Current Report Filing (8-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):

September 14, 2015

TECO ENERGY, INC.

(Exact name of registrant as specified in its charter)

Florida

1-8180

59-2052286

(State or other jurisdiction

of incorporation)

(Commission File Number)

(IRS Employer

Identification No.)


702 North Franklin Street, Tampa Florida		33602
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (813) 228-1111

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Securities Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 – Regulation FD

Item 7.01:

Regulation FD Disclosure

Attached as exhibit 99.1 is information regarding TECO Energy, Inc. excerpted from a prospectus of Emera Inc. for a public offering that Emera Inc. is conducting in Canada. TECO Energy, Inc. is furnishing this information pursuant to Regulation FD. Most of the information has previously been disclosed in TECO Energy, Inc.’s previous filings with the SEC.

Section 9 – Financial Statements and Exhibit

Item 9.01:

Financial Statements and Exhibit

(d)

Exhibit


99.1		Information regarding TECO Energy, Inc. included in a prospectus of Emera Inc. dated September 14, 2015

SIGNATURES

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


Date: September 14, 2015		TECO ENERGY, INC.
		(Registrant)

		/s/ Charles A. Attal III
		Charles A. Attal III
		Senior Vice President-General Counsel
		and Chief Legal Officer

EXHIBIT INDEX


Exhibit No.		Description of Exhibit

99.1		Information regarding TECO Energy, Inc. included in a prospectus of Emera Inc. dated September 14, 2015

EXHIBIT 99.1

TECO Energy Overview

TECO Energy was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company. 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, 2015, excluding 563 employees at TECO Coal and including 462 employees primarily at TECO Energy’s shared services company.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provided retail electric service to approximately 715,000 customers on average in West Central Florida for the six months ended June 30, 2015, and has a net winter system generating capacity of 4,668 MW. 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. With approximately 360,000 customers on average for the six months ended June 30, 2015, 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 2014 was almost 1.5 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 515,000 customers on average for the six months ended June 30, 2015, 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.

Through its subsidiary, TECO Diversified, TECO Energy also owns TECO Coal, a Kentucky limited liability company. TECO Coal has 10 subsidiaries located in Kentucky, Tennessee and Virginia. These entities own mineral rights, own or operate surface and underground coal mines and own interests in coal processing and loading facilities. On September 29, 2014, the board of directors of TECO Energy authorized TECO Energy management to enter into negotiations for the sale of TECO Coal. As a result of this and other factors, TECO Coal was accounted for as an asset held for sale and has been reported as a discontinued operation since September 30, 2014. A pre-tax US$194.5 million impairment charge related to the held-for-sale TECO Coal assets was cumulatively recorded during 2014 and the second quarter of 2015. Efforts to sell TECO Coal are ongoing.

TECO Energy has approximately US$1.5 billion in pre-tax NOL carry-forwards and US$200 million in AMT credits. Depending on the generation of sufficient taxable income in future periods, TECO Energy expects to utilize the NOL carry-forwards primarily in the 2015 to 2019 period, and the AMT carry-forwards beginning in 2019.

TECO Energy is a utility holding company with virtually all of its net income derived from regulated businesses. TECO Energy’s regulated businesses include Tampa Electric, a regulated vertically-integrated electricity utility, PGS, a Florida based local gas distribution company, and NMGC, a New Mexico based local gas distribution company. TECO Energy is in the process of disposing of TECO Coal and has disposed of virtually all of its other unregulated businesses over the last ten years.

TECO Energy’s regulated businesses have shown steady growth over the last decade and have recovered particularly well following the financial crisis of 2008. TECO Energy has demonstrated CAGRs in total segmented net income and total segmented assets of 5.5% and 5.8%, respectively, since 2005, driven by continued investment in rate base. Tampa Electric and PGS experienced 6.0% and 4.2% cumulative annual rate base growth rates through 2009 to 2014 and 2007 to 2014, respectively. As of September 30, 2014, NMGC realized a cumulative annual growth rate of 3.5% between 2005 and 2014.

TECO Energy – Segmented Net Income⁽¹⁾

LOGO

(1)	Segmented net income does not reflect TECO Energy’s consolidated net income as it excludes results from unregulated operations that have been disposed of or are currently held for sale, and excludes financing and unallocated costs at TECO Energy, as well as TECO Energy Corporate and Other.

TECO Energy – Segmented Total Assets⁽¹⁾

LOGO

(1)	Segmented total assets are as at December 31 for the applicable year (except 2015) and exclude discontinued operations, as well as assets from TECO Energy Corporate and Other.

Tampa Electric – Historical Rate Base

LOGO

Source: Tampa Electric Average Rate Base per earnings surveillance reports.

Peoples Gas System – Historical Rate Base

LOGO

Source: Peoples Gas Average Rate Base per earnings surveillance reports.

New Mexico Gas Company – Historical Rate Base

LOGO

Source: 2005 figures from New Mexico Public Regulation Commission.

Constructive Regulatory Jurisdictions

The basic costs of providing electricity and natural gas service, excluding the cost for purchased gas and interstate pipeline capacity, are recovered through base rates. The cost of owning, operating and maintaining the utility system, excluding fuel, conservation costs, purchased power and certain environmental costs for the electric system, are recovered through base rates set by the regulators, being FPSC for Tampa Electric and PGS, and the NMPRC for NMGC. Base rates are determined in each respective regulator’s revenue requirements and rate setting proceedings, which occur at irregular intervals at the initiative of the utility, the regulator or other interested parties. Additional costs are recovered through riders and annual cost recovery proceedings to pass-through the cost to the ratepayer of those services.

Tampa Electric has recovery clauses in place for fuel, purchased power and certain environmental costs. A 2013 rate case settlement provides for US$180 million of base rate increases through 2017, and allows for a midpoint 10.25% return on equity on a 54% common equity component of its deemed structure, and a return on equity range of plus or minus 1% with potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. Tampa Electric is currently earning above a 10.25% midpoint return on equity (range of 9.25% to 11.25%) on a 54% common equity component of its deemed structure.

PGS has recovery clauses in place for purchased gas and cast iron and bare steel pipe replacement, as well as higher increased fixed monthly customer charges that reduce volume sensitivity. Excluded costs are recovered through purchased gas adjustment clauses. PGS is currently earning above a 10.75% midpoint return on equity (range of 9.75% to 11.75%) on a 54.7% common equity component of its deemed structure.

NMGC is regulated by the NMPRC, which allows for the basic costs, excluding purchased gas, storage and interstate capacity to be provided for through rates. The most recent rate case in 2012 concluded with a stipulated settlement that implied a 10% return on equity on a 52% common equity component of its deemed structure. The September 2014 settlement approving TECO Energy’s acquisition of NMGC included US$2 million of customer credits for the first 12 months and US$4 million of customer credits per year thereafter until the next NMGC rate case, which could not be in effect until after 2017. NMGC is currently earning less than a 10% return on equity. NMGC has a purchased gas adjustment clause in place that allows recovery of the excluded costs noted above. See “TECO Energy – New Mexico Gas Company – Regulation”.

Rate Base Growth Through Capital Investment

TECO Energy’s continued investment in its gas and electric businesses to support customer growth, system reliability and facilities is expected to drive rate base growth over the next several years. TECO Energy estimates capital spending from its regulated subsidiaries to be approximately US$3.0 billion during the 2015 to 2019 period.

Tampa Electric’s capital spending forecast during the 2015 to 2019 period totals approximately US$2.2 billion and includes amounts related to the conversion of the Polk Power Station Units 2–5 from peaking service to combined cycle with a January 2017 in-service date. Tampa Electric’s rate base is expected to grow at a CAGR of approximately 7% through 2017.

Tampa Electric’s near-term growth will be driven by, among other investments, generating capacity additions in supporting equipment procurement and construction, the conversion of the Polk Power Station Units 2-5, transmission system improvements to support the increased plant output, capital spending on transmission and distribution systems, and infrastructure renewal. Tampa Electric also expects to spend on a program to replace its customer information system with a state-of-the-art customer relationship management and billing system. This system is the first step in modernizing the distribution system to enable the implementation of smart-grid technologies in the post-2016 forecast period.

Capital expenditures for PGS are expected to total approximately US$500 million during the 2015 to 2019 period. This amount includes an annual average of approximately US$65 million annually for projects associated with customer growth and natural gas distribution system expansion contributing to a CAGR in rate base of approximately 6% through 2017. PGS’s growth will be driven by, among other investments, capital spending to support moderate residential and commercial customer growth, system expansion to serve large commercial and industrial customers, continued interest in conversion of vehicle fleets to compressed natural gas, continued replacement of cast iron and bare steel pipe, ongoing expenditures for infrastructure renewal, replacement, and system safety.

The NMGC capital expenditure forecast is expected to be approximately US$60 million in 2015, approximately US$95 million in 2016 and approximately US$145 million over 2017 to 2019, which amounts involve ongoing renewal, replacement and system safety, and may increase over the years as marketing, economic development and system expansion plans are further developed. NMGC’s growth will be driven by, among other investments, capital expenditures to support modest customer growth and system reliability, ongoing infrastructure renewal, replacement and system safety, software and systems upgrades, which are components of an integration plan with TECO Energy, capital spending in 2016 on a transmission pipeline “looping” project to enhance system reliability and capacity for anticipated growth.

Recent Developments

Following the September 4, 2015 announcement of the signing a definitive agreement with Emera Inc. for the acquisition of TECO Energy, on September 8, 2015, each of S&P, Moody’s and Fitch issued updates and comments in respect of TECO Energy and its subsidiaries’ ratings. S&P affirmed its ‘BBB+’ issuer credit rating on TECO Energy and all of its other ratings on TECO Energy, TEC and NMGC, while revising the outlook to negative from developing. Moody’s indicated that the Acquisition had no immediate impact on TECO Energy’s or TEC’s ratings. Fitch affirmed its ‘BBB’ long-term ‘Issuer Default Rating’ for TECO Energy and its ‘BBB’ senior unsecured debt rating for TECO Finance, and noted that the ratings of TEC were unaffected.

TECO ENERGY

Unless otherwise indicated by the context, “TECO Energy” means the holding company, TECO Energy, Inc. and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries.

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, 2015, excluding 563 employees at TECO Coal and including 462 employees primarily at TECO Energy’s shared services company.

The common stock of TECO Energy trades on the New York Stock Exchange under the symbol “TE”.

The revenues from continuing operations at TECO Energy’s by regulated subsidiary for the periods presented as follows:

Revenues from Continuing Operations


*(millions) (US$)*	Six months ended June 30, 2015			Year ended December 31, 2014			Year ended December 31, 2013
Tampa Electric	$	983.0		$	2,021.0		$	1,950.5
PGS⁽¹⁾		216.4			399.6			393.5
NMGC		173.0			137.5			0.0
Eliminations – sales to affiliates		(4.1	)		(2.2	)		(1.7	)

Total regulated businesses		1,368.3			2,555.9			2,342.3
Other		5.3			10.5			12.8

Total revenues from continuing operations	$	1,373.6		$	2,566.4		$	2,355.1

(1)	PGS segment revenues reflected above include US$5.2 million, US$8.6 million and US$9.8 million of revenues from its subsidiary TECO Partners, Inc. for the six months ended June 30, 2015 and years ended 2014 and 2013, respectively.

Net Income from Continuing Operations


*(millions) (US$)*	Six months ended June 30, 2015			Year ended December 31, 2014			Year ended December 31, 2013
Tampa Electric	$	115.9		$	224.5		$	190.9
PGS		22.2			35.8			34.7
NMGC⁽¹⁾		13.8			10.5			0.0

Total regulated businesses		151.9			270.8			225.6
Other⁽²⁾		(26.6	)		(64.4	)		(36.9	)

Net income from continuing operations	$	125.3		$	206.4		$	188.7

(1)	NMGC amount for year ended December 31, 2014 reflects four months of TECO Energy ownership.

(2)	Other includes non-U.S. GAAP charges and gains related to the NMGC acquisition and pending sale of TECO Coal of US$1.0 million, US$23.3 million and US$6.2 million for the six months ended June 30, 2015, years ended 2014 and 2013, respectively.

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, 2014 and 2013, including the consolidated statements of income, comprehensive income, cash flows and capital for each of the years ended December 31, 2014 and 2013, and the unaudited consolidated financial statements of TECO Energy for the three and six months ended June 30, 2015, each of which is included in this Prospectus.

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, with an estimated population of over 1 million. 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 three electric generating stations in or near Tampa, one electric generating station in southwestern Polk County, Florida and one electric generating station in long-term reserve standby located near Sebring, a city in Highlands County in South Central Florida.

Tampa Electric had 2,077 employees as of June 30, 2015 of which 861 were represented by the International Brotherhood of Electrical Workers and 169 were represented by the Office and Professional Employees International Union.

Operating Revenue

In 2014, Tampa Electric’s total operating revenue was derived approximately 50% from residential sales, 30% from commercial sales, 8% from industrial sales and 12% from other sales, including bulk power sales for resale. Approximately 4% of revenues were attributable to governmental municipalities. During the first six months of 2015, Tampa Electric’s total operating revenue was derived from the same approximate sources as in 2014. The sources of operating revenue and MWH sales for the periods indicated were as follows:


*(millions) (US$)*	Six months ended June 30, 2015		Year ended December 31, 2014		Year ended December 31, 2013
Residential	$	480.8	$	1,007.6	$	936.8
Commercial		287.9		602.0		581.2
Industrial – Phosphate		27.3		59.9		71.9
Industrial – Other		52.7		104.6		100.4
Other retail sales of electricity		85.4		181.9		177.4
Deferred and other revenues		16.7		—		—

Total retail		950.8		1,956.0		1,867.7
Sales for resale		2.9		13.0		8.5
Other		29.4		52.0		74.3

Total operating revenues	$	983.1	$	2,021.0	$	1,950.5

Megawatt-hour Sales


*(thousands) (MWH)*	Six months ended July 30, 2015		Year ended December 31, 2014		Year ended December 31, 2013
Residential		4,170.0		8,656		8,470
Commercial		2,960.1		6,142		6,090
Industrial		939.8		1,901		2,026
Other retail sales of electricity		856.1		1,827		1,832

Total retail		8,926.0		18,526		18,418
Sales for resale		84.7		259		222

Total energy sold		9,010.7		18,785		18,640

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 2014 net winter generating capability of 4,703 MW. Tampa Electric assets include the Big Bend Power Station (1,607 MW capacity from four coal units and 61 MW from a 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 IGCC unit and 732 MW from four CTs).

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. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004 and Units 3 through 6 were completed in 2009. In 2009, Tampa Electric placed the Phillips Power Station on long-term reserve standby. In July 2012, Tampa Electric placed the City of Tampa Partnership Station on long-term reserve standby.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,333 Mega Volt 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 6,215 pole miles of overhead lines and 4,944 trench miles of underground lines. As of December 31, 2014, there were 739,304 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 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 rights-of-way 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.

Regulation

Tampa Electric’s retail operations are regulated by the 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 operations 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 common equity. 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 2014 and the last two months of 2013 reflected the results of a Stipulation and Settlement Agreement entered on September 6, 2013, between TEC 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 TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory return on common equity would be a midpoint 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 January 1, 2018), unless its earned return on common equity were to fall below 9.25% (or 9.5% if the allowed return on common equity is increased as described above) before that time. If its earned return on common equity were to rise above 11.25% (or 11.5% if the allowed return on common equity is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s 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.

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.

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. Given TECO Energy’s acquisition of NMGC on September 2, 2014, Tampa Electric and TECO Energy jointly requested a waiver from FERC on October 1, 2014 in order for Tampa Electric to continue to supply a de-minimis level of non-power goods and services to its affiliates as of January 1, 2015. On October 1, 2014, 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, Tampa Electric filed its required triennial market-power analysis, demonstrating that Tampa Electric does not have wholesale market power using FERC’s two analytical screens. This compliance filing was made in support of the company’s continued ability to effect wholesale market-based rate transactions everywhere, except within Tampa Electric’s balancing-authority area. On June 16, 2015, Tampa Electric filed a supplement to the June 30, 2014 triennial market power update. Public comments were due by July 7, 2015 and FERC is now expected to respond to the filing.

Tampa Electric is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See “– Environmental Compliance”.

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.

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 (Florida) (“PPSA”), which sets Florida’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 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 62% of Tampa Electric’s generation of electricity for 2014 was coal-fired, with natural gas representing approximately 38%. Tampa Electric used its generating units to meet approximately 95% of the total system load requirements, with the remaining 5% coming from purchased power. Tampa Electric’s average delivered fuel cost per MMBTU and average delivered cost per ton of coal burned have been as follows:


*Average cost per MMBTU (US$)*	*2014*		*2013*		*2012*		*2011*		*2010*
Coal	$	3.48	$	3.36	$	3.57	$	3.46	$	3.08
Oil		0.0		30.01		25.88		21.21		16.43
Gas (Natural)		5.68		5.23		5.34		6.20		6.74
Composite		4.16		4.00		4.19		4.38		4.46

Average cost per ton of coal burned	$	83.70	$	77.79	$	84.59	$	83.17	$	74.80

(1)	PGS segment revenues reflected above include US$5.2 million, US$8.6 million and US$9.8 million of revenues from its subsidiary TECO Partners, Inc. for the six months ended June 30, 2015 and years ended 2014 and 2013, respectively.

Tampa Electric’s generating stations burn fuels as follows: Bayside Power Station burns natural gas; Big Bend Power Station, which has SO₂scrubber capabilities and NO_x reduction systems, burns a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas at CT4; Polk Power Station burns a blend of low-sulfur coal and petroleum coke (which is gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil; and Phillips Power Station, which burned residual fuel oil, was placed on long-term standby in September 2009.

Tampa Electric burned approximately 5.0 million tons of coal and petroleum coke during 2014 and estimates that its combined coal and petroleum coke consumption will be about 5.0 million tons in 2015. During 2014, Tampa Electric purchased approximately 76% of its coal under long-term contracts with five suppliers, and approximately 24% of its coal and petroleum coke in the spot market. Tampa Electric obtains approximately 70% of its coal and petroleum coke requirements under long-term contracts with five suppliers and the remaining 30% in the spot market.

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 2014, approximately 84% of Tampa Electric’s coal supply was deep-mined, approximately 7% was surface-mined and the remaining 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.

As of December 31, 2014, approximately 90% of Tampa Electric’s 1,500,000 MMBTU gas storage capacity was full. Tampa Electric contracted for 80% of its expected gas needs for the April 2015 through October 2015 period. In September 2015, Tampa Electric expects to issue RFPs to meet its remaining 2015 gas needs and begin contracting for its 2016 gas needs. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

Tampa Electric has agreements in place to purchase low sulfur No. 2 fuel oil for Big Bend Power Station and Polk Power Station. All of these agreements have prices that are 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 rights-of-way 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 rights-of-way 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 rights-of-way 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 through August 2043. Franchise fees paid by Tampa Electric, which totaled US$44.9 million at December 31, 2014, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

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 rights-of-way 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 2014 capital expenditures were approximately US$590 million, which included approximately US$205 million for the Polk Power Station Units 2-5 conversion to combined cycle and related transmission system improvements, US$16 million for a reclaimed water pipeline to serve the Polk Power Station, approximately US$45 million to improve the Big Bend Power Station solid fuel handling and flue gas desulphurization systems reliability, approximately US$40 million for equipment and facilities, and approximately US$66 million related to environmental compliance and improvement programs, primarily for upgrades to scrubbers and modifications to coal combustion by-product storage areas at the Big Bend Power Station.

As at December 31, 2014, Tampa Electric expected to spend approximately US$570 million on capital expenditure for 2015. For the transmission and distribution systems, Tampa Electric expected to spend approximately US$150 million in 2015, including approximately US$120 million for normal transmission and distribution system expansion and reliability, and approximately US$30 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of US$120 million include approximately US$20 million for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, approximately US$90 million for generating system reliability in 2015 and advance purchases for 2016 unit outages, and approximately US$10 million for the conversion of distillate oil igniters to natural gas. In addition, Tampa Electric expected to spend approximately US$25 million for environmental compliance programs and improvements to environmental control equipment in 2015. The 2015 capital expenditure forecast includes approximately US$5 million for a 2 MW solar array that Tampa Electric will build, own and operate at Tampa International Airport. Tampa Electric also expected to spend 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 (the “CRMB project”). This system is the first step in modernizing the distribution system to enable the implementation of smart-grid technologies in the post-2016 forecast period. As at December 31, 2014, Tampa Electric expected to spend an additional US$20 million in 2016 to complete the CRMB project.

As at December 31, 2014, in the 2016 to 2019 period, Tampa Electric expected to spend approximately US$360 million annually to support normal system growth and reliability, environmental compliance and improvements to computer systems 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$15 million for environmental compliance; average annual expenditures of more than US$35 million for general infrastructure and facilities, including the CRMB project and other software upgrades; average annual expenditures of approximately US$25 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.

The capital spending forecast for generation includes approximately US$120 million for modifications to the Polk Power Station 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.

New generation and transmission for the 2017 to 2019 period includes approximately US$140 million for a simple cycle peaking unit scheduled to be in-service in early 2020. As at December 31, 2014, Tampa Electric recognized that the proposed Clean Power Plan favours generating resources with lower or no carbon emissions, and that Tampa Electric may meet the need for additional generating capacity in 2020 with a conventional peaking unit or some combination of conventional generation and renewable resources such as solar.

As at June 30, 2015, Tampa Electric’s total capital expenditures for the six months ended June 30, 2015 was approximately US$270 million.

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 360,000 customers on average for the six months ended June 30, 2015.

PGS had 519 employees as of June 30, 2015. A total of 131 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

Operating Revenue

In 2014, the total throughput for PGS was approximately 1.5 billion therms. Of this total throughput, 7% was gas purchased and resold to retail customers by PGS, 87% was third-party supplied gas that was delivered for retail transportation-only customers and 6% was gas sold off-system. Industrial and power generation customers consumed approximately 60% of PGS’s annual therm volume, commercial customers consumed approximately 30%, off-system sales customers consumed 5% 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 37% of total revenues in 2014. Approximately 5% of revenues are attributed to governmental municipalities.

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 31 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
*(millions) (US$)*	Six months ended June 30, 2015		Year ended December 31, 2014		Year ended December 31, 2013		Six months ended June 30, 2015		Year ended December 31, 2014		Year ended December 31, 2013
Residential	$	77.3	$	144.1	$	128.1		46.9		80.8		74.4
Commercial		74.1		139.1		133.4		248.1		460.5		438.1
Industrial		6.4		13.1		13.4		146.3		274.3		272.0
Off-system sales		22.2		39.4		56.7		69.8		84.0		143.1
Power generation		3.9		6.8		9.9		375.4		643.5		744.4
Other revenues		27.3		48.5		42.2

Total⁽¹⁾	$	211.2	$	391.0	$	383.7		886.5		1,543.1		1,672.0

(1)	Excludes TECO Partners, Inc.’s (a subsidiary of PGS) portion of PGS.

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 18,540 miles of pipe, including approximately 11,740 miles of mains and 6,800 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 determined in FPSC revenue requirements proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.

FPSC approved a base rate increase of US$19.2 million for PGS in May 2009, which became effective on June 18, 2009 and reflects an 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 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 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 removed from its system within eight 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 U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, of the Code of Federal Regulations.

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. 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.

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 21,900 transportation-only customers as of December 31, 2014 out of approximately 36,000 eligible customers.

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 and through 78 interconnections (gate stations) serving PGS’s operating divisions.

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.

Franchises and Other Rights

PGS holds franchise and other rights with 113 municipalities throughout Florida. These franchises govern the placement of PGS’s facilities on the public rights-of-way 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 rights-of-way 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 with the incorporated municipalities within its service area have various expiration dates ranging from the present through 2044. PGS expects to negotiate fourteen franchises by the end of 2015. Franchise fees paid by PGS, which totaled US$8.7 million at December 31, 2014, 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 are conducted in each case under one or more permits to use state or county rights-of-way 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, 2014, PGS capital expenditures were approximately US$90 million, including approximately US$30 million for maintenance of the existing system, approximately US$45 million to expand the system and support customer growth, and approximately US$14 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, 2014, were any anticipated for the 2015 through 2019 period.

As at December 31, 2014, capital expenditures for PGS were expected to be about US$100 million in 2015 and US$400 million during the 2016 to 2019 period. Included in these amounts is an average of approximately US$65 million annually for projects associated with customer growth and natural gas distribution system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety, including approximately US$10 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 CO₂ emissions than petroleum based fuels that are attractive to users.

NEW MEXICO GAS COMPANY

On September 2, 2014, 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. All post-closing purchase price adjustments including indemnification claims relating to the acquisition have been finalized.

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 had approximately 679 employees as of June 30, 2015. NMGC operates a natural gas distribution system that served approximately 515,000 customers on average for the six months ended June 30, 2015. 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 the last four months of 2014 (since the acquisition by TECO Energy), the total throughput for NMGC was over 275 million therms. Of this total throughput, 53% was gas purchased and resold to retail customers by NMGC, 41% 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 27% of NMGC’s 2014 annual therm volume, commercial customers consumed approximately 31%, off-system transportation customers consumed 6% and the remaining balance was consumed by residential customers.

Natural gas has historically been used primarily for residential heating purposes in New Mexico. The residential market represents approximately 37% of total annual therm volume and 72% of NMGC’s total annual revenues. Approximately 4% of annual revenues are attributed to facilities of governmental entities, including the federal government, the state of New Mexico, school districts and municipalities.

Revenues and therms for NMGC for the six months ended June 30, 2015 and the four months ended December 31, 2014 were as follows:


	*Revenues*		*Therms*		*Revenues*		*Therms*
*(millions) (US$)*	Six months ended June 30, 2015		Six months ended June 30, 2015		Four months ended December 31, 2014		Four months ended December 31, 2014
Residential	$	125.7		160.1	$	99.9		108.2
Commercial		33.5		57.8		27.1		37.4
Industrial		0.3		0.7		0.9		1.6
Off system sales		0.3		1.2		—		—
On system transportation		9.8		158.1		7.1		111.6
Off system transportation		0.4		22.6		0.3		16.5
Other revenues		3.0		—		2.2

Total	$	173.0		400.5	$	137.5		275.3

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 rights-of-way, 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 NMPRC. The NMPRC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters.

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 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 and customers will receive a US$2 to US$4 million credit per year until the next rate case.

NMGC recovers the costs it pays for gas supply and interstate transportation for system supply through the 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 GCBF rate to be used in the next month to recover those

estimated costs. For any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in revenue collected through the PGAC. NMGC 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 allowing for continued use of the PGAC for another four years.

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 U.S. 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.

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.

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 four months ended December 31, 2014, NMGC had approximately 4,000 transportation-only end-use customers and approximately 509,000 gas commodity sales service customers. Transportation-only throughput represented 46.5% of total system throughput and 5.4% of total revenue for the four months ended December 31, 2014.

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 the remaining balance.

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 (Bcf) 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 NAESB 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.

Franchises and Other Rights

Many of NMGC’s transmission and distribution facilities are located on lands that require the grant of rights-of-way or franchises from non-tribal governmental entities, Native American tribes and pueblos, or private landowners. In some cases, renewed rights-of-way or franchises must be submitted to the Federal Bureau of Indian Affairs for approval. For the four months ended December 31, 2014, NMGC incurred expenditures for rights-of-way and franchise renewals on Native American tribal and pueblo lands that amounted to US$7.9 million.

In 2011, the New Mexico legislature passed legislation confirming the validity and enforceability of agreements with public utilities that provide access to public rights of way, including expired agreements that have continued to be honoured 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 rights-of-way or franchises remain in effect by acquiescence, though NMGC expects to enter into negotiations over those expired rights-of-way or franchises and renew them. Based on current renewal experience with rights-of-way and franchises on Native American tribal and pueblo lands, NMGC believes that it is likely those rights-of-way 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 rights-of-way or franchises, it could be obligated to remove its facilities from, or abandon its facilities on, the property covered by the rights-of-way 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 rights-of-way 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, rights-of-way and franchise costs have been recovered in rates charged to customers, and NMGC will continue to seek to recover those costs in future rates charged to customers.

Capital Expenditures

During the four months ended December 31, 2014, NMGC capital expenditures of approximately US$20 million included amounts to support customer growth, system reliability and facilities and equipment to safely and reliably operate the system. NMGC did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2015 through 2019 period.

As at December 31, 2014, the expected 2015 capital expenditure for NMGC were approximately US$60 million, which included approximately US$20 million annually for ongoing renewal, replacement and system safety. As at December 31, 2014, the forecast for capital expenditures in 2016 included approximately US$40 million for a transmission pipeline “looping” project to enhance system reliability and capacity for anticipated growth. The forecast for 2015 and 2016 included approximately US$15 million annually for software and systems upgrades, which are components of the integration plans with TECO Energy. The NMGC capital spending forecast is expected to increase in future years as marketing, economic development and system expansion plans are further developed in the integration process. The capital expenditure forecast does not include any amounts that might be required to improve system reliability to prevent service interruptions, such as occurred in New Mexico in 2011, as a solution is subject to approval by the NMPRC. As a condition of the NMPRC approval of the acquisition, TECO Energy and NMGC agreed to review a previously proposed LNG storage facility to determine if it is the optimal solution and to present a proposed solution to the NMPRC in April 2016.

ENVIRONMENTAL COMPLIANCE

TECO Energy’s businesses have significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, and material Clean Water Act implications and impacts by federal and state legislative initiatives. 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. 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 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 BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.

Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S. Department of Justice and the 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 Nov. 22, 2013. Termination of the Consent Final Judgment was completed in May 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 SO_2, and installation of SCR systems for NO_x 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.

As a result of the actions taken under the Consent Decree, emissions of all pollutant types have been significantly reduced. Since 1998, Tampa Electric has reduced annual SO₂, NO_x and particulate matter emissions from its facilities by 164,000 tons (94%), 63,000 tons (91%) and 4,500 tons (87%), respectively.

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 CAIR. In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO₂and NO_x. 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 CSAPR. The final CSAPR focused on reducing SO₂ and NO_x 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.

The EPA has estimated that the implementation of CSAPR would result in the retirement of primarily smaller, older coal-fired power stations that do not currently have state-of-the-art air pollution control equipment already installed. The retirement of these units or switching to other fuels for compliance with this rule is likely to reduce overall demand for coal, which could reduce sales at TECO Coal.

SO₂ National Ambient Air Quality Standards (“NAAQS”)

On June 2, 2010, the EPA revised the primary SO₂ NAAQS by establishing a new one-hour standard at a level of 75 parts per billion. 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 SO₂exceedances 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 SO₂emission reductions may be required depending on the outcome of this process.

Hazardous Air Pollutants (“HAPS”) Maximum Achievable Control Technology (“MACT”)

The EPA published proposed rules under National Emission Standards for HAPS 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 Mercury Air Toxics Standards (“MATS”), were published in December 2011 and went into effect in April 2015. On June 29, 2015, the U.S. Supreme Court remanded the EPA’s MATS to the U.S. District Court for the District of Columbia for failing to properly consider the cost of compliance. The Circuit Court will now decide whether to vacate or stay the rule and require EPA to submit further cost benefit analysis.

All of Tampa Electric’s conventional coal-fired units were already equipped with scrubbers and SCRs, and the Polk Power Station Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric was already positioned to be able to meet the new standards without considerable impacts, compared to others who have not taken similar early action. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of the current rule and expects that it will remain in compliance with MATS with nominal additional capital investment and the retirement of coal fired generating units as a result of the implementation of this rule could reduce demand for sales at TECO Coal.

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 GHGs, requiring facilities, including Tampa Electric and PGS, 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 and PGS complied with the reporting requirement and continues to submit annual reports as required.

In December 2009, the EPA published the final Endangerment Finding in the U.S. 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 U. S. 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.

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 Clean Power Plan, was signed by the Administrator 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 2020 through 2029. Under the methodology employed by the EPA in the final rule, 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 29% reduction in the GHG emission rate of affected electricity generating units. 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. 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 rule was finalized on August 3, 2015, and publication with the U.S. Federal Register is pending. Under the rule, states will have until September 2016 to submit plans to achieve their target emission reductions (subject to extension and EPA approval of the states’ plans). The outcome of this rule-making process and its impact on TECO Energy’s businesses cannot be determined at this time; however, it could result in increased operating costs, decreased demand for coal, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on how they are implemented, the proposed rules could increase the costs or rates charged to customers, which could curtail sales. See “Risk Factors Related to TECO Energy”.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the 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 cannot predict whether the FPSC would grant such recovery. Tampa Electric’s current solid-fuel energy generation was about 55% of its total system output in 2014, compared to being approximately 84% of its output in 2001. This is due to the conversion of the coal-fired Gannon Power Station into the natural gas-fired Bayside Power Station. However, solid fuel-fired facilities remain a significant component of Tampa Electric’s diverse generation fleet and additional solid fuel units could be considered in the future.

There are not yet federal limits on GHG emissions for the coal sector, and it is unclear if future requirements for GHG emissions reductions would directly impact it as a carbon-based fuel provider or the end users of its products. In either case, these requirements could make the use of coal more expensive or less desirable, which could impact TECO Coal’s margins and profitability.

Water Supply and Quality

The EPA’s final Clean Water Act Section 316(b) rule took effect in 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Tampa Electric uses water from Tampa Bay at its Bayside Power Station and Big Bend Power Station facilities as 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. Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule.

On December 6, 2010, the EPA published its final rule, setting numeric nutrient criteria for Florida’s lakes and flowing waters. The rule, as published, is being challenged in the courts by numerous parties, including the state of Florida. The rule sets numeric limits for nitrogen and phosphorous in lakes and streams and for nitrate plus nitrite in springs. The EPA promulgated the rule pursuant to the terms of a consent decree approved by the U.S. District Court in Florida Wildlife Federation v. Jackson, in which environmentalists sued the EPA for allegedly violating a duty under the Federal Water Pollution Control Act (Clean Water Act or Act) to set the numeric criteria. In response to comments raising numerous implementation concerns, the EPA decided to delay the effective date of the criteria until 15 months after publication. The EPA announced that, in the interim, it would undertake a series of implementation steps in Florida, including an “education and outreach rollout,” training meetings, and the development of guidance materials to coincide with the expected comment period on proposed site-specific alternative criteria. On Nov. 30, 2012, the EPA

approved the FDEP rule in its entirety. The EPA proposed additional criteria in December 2012, including a re-proposal of streams criteria that were previously invalidated. In January 2014, the EPA consent decree was revised allowing only the FDEP criteria to be implemented in Florida. Additional litigation was filed in 2014 challenging the legality of the revision of the consent decree; oral arguments occurred in January 2015, but there has been no final ruling. Streams criteria 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 that place technology-based limits on wastewater discharges. The final rulemaking is scheduled for September 2015 and is expected to focus on wastewater discharges from scrubbers, fly ash and bottom ash sluicing processes, leachate from ponds and landfills containing CCRs, IGCC processes, and flue gas mercury controls. The EPA is evaluating a suite of technology options which include treatment processes for wastewater discharges as well as the conversion to dry handling of fly ash and bottom ash to allow for zero discharge of transport water. Final impacts will vary depending on the mandated technology, the volume of wastewater to be treated and the pollutant limits. Tightened limits are anticipated for mercury, selenium, trace metals, and chlorides. New guidelines will likely add stricter limits to future National Pollutant Discharge Elimination System permits.

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 June 30, 2015, TEC has estimated its ultimate financial liability to be US$33.3 million, primarily at PGS. 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 and a reserve has already been accrued in TECO Energy’s consolidated financial statements.

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.

Coal Combustion Residuals Recycling and Disposal

The combustion of coal at two of Tampa Electric’s power-generating facilities, the Big Bend Power Station and Polk Power Station, produces ash and other by-products, collectively known as CCRs. The CCRs produced at Big Bend Power Station include fly ash, FGD gypsum, boiler slag, bottom ash and economizer ash. The CCRs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, over 95% of all CCRs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products. The remaining 5% were either disposed of onsite or shipped offsite to nearby industrial waste landfills in Central Florida.

The EPA published a final CCR rule in the U.S. Federal Register on April 17, 2015. This rule will go into effect on October 19, 2015. The rule is modeled after the existing Subtitle D rules for non-hazardous waste, with some special requirements for disposal of CCRs in surface impoundments and landfills. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. The initial assessment is that activities in 2015 and 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. Under current Florida regulation, compliance related expenditures and capital investments related to complying with this new rule would be recoverable under Florida’s ECRC. This rule is likely to face 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 and it is not possible to predict the ultimate impact on Tampa Electric at this time.

Renewable Energy

Renewables are a component of Tampa Electric’s environmental portfolio. Tampa Electric’s renewable energy program offers to sell renewable energy as an option to customers and utilizes energy generated in Florida from renewable sources (e.g. biomass and solar). To date, almost 70 million kWh of renewable energy have been produced by Tampa Electric and other renewable energy generating sources within Florida to support participating customer requirements.

Tampa Electric has installed 135 kW of solar panels to generate electricity from the sun at seven 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 most recently at LEGOLAND Florida. Tampa Electric continues to evaluate opportunities to increase its solar portfolio. In particular, Tampa Electric plans to install its first, large-scale solar facility at Tampa International Airport by the end of 2015; at 2 MW, the solar panels will produce enough electricity to power up to 250 homes as well as the airport. In addition, Tampa Electric announced on August 4, 2015 that it will build the largest solar project in the Tampa Bay area, which will be a 25 MW facility that will feature more than 70,000 solar panels on 125 acres of land owned by Tampa Electric at the Big Bend Power Station. This project is expected to be completed in 2016 and will be the largest solar project ever built by Tampa Electric, with the capacity to power more than 3,500 homes.

In Florida, solar energy advocates have proposed a constitutional ballot initiative that would allow direct rooftop solar energy, potentially bypassing the utility. A Florida Supreme Court ruling related to the constitutionality of the ballot initiative is pending. If the solar energy advocates are successful with the ballot initiative, corresponding state legislation will be necessary to implement the terms.

Distributed Generation

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. 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 2015 and a potential amendment to the Florida constitution in 2016 would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and to allow limited sales of electricity by non-utility generators.

Additionally, the EPA’s proposed Clean Power Plan relies heavily on the use of renewable energy in the calculation of emission performance goals, and depending on how it is implemented, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets. Depending on how this 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 objectives toward increasing energy efficiency. In 2014, 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 331 MW and the winter peak demand by 723 MW.

In November 2014, the FPSC established new demand-side-management goals for 2015 to 2024 for all Florida investor-owned electric utilities. In the goal setting process, all of the Florida investor-owned utilities sought permission from the FPSC to lower the demand-side-management goals. The primary drivers for the lower demand-side-management goals were: 1) lower overall annual customer growth and lower per customer electricity usage, which defers the in-service date for the next generating unit, 2) decreased costs of utility natural gas fired generation, 3) increased efficiency of air conditioners, appliances and lighting, which have reduced the available demand and energy savings that can be achieved through demand-side-management programs.

While the new approved goals for Tampa Electric are lower, the goals are reasonable, beneficial and cost-effective to all customers as required by the Florida Energy Efficiency & Conservation Act. For Tampa Electric, the new 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 demand-side-management 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 customers’ gas bill.

OUTSTANDING INDEBTEDNESS AND LONG-TERM COMMITMENTS

Liquidity, Capital Resources

The table below sets forth the June 30, 2015 consolidated liquidity and cash balances, the cash balances at TECO Energy and its operating companies, and amounts available under the TECO Energy/TECO Finance, TEC and NMGC credit facilities.

Balances as of June 30, 2015


*(millions) (US$)*	Consolidated		TEC		NMGC		Other
Credit facilities	$	900.0	$	475.0	$	125.0	$	300.0
Drawn amounts/Letters of credit		87.8		0.6		12.2		75.0

Available credit facilities		812.2		474.4		112.8		225.0
Cash and short-term investments		56.0		33.9		2.7		19.4

Total liquidity	$	868.2	$	508.3	$	115.5	$	244.4

Summary of Contractual Obligations

The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations.

Contractual Cash Obligations at December 31, 2014


	Payments Due by Period
*(millions) (US$)*	*Total*		*2015*		*2016*		*2017*		*2018-2019*		*After 2019*
Long-term debt ⁽¹⁾	$	3,610.5	$	274.5	$	333.4	$	300.0	$	354.2	$	2,348.4
Operating leases/rentals/capacity payments ⁽²⁾		118.8		38.9		22.6		16.9		22.0		18.4
Net purchase obligations/commitments ^(2) (3)		321.6		204.5		86.8		19.8		10.5		0.0
Interest payment obligations		1,980.6		175.4		158.8		151.2		235.4		1,259.8
Pension plan ⁽⁴⁾		0.0		0.0		0.0		0.0		0.0		0.0

Total contractual obligations	$	6,031.5	$	693.3	$	601.6	$	487.9	$	622.1	$	3,626.6

(1)	Includes debt at TECO Finance, Tampa Electric, PGS, NMGI and NMGC. The payments due in 2015 were made as of June 30, 2015. Long-term debt as at June 30, 2015 was US$3,851.8, net of unamortized debt discount.

(2)	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 approved by the FPSC and NMPRC.

(3)

Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2014, these commitments include Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.

(4)

Under calculation requirements of the Pension Protection Act, as of the January 1, 2015 measurement date, TECO Energy’s pension plan was essentially fully funded. Under MAP 21, TECO Energy is not required to make additional cash contributions over the next five years; however it may make additional cash contributions from time to time. Future contributions are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors.

Long-Term Commitments

TECO Energy has commitments under long-term leases, primarily for building space, capacity payments, vehicles, office equipment and heavy equipment. In addition, TECO Energy 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 power purchase agreements, and other net purchase obligations/commitments at December 31, 2014:


*(millions) (US$)*	Capacity Payments		Operating Leases⁽¹⁾		Net Purchase Obligations/Commitments⁽¹⁾		*Total*
Year ended December 31:
2015	$	30.0	$	8.9	$	204.5	$	243.4
2016		14.6		8.0		86.8		109.4
2017		9.9		7.0		19.8		36.7
2018		10.1		6.2		5.2		21.5
2019		0.0		5.7		5.3		11.0
Thereafter		0.0		18.4		0.0		18.4

Total future minimum payments	$	64.6	$	54.2	$	321.6	$	440.4

(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.

LEGAL PROCEEDINGS

From time to time, TECO Energy and its subsidiaries are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management of TECO Energy 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. Certain of such legal proceedings of TECO Energy and its subsidiaries are described below.

Tampa Electric Legal Proceedings

A 33-year old man made contact with a primary line in June 2013, suffering severe burns. He and his wife are suing 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 alleges, among other things, negligence and loss of consortium. As of June 30, 2015, discovery in the case was ongoing.

PGS 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 scheduled for the fourth quarter of 2015.

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

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

Eighteen insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment as discussed above. These subrogation matters are pending and discovery is proceeding. NMGC has filed motions to dismiss similar to those filed in the class actions.

TGH Legal Proceedings - TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On December 19, 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TECO Guatemala Holdings, LLC (“TGH”), against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (the “Award”). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately US$21.1 million, plus interest from October 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 US$7.5 million of the costs that it incurred in pursuing the arbitration.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. In addition, on April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding. While the duration of the annulment proceedings is uncertain, a hearing is scheduled in October 2015 with a decision by the ad hoc committee expected in mid- to late-2016. Publicly-filed results to date for TECO Energy do not yet reflect any benefit of this decision.

Risk Factors Relating to TECO Energy

Failure to dispose of TECO Coal

On September 29, 2014, the board of directors of TECO Energy authorized management to enter into negotiations for the sale of TECO Coal. As a result of this and other factors, TECO Coal was accounted for as an asset held for sale and has been reported as a discontinued operation since September 30, 2014. A pre-tax US$194.5 million impairment charge related to the held-for-sale TECO Coal assets was cumulatively recorded during 2014 and 2015. Efforts to dispose of TECO Coal are ongoing.

In addition, TECO Energy has indemnified sureties that have issued bonds in support of TECO Coal’s operations that TECO Energy may be liable for in the event any of those bonds are called upon by the beneficiary of those bonds.

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 shown indications of improvement, 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.

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, transporting gas or make the existing generating facilities of Tampa Electric uneconomic. In addition, advances in such technologies could reduce electrical or natural gas demand, which could negatively impact the results of operations, net income and cash flows of TECO Energy.

TECO Energy’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations

TECO Energy’s 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.

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 consistently earn returns on equity above their respective allowed ranges over an extended period of time, 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.

Various factors relating to the integration of NMGC could adversely affect TECO Energy’s business and operations

Based on the completion of the permanent financing for the NMGC acquisition, as at December 31, 2014, TECO Energy expected NMGC to be accretive to earnings for the full-year 2015 period. However, the anticipated accretion to earnings from NMGC during this 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 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 TECO Energy’s business, financial condition, results of operations or stock price. 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 U.S. EPA published a new CCR rule in the U.S. Federal Register on April 17, 2015 setting federal standards for companies that dispose of CCRs in onsite landfills and impoundments. The rule will go 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. The initial assessment is that activities in 2015 and 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. Under current Florida regulation, compliance related expenditures and capital investments related to complying with this new rule would be recoverable under Florida’s ECRC. 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 and it is not possible to predict the ultimate impact on Tampa Electric at this time. 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 those regulations will be eligible for such treatment.

Federal or state regulation of GHG emissions, depending on how they are enacted, 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 to implement their own regulations to accord to the federal standards. As such, Florida’s regulatory landscape may change, which could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by governmental authorized 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 may encounter more difficulty than its competitors in achieving cost-effective GHG emission reductions. However, because the ultimate form of Florida’s state plan remains unknown, it is not currently possible to predict the increased compliance costs that TECO may face as a result of the Clean Power Plan.

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

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

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 site 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 U.S. 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.

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 declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, trends toward smaller single family houses and increased multi-family housing.

Forecasts by 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 may be subject to cyber (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or 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 such a manner to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting 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.

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 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 may be hindered.

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 several 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 that TECO Energy cannot predict could adversely affect PGS and NMGC.

Increased customer use of distributed generation could adversely affect TECO Energy’s regulated electric utility business

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.

A proposed constitutional ballot initiative pending before the Florida Supreme Court to review its constitutionality and any corresponding legislative proposal could, if successful, promote increased direct sale and use of solar energy to generate electricity

A potential amendment to the Florida constitution in 2016 and corresponding 2016 legislation would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and to 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.

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 U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate

income tax rate could result in lower future tax expense and tax payments, it would reduce the value of TECO Energy’s existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and would reduce future cash flow of TECO Energy.

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 favorable 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.

Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses

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

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

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

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

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 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 some events 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 purchase rights allowing municipalities to purchase the corresponding subsidiary’s system within a given municipality’s boundaries under certain conditions.

Tampa Electric, PGS and NMGC may not be able to secure adequate rights-of-way 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 right-of-way 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 rights-of-way 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.

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, 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 June 30, 2015, 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.

TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates that do not appear on its balance sheet.

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 2016 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, as of the January 1, 2015 measurement date, TECO Energy’s pension plan was essentially fully funded. Under MAP 21, 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.

TECO Energy’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast

As at December 31, 2014, TECO Energy was 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 was 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 is 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 unfavorable 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 ‘Baa1’, and by Fitch at ‘BBB’. The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A2’ and by Fitch at ‘A-’. The senior unsecured debt of NMGC is rated by S&P at BBB+. A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P and Fitch, and a three notch downgrade by Moody’s, may affect 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 may have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any such 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.

TECO Energy is a holding company with no business operations of its own and depends on cash flow from its subsidiaries to meet its obligations

TECO Energy is a holding company with no business operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of TECO Energy’s operations are conducted by its subsidiaries. As a holding company, TECO Energy requires dividends and other payments from its subsidiaries to meet its cash requirements. If TECO Energy’s subsidiaries are unable to pay it dividends or make other cash payments to it, TECO Energy may be unable to pay dividends or satisfy its obligations.

***

This exhibit may be deemed to contain forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on TECO Energy’s current expectations and assumptions, and TECO Energy does not undertake to update that information or any other information contained in this exhibit, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; the ability to successfully implement the integration plans for NMGC and generate the financial results to make the acquisition

accretive; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales at the utility companies; economic conditions affecting the Florida and New Mexico economies; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; and the ability of TECO Energy to successfully close the sale of TECO Coal on reasonable terms, or otherwise exit the coal business. Additional information is contained under “Risk Factors” in TECO Energy, Inc.‘s Annual Report on Form 10-K for the period ended Dec. 31, 2014.

Teco (NYSE:TE)
Historical Stock Chart
From Mar 2024 to Apr 2024

Teco (NYSE:TE)
Historical Stock Chart
From Apr 2023 to Apr 2024

Market Data

News

Trading Tools

Markets

Discover

Hot Features

Follow Feed

Options Flow

Monitor

TE Teco Energy, Inc. (delisted)

Latest TE Messages

Loading Messages....

Teco Energy Inc News

Loading Messages....

Your Recent History

Company

Business

Popular

Get The App

Trending Now

Toplists

Market Data

News

Trading Tools

Markets

Discover

Hot Features

Follow Feed

Options Flow

Monitor

TE Teco Energy, Inc. (delisted)

Latest TE Messages

Loading Messages....

Teco Energy Inc News

Loading Messages....

Your Recent History

Company

Business

Popular

Get The App