
Weighted average rate—January 1, 2016 to March 31, 2016: 1.3748
D-12