ITEM 1. - BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP generates, transmits and distributes electricity to approximately 406,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).
UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits and distributes electricity to approximately 92,000 retail customers in Mohave and Santa Cruz counties.
UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.
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BUSINESS SEGMENT CONTRIBUTIONS
The table below shows the contributions to our consolidated after-tax earnings by our three business segments.
(1) Includes: UNS Energy parent company expenses, Millennium, UED, and intercompany eliminations.
See Note 3 for additional financial information regarding our business segments.
References in this report to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
Rates and Regulation of TEP, UNS Gas, and UNS Electric
The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas, and UNS Electric’s utility accounting practices and energy rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utility rates for retail electric and natural gas service are determined on a “cost of service” basis. Retail Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for our utility businesses to earn a reasonable return on rate base. Rate base is generally determined by reference to the original cost (net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items, plus a working capital component. Over time, additions to utility plant in service increase rate base while depreciation and retirements of utility plant reduce rate base.
The rates charged to retail customers by TEP, UNS Gas, and UNS Electric also include pass-through mechanisms that allow each utility to recover the actual costs of its fuel, transmission, and energy purchases.
The Federal Energy Regulatory Commission (FERC) regulates the terms and prices of transmission services and wholesale electricity sales, wholesale transport and purchases of natural gas, and portions of our accounting practices. TEP and UNS Electric have FERC tariffs to sell power at market-based rates.
TEP
TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UNS Energy. In 2012, TEP’s electric utility operations contributed 78% of UNS Energy’s operating revenues and comprised 84% of its assets.
SERVICE AREA AND CUSTOMERS
TEP is a vertically integrated utility that provides regulated electric service to approximately 406,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately one million people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to other entities in the western United States.
Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases, and other governmental entities. TEP’s retail sales are influenced by several factors, including economic conditions, seasonal weather patterns, demand side management (DSM) initiatives and the increasing use of energy efficient products, and opportunities for customers to generate their own electricity.
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Customer Base
The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. In 2013, the retail energy consumption by customer class is expected to be similar to the historical distribution.
Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2012, 2011, and 2010, TEP’s average number of retail customers increased by less than 1% in each year.
We expect the number of TEP’s retail customers to increase at a rate of less than 1% in 2013 and 2014.
Two of TEP’s largest retail customers are in the copper mining industry. TEP’s kilowatt-hour (kWh) sales to mining customers depend on a variety of factors including the market price of copper, the electricity rate paid by mining customers, and the mines’ potential development of their own electric generation resources. TEP’s kWh sales to mining customers increased by 0.9% in 2012 and 0.3% in 2011 as a result of increased production due to high copper prices.
Retail Sales Volumes
During the past three years, economic conditions and state requirements for energy efficiency and distributed generation have negatively affected retail electricity sales. TEP’s retail sales volumes in 2012 were approximately 9,265 Gigawatt-hours (GWh) or 1.1% below 2009.
Energy Service Providers
Although the Retail Electric Competition Rules established by the ACC in 1999 (Rules) contemplated that TEP’s retail customers may be eligible to choose an alternative energy service provider (ESP), portions of those Rules have been invalidated by the Arizona courts and there are no ESPs currently authorized to provide alternative retail electric service to TEP’s customers. See Rates and Regulation, below for more information regarding the status of retail competition in Arizona.
Wholesale Business
TEP’s electric utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions. See Generating and Other Resources, Purchases and Interconnections, below.
Generally, TEP commits to future sales based on expected excess generating capability, forward prices, and generation costs, using a diversified portfolio approach to provide a balance between long-term, mid-term, and spot energy sales. TEP’s wholesale sales consist primarily of two types of sales:
Long-Term Sales
Long-term wholesale sales contracts cover periods of more than one year. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers. TEP’s long-term contracts are described below:
• From January 1, 2012 through the end of the contract in May 2016, Salt River Project Agriculture Improvement and Power District (SRP) is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the Palo Verde Market Index. Prior to June 1, 2011, TEP received an annual demand charge of approximately $22 million.
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• TEP’s contract with the Navajo Tribal Utility Authority (NTUA) expires in December 2015. TEP serves the portion of NTUA’s load that is not served by the authority’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh per year. Since 2010, the price of 50% of the MWh sales to NTUA from June to September has been based on the Palo Verde Market Index. In 2012, approximately 13% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.
• TEP’s 2 MW contract with the Tohono O’odham Utility Authority expires in 2014.
Short-Term Sales
Forward contracts commit TEP to sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one-month, three-month, or one-year periods. TEP also engages in short-term sales by selling energy in the daily or hourly markets at fluctuating spot market prices and making other non-firm energy sales. All revenues from short-term wholesale sales offset fuel and purchased power costs and are passed through to TEP’s retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. See Rates and Regulation, below.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, for additional discussion of TEP’s wholesale marketing activities.
GENERATING AND OTHER RESOURCES
At December 31, 2012, TEP owned or leased 2,267 MW of net generating capability, as set forth in the following table:
(1) Leased asset as of December 31, 2012.
(2) Excludes 683 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2012, total owned capacity was 1,866 MW and leased capacity was 401 MW.
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Springerville Generating Station
TEP currently owns a 14% undivided interest in Unit 1 of the Springerville Generating Station (Springerville Unit 1) and the remainder is leased by TEP. Unit 2 of the Springerville Generating Station (Springerville Unit 2) is owned by San Carlos Resources, Inc. (San Carlos), a wholly-owned subsidiary of TEP. TEP’s other interests in the Springerville Generating Station (Springerville) include leasehold interests in the Springerville Coal Handling Facilities and the facilities at Springerville used in common by all four Springerville units (Springerville Common Facilities).
Springerville Unit 1 Leases
The terms of the leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities (Springerville Unit 1 Leases), expire in 2015 but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back the remaining 50% interest in the Springerville Common Facilities.
In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure to determine the fair market value purchase price. The formal appraisal process was completed in accordance with the Springerville Unit 1 lease agreements. The purchase price was determined to be $478 per kW of capacity, based on a continuous capacity rating of 387 MW. TEP has until September 1, 2013 to give notice that it will exercise its purchase option, with the purchase occurring in January 2015. TEP can choose to exercise this option to purchase any or all of the lease interests not currently owned by TEP. If TEP chooses to purchase all of the remaining interests in Springerville Unit 1 from the owner participants, the aggregate purchase price would be $159 million. See Item 3. - Legal Proceedings, Springerville Unit 1 Appraisal.
Springerville Common Facilities Leases
The leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities (Springerville Common Facilities Leases), which expire in 2017 and 2021, have optional fair market value renewal options as well as a fixed-price purchase provision. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 and $68 million in 2021.
Springerville Coal Handling Facilities Lease
In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. Since entering the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in April 2015 but have optional fixed-rate renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million.
See Note 6 and Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for more information regarding the Springerville leases.
Sundt Generating Station
The H. Wilson Sundt Generating Station (Sundt) and the internal combustion turbines located in Tucson are designated as “must-run generation” facilities. Must-run generation units are required to run in certain circumstances to maintain distribution system reliability and to meet local load requirements.
In 2010, TEP purchased 100% of the equity interest in the Sundt Unit 4 lease for approximately $51 million, redeemed the outstanding Sundt Unit 4 lease debt of $5 million, and terminated the lease agreement.
Renewable Energy Resources
Owned Resources
As of December 31, 2012, TEP owned 18 MW of photovoltaic (PV) solar generating capacity. The Springerville solar system, which is located near the Springerville Generating Station, has a total capacity of 6 MW. TEP’s remaining 12 MW of PV solar generating capacity is located in the City of Tucson.
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Power Purchase Agreements
In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 125 MW of capacity from solar resources, 50 MW of capacity from wind resources and 2 MW of capacity from a landfill gas generation plant. As of December 31, 2012, approximately 74 MW of contracted solar resources and 50 MW of contracted wind resources were operational. The remaining resources are expected to be developed over the next several years. The solar PPAs contain options that would allow TEP to purchase all or part of the related project at a future period. See Rates and Regulation, Renewable Energy Standard and Tariff below for more information.
Purchases and Interconnections
TEP purchases power from other utilities and power marketers. TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy for resale to certain wholesale customers under load and resource management agreements.
TEP typically uses generation from its gas-fired units, supplemented by power purchases, to meet the summer peak demands of its retail customers. Some of these PPAs are price-indexed to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure with fixed price contracts for a maximum of three years. TEP also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when doing so is more economical than generating its own energy.
TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry.
As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory reliability standards that are developed and enforced by the North American Electric Reliability Corporation (NERC) and subject to the oversight of the FERC. TEP periodically reviews its operating policies and procedures to ensure continued compliance with these standards.
Springerville Units 3 and 4
Springerville Units 3 and 4 are each approximately 400 MW coal-fired generating facilities that are operated, but not owned by TEP. These facilities are located at the same site as TEP’s Springerville Units 1 and 2. The owners of Springerville Units 3 and 4 compensate TEP for operating the facilities and pay an allocated portion of the fixed costs related to the Springerville Common Facilities and Coal Handling Facilities. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4.
Peak Demand and Resources
(1) Other Resources include firm power purchases and interruptible retail and wholesale loads. Additional firm power purchases were made in 2009 and 2010 to displace more expensive owned gas generation.
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Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions, and other factors. TEP’s retail peak demand declined over the period of 2008 to 2012 due primarily to weak economic conditions and the implementation of energy efficiency programs.
The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s total margin is the difference between total energy resources and coincident peak demand, and the reserve margin is the ratio of margin to coincident peak demand. TEP’s reserve margin in 2012 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.
Forecasted retail peak demand for 2013 is 2,243 MW, compared with actual peak demand of 2,290 MW in 2012 when Cooling Degree Days exceeded the ten-year average by 4.9%. TEP’s 2013 estimated retail peak demand is based on normal weather patterns. TEP believes existing generation capacity and power purchase agreements are sufficient to meet expected demand in 2013.
Future Generating Resources
TEP will add generating resources and/or transmission import capability to meet forecasted retail and firm wholesale load. TEP expects to add approximately 65 MW of new solar PV resources in 2013.
FUEL SUPPLY
Fuel Summary
Fuel cost and usage information is provided below:
Coal
TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico, and Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. The average cost per ton of coal, including transportation, was $45.84 in 2012, $46.64 in 2011, and $41.99 in 2010.
(1) Substantially all of the suppliers’ mining leases extend at least as long as coal is being mined in economic quantities.
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TEP Operated Generating Facilities
TEP is the operator, and sole owner (or lessee), of the Springerville Units 1 and 2 and Sundt Unit 4. The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects coal reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining lives.
The coal supplies for Sundt Unit 4 are transported approximately 1,300 miles by railroad from Colorado. Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with methane, a renewable energy resource, piped in from a nearby landfill. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic. In 2013, TEP expects to fuel Sundt Unit 4 with coal from inventory. See Note 4 for more information.
Generating Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generating facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo), and the San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service (APS), and San Juan, which is operated by Public Service Company of New Mexico (PNM), are mine-mouth generating stations located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. The coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining presently estimated lives of the stations.
Natural Gas Supply
TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from Southwest Gas Corporation under a retail tariff for North Loop’s 95 MW of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie, a 75 MW internal combustion turbine. TEP purchases capacity from El Paso Natural Gas Company (EPNG) for transportation from the San Juan and Permian Basins to its Sundt plant under a contract that expires in April 2013, with right-of-first-refusal for continuation thereafter. TEP also buys gas from third-party suppliers for Sundt and DeMoss Petrie.
TEP purchases gas transportation for Luna Generating Station (Luna) from EPNG from the Permian Basin to the plant site under an agreement effective through January 2017, with right-of-first-refusal for continuation thereafter. TEP purchases gas for its share of Luna from various suppliers in the Permian Basin region.
TRANSMISSION ACCESS
TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability, capacity and efficiency of its existing transmission and distribution systems.
TEP is participating in the continuation of the 500 kV transmission line from the Pinal West substation to the Pinal Central substation. TEP has obtained ACC approval to build a 40-mile 500-kV transmission line from the Pinal Central substation to the Tortolita substation northwest of Tucson to further enhance its ability to access the region’s energy resources. TEP expects the transmission lines to be in service in 2016. As a result of these high-voltage transmission additions, TEP expects that its ability to import energy into its service territory would increase by at least 250 MW.
Tucson to Nogales Transmission Line
TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP had previously capitalized $11 million related to the project, including $2 million to secure land and land rights. UNS Electric had previously capitalized $0.4 million related to the project.
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TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting the elimination of this project. In TEP’s pending rate case proceeding before the ACC, TEP entered into a proposed settlement agreement in which it agrees to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In the fourth quarter of 2012, TEP and UNS Electric wrote off a portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and $0.2 million, respectively, of costs incurred through 2012. See Note 4 and see Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for more information.
RATES AND REGULATION
2012 TEP Rate Case
In July 2012, TEP filed an application for a base rate increase with the ACC. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for more information.
Purchased Power and Fuel Adjustment Clause
The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component.
• The forward component is updated on April 1 of each year. The forward component is based on the forecasted fuel and purchased power costs for the 12-month period from April 1 to March 31 of the following year.
• The true-up component will reconcile any over/under collected amounts from the preceding 12-month period and will be credited to or recovered from customers in the subsequent year.
As part of the reconciliation of fuel and purchased power costs and PPFAC revenues, TEP credits, among other things, 100% of short-term wholesale revenues against the recoverable costs.
In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012 to recover $77 million of under-collected fuel and purchased power costs. At December 31, 2012, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $12 million.
A proposed settlement agreement in TEP’s pending rate case proceeding includes certain modifications to TEP’s PPFAC. In February 2013, TEP filed a request with the ACC to defer the effective date of resetting the PPFAC until the effective date of new rates in TEP’s pending rate case. This request is consistent with a provision of the settlement agreement. TEP cannot predict if or when the ACC will respond to its request. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, PPFAC Modifications, for more information.
Renewable Energy Standard and Tariff
The ACC’s Renewable Energy Standard (RES) requires TEP, UNS Electric, and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans is recovered from retail customers through the RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in TEP’s financial statements as a regulatory asset or liability.
In 2010, the ACC approved a funding mechanism that allows TEP to recover operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through RES funds until such costs are reflected in TEP’s Base Rates.
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In 2011, the ACC approved TEP’s RES implementation plan including investments of $28 million in 2012 and $8 million in 2013 for company-owned solar projects. In 2012, TEP’s solar energy investments totaled $28 million. During 2012, TEP earned approximately $2 million pre-tax on its non-rate base investments in solar projects. In 2012, TEP spent $30 million on its 2012 RES implementation plan and met the 2012 renewable energy target of 3.5% of retail kWh sales.
In January 2013, the ACC approved TEP’s 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2013 on solar investments made in 2010, 2011, and 2012. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales.
Electric Energy Efficiency Standards and Decoupling
In August 2010, the ACC approved new Electric Energy Efficiency Standards (Electric EE Standards) designed to require TEP, UNS Electric, and other affected electric utilities to implement cost-effective programs to reduce customers’ energy consumption. In 2012, the Electric EE Standards target total kWh savings of 3% of 2011 retail kWh sales; in 2013, the Electric EE Standards target total kWh savings of 5% of 2012 retail kWh sales. The Electric EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. The cumulative annual energy savings from TEP’s energy efficiency and DSM programs equaled approximately 2.5% of its 2011 retail kWh sales.
New and existing DSM programs, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC.
A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. See Item. 7-Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Energy Efficiency Resource Plan.
Decoupling
In 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s Electric EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. A proposed settlement agreement in TEP’s pending rate case proceeding includes a partial decoupling mechanism. See Item. 7-Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Lost Fixed Cost Recovery Mechanism.
Retail Electric Competition Rules
In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004. In 2008, the ACC opened an administrative proceeding to address the Rules but has since taken no action. During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP’s service territory as an ESP. Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP’s retail customers to use an alternative ESP. We cannot predict what changes, if any, the ACC will make to the Rules or if the ACC will grant a CC&N to an ESP.
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TEP’S UTILITY OPERATING STATISTICS
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ENVIRONMENTAL MATTERS
Clean Air Act Requirements
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan. TEP expects to capitalize environmental compliance costs of $10 million in 2013 and $27 million in 2014. In addition, TEP recorded Operations and Maintenance (O&M) expense of $15 million in 2012, $12 million in 2011, and $14 million in 2010 related to environmental compliance. TEP expects environmental O&M expenses to be $16 million in 2013.
TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its retail customers.
TEP has sufficient emission allowances to comply with acid rain SO2 regulations.
Hazardous Air Pollutant Requirements
The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules called the Mercury and Air Toxics Standards (MATS) setting limits for mercury emissions and other hazardous air pollutants from power plants.
Navajo
Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which includes the regional haze final Best Available Retrofit Technology (BART) rules.
San Juan
TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards.
Four Corners
Based on the EPA’s final standards, Four Corners may need mercury emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million. We expect TEP’s share of the annual operating cost of the mercury emission control equipment to be less than $1 million.
Springerville Generating Station
Based on the EPA’s final standards, Springerville Units 1 and 2 may need mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.
Sundt Generating Station
TEP expects the final EPA standards will have little effect on capital expenditures at Sundt.
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Climate Change
In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al. v. EPA that carbon dioxide and other Greenhouse Gases (GHG) are air pollutants under the Clean Air Act. In 2009, the EPA issued a final Endangerment Finding stating that GHGs endanger public health and welfare. The EPA issued final GHG regulations for new motor vehicles in 2010 triggering GHG permitting requirements for power plants under the Clean Air Act. As of January 2011, air quality permits for new sources and modifications of existing sources must include an analysis for GHG controls. In the near term, based on our current construction plans, we do not expect the new permitting requirements to impact TEP or UNS Electric.
In March 2012, the EPA released its proposed new source performance standard for GHGs. TEP does not anticipate this standard will have any material impact on its existing facilities.
Based on the competing proposals to regulate GHG emissions by federal, state, and local regulatory and legislative bodies and uncertainty in the regulatory and legislative processes, the scope of such requirements and initiatives and their effect on our operations cannot be determined at this time.
Regional Haze Rules
The EPA’s regional haze rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight. The EPA oversees Regional Haze planning for these power plants.
Complying with the EPA’s BART findings, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.
Navajo
In January 2013, the EPA proposed an alternative BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant’s particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP’s share of annual operating costs are estimated at less than $1 million for each of the control technologies (SCR and baghouses).
San Juan
In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.
In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit United States Court of Appeals (Circuit Court). In addition, PNM filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA’s reconsideration and the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP’s five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the Court’s decision.
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In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction (SNCR) technology on San Juan Units 1 and 4 by January 31, 2016. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million.
TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At December 31, 2012, the book value of TEP’s share of San Juan Units 1 and 2 was $217 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals.
If the proposed plan is not accepted and agreed to by the EPA, New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in 2013 to meet the FIP compliance deadline. TEP cannot predict the outcome of this matter.
Four Corners
In August 2012, the EPA finalized the Regional Haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install SCR technology is about $35 million. TEP’s share of annual operating costs for SCR is estimated at $2 million.
Springerville
Regional Haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.
Sundt
In December 2012, the EPA issued a proposed rule on provisions, that had not been previously addressed, in the Arizona State Implementation Plan related to regional haze. Contrary to the Arizona plan the EPA disapproved, among other things, the determination that Sundt Unit 4 is not subject to the BART provisions of the regional haze rule and is therefore subject to BART requirements. If the BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART rule which is likely to be completed in October 2013. The EPA is expected to release a proposed BART requirement for Sundt Unit 4 in March 2013.
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Environmental Investments and Expenses
The table below provides a summary of the estimated impact of pending environmental regulations on TEP’s annual O&M expense and capital expenditures.
(1) If SNCR technology is installed on San Juan Unit 1, TEP estimates its share of the cost would be approximately $25 million. See Regional Haze Rules, San Juan, above.
Coal Combustion Residuals
In 2010, the EPA proposed a rule to regulate the handling and disposal of coal ash and other Coal Combustion Residuals (CCRs). The EPA has proposed regulating CCRs as either non-hazardous solid waste or hazardous waste. The hazardous waste alternative would require additional capital investments and operational costs for both storage and handling at plants and transportation to disposal locations. Both the hazardous waste and non-hazardous solid waste alternatives would require liners for new ash landfills or expansions to existing ash landfills. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets. San Juan may also be subject to separate regulations being drafted by the Office of Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits.
The EPA has not yet indicated a preference for an alternative. Each option would allow CCRs to be beneficially reused or recycled as components of other products. We expect the EPA to issue a final rule in 2013 or 2014. TEP cannot determine the financial impact of this rulemaking at this time.
UNS GAS
SERVICE TERRITORY AND CUSTOMERS
UNS Gas is a gas distribution company serving approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as Santa Cruz County in southeastern Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 700,000. UNS Gas’ customer base is primarily residential. Sales to residential customers provided approximately 58% of total revenues in 2012.
UNS Gas’ annual retail customer growth rate was less than 1% from 2010 through 2012. In 2013, we expect UNS Gas’ retail customer base to increase by approximately 0.4%.
GAS SUPPLY AND TRANSMISSION
UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased and is affected by weather, supply issues, the economy, and other factors. UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month.
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UNS Gas buys most of the gas it distributes from the San Juan Basin. The gas is delivered on the EPNG and Transwestern Pipeline Company (Transwestern) interstate pipeline systems under firm transportation agreements with combined capacity sufficient to meet UNS Gas’ customers’ demands.
With EPNG, the average daily capacity right of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000 therms per day in the winter season (November through March) to serve its northern and southern Arizona service territories. UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline. The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman and also the Griffith Power Plant in Mohave County.
UNS Gas signed a separate agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line that expires in 2024. UNS Gas’ average daily capacity right is 126,100 therms per day, with an average of 221,900 therms per day in the winter season.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Liquidity and Capital Resources, Contractual Obligations, UNS Gas Supply Contracts, for more information.
RATES AND REGULATION
2012 UNS Gas Rate Order
In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a Lost Fixed Cost Recovery (LFCR) mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the Gas Energy Efficiency Standards (Gas EE Standards). The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012. The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills was offset by a temporary credit adjustment to the PGA. See Purchased Gas Adjustor, below, for more information.
2010 UNS Gas Rate Order
The ACC authorized a Base Rate increase of $3 million, or 2%, effective in April 2010.
Purchased Gas Adjustor
The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism.
The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that calculates the 12-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a 12-month period. The annual cap on the maximum increase in the PGA factor is 15 cents per therm in a 12-month period.
At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customer basis, UNS Gas is required to make a filing with the ACC to determine how the over-collected balance should be returned to customers.
In April 2012, the ACC approved a temporary PGA credit adjustment of 4.5 cents per therm which became effective on May 1, 2012. At December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.
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Gas Energy Efficiency Standards and Decoupling
In 2010, the ACC approved Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2012, the Gas EE Standards targeted total retail therm savings equal to 1.2% of 2011 sales; in 2013, the Gas EE Standards target total therm savings of 1.8% of 2012 retail therm sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020. UNS Gas’ programs, during 2011 and 2012, saved cumulative energy equal to approximately 0.35% of its 2011 retail therm sales.
New and existing DSM programs, renewable energy technology that displaces gas, and certain energy efficient building codes are acceptable means to meet the Gas EE Standards. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas’ DSM programs and rates charged to retail customers for these programs are subject to ACC approval.
In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Energy Efficiency plan or the subsequent requests.
ENVIRONMENTAL MATTERS
UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Gas’ facilities are in substantial compliance with existing regulations. See Item. 1 - Business, TEP, Environmental Matters, for more information.
UNS ELECTRIC
SERVICE TERRITORY AND CUSTOMERS
UNS Electric is a vertically integrated electric utility company serving approximately 92,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 250,000. UNS Electric’s annual retail customer growth rate was less than 1% from 2010 through 2012. We estimate that UNS Electric’s retail customer base will increase by approximately 0.8% in 2013. UNS Electric’s customer base is primarily residential, with some commercial and industrial customers. Peak demand for 2012 was 437 MW.
POWER SUPPLY AND TRANSMISSION
Purchased Energy
UNS Electric relies on a portfolio of long, intermediate, and short-term purchases to meet customer load requirements.
Generating Resources
UNS Electric owns and operates Black Mountain Generating Station (BMGS), a 90 MW gas-fired facility located near Kingman, Arizona. In July 2011, UNS Electric purchased BMGS from UED. UNS Gas purchases and transports natural gas to BMGS for UNS Electric under long-term natural gas transportation and sales agreements. See Rates and Regulation, 2010 UNS Electric Rate Order, below for more information.
UNS Electric also owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. Valencia consists of four gas and diesel-fueled combustion turbine units and provides approximately 62 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas.
Renewable Energy Resources
UNS Electric agreed to purchase the output of a combined wind farm and solar generating facility located near Kingman. The above-market cost of energy purchased through the 20-year PPA will be recovered through the RES surcharge. For more information see Rates and Regulation, Renewable Energy Standard and Tariff below.
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Future Generating Resources
UNS Electric invested $5 million in 2012 in company-owned solar PV capacity and expects to invest approximately $5 million in 2013 and 2014 in company-owned solar PV capacity. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff for more information.
Transmission
UNS Electric imports the power generated at BMGS into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has transmission service agreements with WAPA for its transmission capacity that expire in June 2016.
UNS Electric is upgrading its existing 115 kV transmission line serving Santa Cruz County to 138 kV to improve service reliability. This upgrade is expected to be completed by October 2014 and is included in UNS Electric’s current capital expenditures forecast. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resources for more information.
RATES AND REGULATION
2012 UNS Electric Rate Filing
In December 2012, UNS Electric filed an application for a base rate increase with the ACC. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Filing, for more information.
2010 UNS Electric Rate Order
In 2010, the ACC authorized a Base Rate increase of $7.4 million, or 4%, effective in October 2010.
The 2010 UNS Electric Rate Order approved UNS Electric’s purchase of BMGS from UED.
The 2010 UNS Electric Rate Order also approved a plan for UNS Electric to invest $5 million each year from 2011 through 2014 in solar projects that would be owned by UNS Electric.
In compliance with the 2010 Rate Order, UNS Electric filed a rate case application in December 2012. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Filing, for more information.
Purchased Power and Fuel Adjustment Clause
The PPFAC allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component.
• The forward component is updated on June 1 of each year. The forward component is based on the forecasted fuel, transmission, and purchased power costs for the 12-month period from June 1 of the current year to May 31 of the following year, less the base fuel, transmission, and purchased power costs embedded in Base Rates. The cap on the PPFAC forward component, over the 6.77 cents per kWh in Base Rates, is 1.845 cents per kWh.
• The true-up component will reconcile any over/under collected amounts from the preceding 12-month period and will be credited to or recovered from customers in the subsequent year.
At December 31, 2012, UNS Electric’s PPFAC bank balance was under-collected by $11 million on a billed-to-customer basis.
Renewable Energy Standard and Tariff
The ACC’s RES requires UNS Electric, TEP, and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC. The approved costs of carrying out those plans are recovered from retail customers through the RES surcharge. Any surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in UNS Electric’s financial statements as a regulatory asset or liability.
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As part of the 2010 UNS Electric rate order, the ACC authorized UNS Electric to recover operating costs, depreciation, property taxes, and a return on its investment in company-owned solar projects through RES funds until these costs are reflected in its Base Rates. Under these terms, UNS Electric expects to invest $5 million annually in 2013 and 2014 in solar photovoltaic projects.
In January 2013, the ACC approved UNS Electric’s 2013 RES implementation plan. UNS Electric will collect approximately $7 million from customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on investment to UNS Electric for company-owned solar projects.
Energy Efficiency Standards and Decoupling
In 2010, the ACC approved Electric EE Standards designed to require UNS Electric, TEP, and other affected electric utilities to implement cost effective DSM programs. For more information, see TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above. UNS Electric’s programs, during 2011 and 2012, saved cumulative energy equal to approximately 2.5% of its 2011 retail kWh sales.
UNS Electric filed a general rate case in December 2012 which included a request for a partial decoupling mechanism. See Item. 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Case, Lost Fixed Cost Recovery Mechanism.
In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter.
ENVIRONMENTAL MATTERS
UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Electric believes that its facilities are in substantial compliance with all existing regulations and will be in compliance with expected environmental regulations. See Item. 1 - Business, TEP, Environmental Matters, for more information.
OTHER NON-REPORTABLE SEGMENTS
Millennium
As of December 31, 2012, Millennium had assets of $7 million, including cash and cash equivalents of $4 million. In total, Millennium’s assets represented less than 1% of UNS Energy’s total consolidated assets. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other Non-Reportable Business Segments, for more information.
SES
SES, a wholly-owned subsidiary of Millennium, provides electrical contracting and meter reading services in Arizona, as well as other services at Springerville.
EMPLOYEES (As of December 31, 2012)
TEP had 1,392 employees, of which approximately 49% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A new collective bargaining agreement between the IBEW and TEP was entered into in January 2013 and expires in January 2016.
UNS Gas had 186 employees, of which 110 employees were represented by IBEW Local No. 1116 and 5 employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2015 and February 2014, respectively.
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UNS Electric had 148 employees, of which 30 employees were represented by the IBEW Local No. 387 and 88 employees were represented by the IBEW Local No. 769. The existing agreements with the IBEW Local No. 387 and No. 769 expire in February 2014 and June 2013, respectively.
SES had 253 employees, of which 226 are represented by IBEW Local No. 1116 and 16 by IBEW Local No. 570. These agreements expire in December 2014 and May 2013, respectively.
EXECUTIVE OFFICERS OF THE REGISTRANTS
Executive Officers - UNS Energy and TEP
Executive Officers of UNS Energy and TEP, who are elected annually by UNS Energy’s Board of Directors and TEP’s Board of Directors, are as follows:
(1) Mr. Larson is also Treasurer at UNS Energy.
(2) Mr. Grant is also Treasurer at TEP.
Paul J. Bonavia
Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009. He also served as President from January 2009 to December 2011. Prior to joining UNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
David G. Hutchens
Mr. Hutchens has served as President of UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995.
Michael J. DeConcini
Mr. DeConcini has served as Senior Vice President, Operations of UNS Energy since May 2010 and Senior Vice President and Chief Operating Officer of TEP from May 2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution.
Kevin P. Larson
Mr. Larson has served as Senior Vice President and Chief Financial Officer of UNS Energy and TEP since September 2005. Mr. Larson is also Treasurer of UNS Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Treasurer in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.
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Philip J. Dion III
Mr. Dion has served as Vice President of Public Policy of UNS Energy and TEP since April 2010. Mr. Dion joined UNS Energy in February 2008 as Vice President of Legal and Environmental Services. Prior to joining UNS Energy, Mr. Dion was chief of staff and chief legal advisor to Commissioner Marc Spitzer of the FERC. Mr. Dion previously worked in various roles at the ACC, including as an administrative law judge and as an advisor to Mr. Spitzer, prior to his appointment to the FERC.
Kentton C. Grant
Mr. Grant has served as Vice President of Finance and Rates of UNS Energy and TEP since January 2007. Mr. Grant also serves as Treasurer of TEP. Mr. Grant joined TEP in 1995.
Todd C. Hixon
Mr. Hixon has served as Vice President and General Counsel of UNS Energy and TEP since May 2011. Mr. Hixon joined TEP’s legal department in 1998 and served in a variety of capacities, most recently serving as Associate General Counsel.
Arie Hoekstra
Mr. Hoekstra has served as Vice President of Generation of UNS Energy and TEP since January 2007. Mr. Hoekstra joined TEP in 1979 and thereafter served in various positions at TEP’s generating stations in Tucson and Springerville.
Karen G. Kissinger
Ms. Kissinger has served as Vice President, Controller and Principal Accounting Officer of UNS Energy and TEP since January 1998 and has served as Chief Compliance Officer since 2003. Ms. Kissinger joined TEP as Vice President and Controller in January 1991.
Mark Mansfield
Mr. Mansfield is Vice President of Generation. He joined the company in 2008, most recently serving as Senior Director of Generation. Prior to joining TEP, Mr. Mansfield held various leadership positions at PacifiCorp Energy.
Thomas A. McKenna
Mr. McKenna has served as Vice President of Engineering of UNS Energy and TEP since January 2007. Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998.
Catherine E. Ries
Ms. Ries has served as Vice President of Human Resources of UNS Energy and TEP since June 2007. Prior to joining UNS Energy, Ms. Ries worked for Clopay Building Products, a division of Griffon Corporation, from 2000 to 2007, and held the position of Vice President of Human Resources.
Herlinda H. Kennedy
Ms. Kennedy has served as Corporate Secretary of UNS Energy and TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.
SEC REPORTS AVAILABLE ON UNS ENERGY’S WEBSITE
UNS Energy and TEP make available their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after they electronically file them with, or furnish them to, the Securities and Exchange Commission (SEC). These reports are available free of charge through UNS Energy’s website address: http://www.uns.com. A link from UNS Energy’s website to these SEC reports is accessible as follows: At the UNS Energy main page, select Investors from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page. UNS Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UNS Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, is also available on UNS Energy’s website.
UNS Energy and TEP are providing the address of UNS Energy’s website solely for the information of investors and do not intend the address to be an active link. Information contained at UNS Energy’s website is not part of any report filed with the SEC by UNS Energy or TEP.
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ITEM 1A.
ITEM 1A. - RISK FACTORS
The business and financial results of UNS Energy and TEP are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the SEC. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational.
REVENUES
National and local economic conditions can have a significant impact on the results of operations, net income, and cash flows at TEP, UNS Gas, and UNS Electric.
Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the company’s residential, commercial, and industrial customers. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 0.4% in each year from 2008 through 2012 compared with average increases of approximately 2% in each year from 2003 to 2007. In 2012, total retail kWh sales were 0.7% below 2011 levels. TEP estimates that a 1% change in annual retail sales could impact pre-tax net income and pre-tax cash flows by approximately $6 million.
Similar impacts were felt at UNS Gas and UNS Electric. Annual average increases in the number of retail customers at both companies remained below 1% in 2008 through 2012 compared with average annual growth rates of 3% from 2003 to 2007. We estimate that a 1% change in annual retail sales at UNS Gas and UNS Electric could impact pre-tax net income and pre-tax cash flows by approximately $1 million.
New technological developments and the implementation of new Energy Efficiency Standards will continue to have a significant impact on retail sales, which could negatively impact UNS Energy’s results of operations, net income, and cash flows.
Heightened awareness of energy costs has increased demand for products intended to reduce consumers’ use of electricity. TEP and UNS Electric also are promoting DSM programs designed to help customers reduce their energy use, and these efforts will increase significantly under energy efficiency rules approved in 2010 by the ACC. Unless the ACC makes a specific provision for the recovery of usage-based revenues lost to these energy efficiency programs, the reduced retail sales that would result from the success of these efforts would negatively impact the results of operations, net income, and cash flows of TEP and UNS Electric.
The revenues, results of operations, and cash flows of TEP, UNS Gas, and UNS Electric are seasonal, and are subject to weather conditions and customer usage patterns, which are beyond the companies’ control.
TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales peak in the winter during home heating season. Cool summers or warm winters may reduce customer usage at all three companies, adversely affecting operating revenues, cash flows, and net income by reducing sales. TEP estimates that a 1% impact in annual retail sales would impact pre-tax net income and pre-tax cash flows by approximately $6 million. We estimate that a 1% change in annual retail sales at UNS Gas and UNS Electric would impact pre-tax net income and pre-tax cash flows by approximately $1 million.
REGULATORY
TEP, UNS Gas, and UNS Electric are subject to regulation by the ACC, which sets the companies’ Retail Rates and oversees many aspects of their business in ways that could negatively affect the companies’ results of operations, net income, and cash flows.
The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
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The ACC is charged with setting retail electric and gas rates that provide utility companies with an opportunity to recover their costs of service and earn a reasonable rate of return. The decisions these elected officials make on such matters impact the net income and cash flows of TEP, UNS Gas, and UNS Electric.
Changes in federal energy regulation may negatively affect the results of operations, net income, and cash flows of TEP, UNS Gas, and UNS Electric.
TEP, UNS Gas, and UNS Electric are subject to the impact of comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industries and the ways in which these industries are regulated. UNS Energy’s electric utility subsidiaries are subject to regulation by the FERC. The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale prices.
ENVIRONMENTAL
UNS Energy’s utility subsidiaries are subject to numerous environmental laws and regulations that may increase their cost of operations or expose them to environmentally-related litigation and liabilities. Many of these regulations could have a significant impact on TEP due to its reliance on coal as its primary fuel for energy generation.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste, and management of coal combustion residuals.
These laws and regulations can contribute to higher capital, operating, and other costs, particularly with regard to enforcement efforts focused on existing power plants and new compliance standards related to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations may result in litigation, and the imposition of fines, penalties, and a requirement for costly equipment upgrades by regulatory authorities.
We cannot provide assurance that existing environmental laws and regulations will not be revised or that new environmental laws and regulations will not be adopted or become applicable to our facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on our results of operations, particularly if those costs are not fully recoverable from our customers. TEP’s obligation to comply with the EPA’s BART determinations as a participant in the San Juan, Four Corners, and Navajo plants, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to meet their obligations and continue their participation in these plants. TEP cannot predict the ultimate outcome of these matters.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generating stations. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.
New federal regulations to limit greenhouse gas emissions could increase TEP’s cost of operations and result in a change in the composition of TEP’s coal-dominated generating fleet.
Based on the finding by the EPA in December 2009 that emissions of greenhouse gases endanger public health and welfare, the agency is in the process of regulating greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, federal, and international levels to address global climate change that could also result in the regulation of CO2 and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2012, 72% of TEP’s total energy resources came from its coal-fueled generating facilities.
Reductions in CO2 emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. Any future legislation or regulation addressing climate change could produce a number of other results including costly modifications to, or reexamination of the economic viability of, our existing coal plants; changes in the overall fuel mix of our generating fleet; or additional costs to fund energy efficiency activities. The impact of legislation or regulation to address global climate change would depend on the specific terms of those measures and cannot be determined at this time.
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FINANCIAL
Volatility or disruptions in the financial markets may increase our financing costs, limit our access to the credit markets, and increase our pension funding obligations, which may adversely affect our liquidity and our ability to carry out our financial strategy.
We rely on access to the bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. Market disruptions such as those experienced over the last four years in the United States and abroad may increase our cost of borrowing or adversely affect our ability to access sources of liquidity needed to finance our operations and satisfy our obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties we do business with, unprecedented volatility in the markets where our outstanding securities trade, and general economic downturns in our utility service territories. If we are unable to access credit at competitive rates, or if our borrowing costs dramatically increase, our ability to finance our operations, meet our short-term obligations, and execute our financial strategy could be adversely affected.
Changing market conditions could negatively affect the market value of assets held in our pension and other retiree plans and may increase the amount and accelerate the timing of required future funding contributions.
UNS Energy’s net income and cash flows can be adversely affected by rising interest rates.
As of February 13, 2013, TEP had $215 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a fixed-for-floating interest rate swap through September 2014. The interest rates are set weekly with maximum interest rates of 20% on $178 million of debt obligations and 10% on the remaining $37 million. The average weekly interest rate ranged from 0.06% to 0.26% in 2012. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $2 million.
UNS Energy, TEP, UNS Gas, and UNS Electric also are subject to risk resulting from changes in the interest rate on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on a spread over London Interbank Offer Rate (LIBOR) or an Alternate Base Rate. Each of these agreements is a committed facility and expires in November 2016.
If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would negatively impact UNS Energy’s, TEP’s, UNS Gas’, and UNS Electric’s results of operations, net income, and cash flows.
TEP, UNS Gas, and UNS Electric may be required to post margin under their power and fuel supply agreements, which could negatively impact their liquidity.
TEP, UNS Gas, and UNS Electric secure power and fuel supply resources to serve their respective retail customers. The agreements under which we contract for such resources include requirements to post credit enhancement in the form of cash or letters of credit (LOCs) under certain circumstances, including changes in market prices which affect contract values, or a change in creditworthiness of the respective companies.
In order to post such credit enhancement, TEP, UNS Gas, and UNS Electric would have to use available cash, draw under their revolving credit agreements, or issue LOCs under their revolving credit agreements.
The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 13, 2013, TEP had $169 million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may borrow is $70 million, so long as the combined amount drawn by both companies does not exceed $100 million (the size of their combined borrowing capacity under the revolving credit facility). As of February 13, 2013, UNS Gas had $70 million and UNS Electric had $70 million, available to borrow under their revolving credit facility. From time to time, TEP, UNS Gas, and UNS Electric use their respective revolving credit facilities to post collateral. If additional collateral is required, it may negatively impact TEP, UNS Gas, and/or UNS Electric’s ability to fund their capital requirements. As of December 31, 2012, TEP and UNS Electric each had posted less than $1 million with counterparties in the form of cash or LOCs.
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UNS Energy and its subsidiaries have debt which could adversely affect their business and results of operations.
UNS Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 2012, the ratio of total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UNS Energy and its subsidiaries was 63%. This debt level:
• requires UNS Energy and its subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on their debt, which could reduce the funds available for working capital, capital expenditures, acquisitions, and other general corporate purposes; and
• could limit UNS Energy and its subsidiaries’ ability to borrow additional amounts for working capital, capital expenditures, acquisitions, dividends, debt service requirements, execution of its business strategy, or other purposes.
The cost of purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power in 2015, could require significant outlays of cash in one year, which could be difficult to finance.
TEP leases the following generation facilities under separate sale and leaseback arrangements that expire in 2015:
TEP may renew the leases or purchase the assets when the leases expire in 2015. The renewal and purchase options for Springerville Unit 1 are for fair market value, with the fair market value purchase price having been determined in December 2011 through an appraisal process to be $159 million. The owner participants of Springerville Unit 1 have disputed the appraisal price; however, TEP believes that the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding.
The Springerville Coal Handling Facilities can be purchased in 2015 for a fixed price of $120 million. TEP also leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending in 2017 and 2021. Upon expiration of the Springerville Coal Handling and Common Facilities Leases (whether at the end of the initial term or any renewal term), TEP has the obligation under agreements with the owners of Springerville Units 3 and 4 to purchase such facilities. Upon acquisition by TEP, the owner of Springerville Unit 3 has the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities and a 17% interest in the Coal Handling Facilities.
Regulatory rules and other restrictions could limit the ability of TEP, UNS Gas, and UNS Electric to make distributions to UNS Energy.
As a holding company, UNS Energy is dependent on the earnings and distributions of funds from its subsidiaries to service its debt and pay dividends to shareholders.
Restrictions include:
• TEP, UNS Gas, and UNS Electric are restricted from lending to affiliates or issuing securities without ACC approval;
• The Federal Power Act states that an electric utility’s dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe there is a reasonable basis for TEP to pay dividends from current year earnings; and
• TEP, UNS Gas, and UNS Electric must be in compliance with their respective debt agreements to make dividend payments to UNS Energy.
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Unanticipated financing needs or reductions to net income could adversely impact our ability to comply with financial covenants in the UNS Energy, TEP, and UES Credit Agreements.
The UNS Energy, TEP, and UES credit and reimbursement agreements include a maximum leverage ratio. The leverage ratios are calculated as the ratio of total indebtedness to total capital. The ability to comply with these covenants could be adversely impacted by unanticipated borrowing needs or unexpected charges to earnings or shareholder equity. In the event that we seek to renegotiate these provisions to provide additional flexibility, we may need to pay fees or increased interest rates on borrowings as a condition to any amendments or waivers.
OPERATIONAL
The operation of electric generating stations involves risks that could result in unplanned outages or reduced generating capability that could adversely affect TEP’s or UNS Electric’s results of operations, net income, and cash flows.
The operation of electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel supply, and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of our business. If TEP’s or UNS Electric’s generating stations operate below expectations, TEP or UNS Electric could be adversely affected.
The operation of electric transmission and distribution systems involves a risk of significant unplanned outages that could adversely affect TEP’s and UNS Electric’s businesses, results of operations, net income, and cash flows.
The operation of electric transmission and distribution systems involves certain risks, including equipment failure and damage caused by storms, fires, or other hazards. Unplanned outages occur from time to time and are an inherent risk of our business. If TEP’s or UNS Electric’s transmission and distribution systems experience a significant failure, TEP or UNS Electric could be adversely affected.
The nature of our gas operations presents inherent risks of loss that could adversely affect our results of operations.
The operation of UNS Gas’ transmission and distribution systems involves certain risks, including gas leaks, fires, natural disasters, catastrophic accidents, 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 UNS Gas.
TEP could be subject to higher costs and the possibility of significant penalties as a result of mandatory transmission standards.
As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory transmission standards developed and enforced by NERC and subject to the oversight of FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.
We may be subject to cyber attacks and information security risks.
As operators of critical energy infrastructure, we may face a heightened risk of cyber attack, and our corporate and informational technology systems may be vulnerable to disability or failures as a result of unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. In addition, our utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. If, despite our security measures, a significant or widely publicized breach occurred, we could have our operations disrupted, property damaged, and customer information stolen; experience substantial loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.
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TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission 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.
TEP and UNS Electric rely on federal, state, and local governmental agencies to secure right-of-way and siting permits to construct transmission lines and distribution-related facilities. If adequate right-of-way and siting permits to build new transmission lines cannot be secured:
• TEP and UNS Electric may need to rely on more costly alternatives to provide energy to their customers;
• TEP and UNS Electric may not be able to maintain reliability in their service areas; or
• TEP and UNS Electric’s ability to provide electric service to new customers may be negatively impacted.
ITEM 1B.
ITEM 1B. - UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. - PROPERTIES
TEP PROPERTIES
TEP’s transmission facilities, located in Arizona and New Mexico, transmit the output from TEP’s remote electric generating stations at Four Corners, Navajo, San Juan, Springerville, and Luna to the Tucson area for use by TEP’s retail customers (see Item 1. Business, TEP, Generating and Other Resources). The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 140 companies to interchange generation capacity and transmission of energy.
As of December 31, 2012, TEP owned or participated in an overhead electric transmission and distribution system consisting of:
• 564 circuit-miles of 500-kV lines;
• 1,088 circuit-miles of 345-kV lines;
• 405 circuit-miles of 138-kV lines;
• 481 circuit-miles of 46-kV lines; and
• 2,612 circuit-miles of lower voltage primary lines.
TEP’s underground electric distribution system includes 4,410 cable-miles. TEP owns approximately 76% of the poles on which its lower voltage lines are located. Electric substation capacity consists of 103 substations with a total installed transformer capacity of 13,269,950 kilovolt amperes.
Substantially all of the utility assets owned by TEP are subject to the lien of the 1992 Mortgage. Springerville Unit 2, which is owned by San Carlos, a wholly-owned subsidiary of TEP, is not subject to the lien.
The electric generating stations (except as noted below), administrative headquarters, warehouse and service center are located on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located:
• on property owned by TEP;
• under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, easements, or other rights which are generally subject to termination;
• under or over private property as a result of easements obtained primarily from the record holder of title; or
• over American Indian reservations under grant of easement by the Secretary of Interior or lease by American Indian tribes.
It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.
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Springerville is located on property held by TEP under a long-term surface ownership agreement with the State of Arizona.
Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired land rights, easements and leases for the plant, transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP also has acquired easements for transmission facilities related to San Juan, Four Corners, and Navajo across the Zuni, Navajo, and Tohono O’dham American Indian Reservations. TEP, in conjunction with PNM and Freeport McMoRan, holds an undivided ownership interest in the property on which Luna is located.
TEP’s rights under these various easements and leases may be subject to defects such as:
• possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) and the American Indian tribes;
• possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without Congressional consent; or
• failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.
These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.
TEP, under separate sale and leaseback arrangements, leases the following generation facilities (which do not include land):
• Springerville Coal Handling Facilities;
• a 50% undivided interest in the Springerville Common Facilities; and
• Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities.
See Note 6 and Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for additional information on TEP’s capital lease obligations.
UES PROPERTIES
UNS Gas
As of December 31, 2012, UNS Gas’ transmission and distribution system consisted of approximately 31 miles of steel transmission mains, 4,229 miles of steel and plastic distribution piping, and 137,705 customer service lines.
UNS Electric
As of December 31, 2012, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 274 circuit-miles of 69-kV transmission lines, and 3,648 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 62 MW Valencia plant, the 90 MW BMGS, as well as 40 substations having a total installed capacity of 1,504,000 kilovolt amperes.
The gas and electric distribution and transmission facilities owned by UNS Gas and UNS Electric are located:
• on property owned by UNS Gas or UNS Electric;
• under or over streets, alleys, highways, and other places in the public domain, as well as national forests and state lands, under franchises, easements, or other rights which are generally subject to termination; or
• under or over private property as a result of easements obtained primarily from the record holder of title.
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ITEM 3.
ITEM 3. - LEGAL PROCEEDINGS
Right of Way Matters
TEP was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were requesting, among other things, that the transmission lines on these lands be removed. In June 2009, TEP and the other defendants filed motions to dismiss the lawsuit on procedural grounds. In March 2010, the court granted several of the defendants’ motions to dismiss and entered a final judgment dismissing the case in April 2010. The plaintiffs filed a Notice of Appeal with the BIA in May 2010, appealing the BIA’s decision to grant the rights of way that were the subject of the now-dismissed complaint. In June 2010, the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. The appeals are currently pending. TEP cannot predict the outcome of these appeals.
Springerville Unit 1 Appraisal
Springerville Unit 1 is leased by TEP under leases which expire in 2015 and which provide TEP with an option to purchase the lease interests upon the lease expiration at fair market value. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure with three appraisers in accordance with the lease agreements to determine the fair market value purchase price. The lease agreements provide that the purchase price determined through the appraisal procedure will be final and binding upon the parties. The aggregate purchase price for the owner participants’ lease interests was determined to be $159 million.
On April 26, 2012, TEP filed a petition to confirm the appraisal in the United States District Court for the District of Arizona naming the owner participants (Daimler Capital Services LLC, LDVFI TEP LLC, Alterna Springerville LLC, MWR Capital Inc., and Pacific Harbor Capital Inc.) and the owner trustee and co-trustee (Wilmington Trust Company and William J. Wade) as respondents. The petition states that TEP filed the petition since neither the owner participants nor the owner trustee and co-trustee have acknowledged that the purchase price determined by the appraisal procedure in December 2011 is final and binding and that TEP seeks an order from the court confirming the appraisal as an arbitration award under the Federal Arbitration Act (FAA).
On June 1, 2012, the owner participants filed a response in opposition to TEP’s petition. In their response, the owner participants allege that the appraisal procedure failed to yield a legitimate purchase price for the lease interests, stating, among other things, that not all of the three appraisers performed their appraisals in accordance with required standards. The owner participants requested that the court dismiss the action and deny TEP’s petition on the grounds that there is not a present controversy for the court to decide, since, among other things, TEP has not exercised the purchase option. The owner participants also dispute TEP’s position that the appraisal procedure should be treated as an arbitration award for purposes of judicial review. In January 2013, the court denied TEP’s petition on the grounds that the court is without jurisdiction under the FAA to confirm the appraisal.
On February 12, 2013, TEP appealed the matter to the United States Court of Appeals for the Ninth Circuit.
TEP believes that the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding. TEP intends to continue vigorously pursuing its legal remedies to confirm the results of the appraisal procedure.
In addition, see legal proceedings described in Note 4.
ITEM 4.
ITEM 4. - MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5.
ITEM 5. - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF COMMON EQUITY
Stock Trading
UNS Energy’s Common Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 13, 2013, the closing price was $46.42 with 7,881 shareholders of record.
TEP’s common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange.
Dividends
UNS Energy
UNS Energy’s Board of Directors expects to continue to pay regular quarterly cash dividends on our Common Stock; however, such dividends are subject to the Board’s evaluation of our financial condition, earnings, cash flows, and dividend policy.
On February 25, 2013, UNS Energy declared a first quarter cash dividend of $0.435 per share of Common Stock. The first quarter dividend, totaling approximately $18 million, will be paid March 25, 2013 to shareholders of record at the close of business March 13, 2013. The table below summarizes UNS Energy’s dividends paid in 2010 through 2012.
UNS Energy relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends.
TEP
TEP paid $30 million of dividends to UNS Energy in 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010.
TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement.
The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings.
UNS Gas
UNS Gas paid dividends to UNS Energy of $20 million in 2012, and $10 million in both 2011 and 2010. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Gas was in compliance with the terms of its note purchase agreement.
UNS Electric
UNS Electric paid dividends to UNS Energy of $10 million in 2012. UNS Electric did not pay any dividends to UNS Energy in 2011 or 2010. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
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The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Electric was in compliance with the terms of its note purchase agreement.
Other Non-Reportable Segments
In 2012, Millennium paid dividends of $14 million to UNS Energy. In 2011 and 2010, Millennium paid dividends of $3 million and $8 million to UNS Energy, respectively.
UED did not pay any dividends to UNS Energy in 2012. In 2011 and 2010 UED paid dividends to UNS Energy of $39 million and $9 million, respectively. Of those dividends paid by UED, the portions representing a return of capital were $28 million in 2011 and $4 million in 2010.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Dividends on Common Stock.
Common Stock Dividends and Price Ranges
(1) UNS Energy’s Common Stock price as reported by the New York Stock Exchange.
Convertible Senior Notes
In March 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In 2012, holders of approximately $147 million of the Convertible Senior Notes outstanding converted their interests into approximately 4.3 million shares of Common Stock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed at par for cash. See Item 7.- Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Convertible Senior Notes, below, for more information.
Issuer Purchases of Common Equity
UNS Energy did not purchase any shares of Common Stock during 2012, 2011, or 2010.
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ITEM 6.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
UNS Energy
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TEP
(1) See Note 1 for revisions to prior period financial statements.
(2) Other Investing Cash Flows in 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds.
(3) For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount, interest on operating lease payments, and expense on indebtedness.
See Item 7.
ITEM 7. - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UNS Energy and its three primary business segments and includes the following:
•
outlook and strategies;
•
operating results during 2012 compared with 2011, and 2011 compared with 2010;
•
factors which affect our results and outlook;
•
liquidity, capital needs, capital resources, and contractual obligations;
•
dividends; and
•
critical accounting policies.
UNS Energy is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP generates, transmits and distributes electricity to approximately 406,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western U.S. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).
UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company with approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated vertically integrated public utility with approximately 92,000 retail customers in Mohave and Santa Cruz counties.
UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no impact on UNS Energy’s consolidated financial statements.
Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.
Our business is comprised of three reporting segments - TEP, UNS Gas, and UNS Electric.
References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
UNS ENERGY CONSOLIDATED
OUTLOOK AND STRATEGIES
Our financial prospects and outlook are affected by many factors including: the outcome of TEP’s pending rate proceeding before the ACC; national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:
•
Focusing on our core utility businesses through operational excellence, investing in utility rate base, emphasizing customer satisfaction, and maintaining a strong community presence.
•
Strengthening the underlying financial condition of our utility subsidiaries by achieving constructive regulatory outcomes, evaluating our capital structure, improving our credit ratings, and promoting economic development in our service territories.
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•
Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP’s existing mix of generation resources and defining steps to achieve environmental objectives that protect the financial stability of our utility businesses.
•
Developing a long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.
•
Expanding TEP’s and UNS Electric’s portfolio of renewable energy resources and programs to meet Arizona’s Renewable Energy Standard (RES) while creating ownership opportunities for renewable energy projects that benefit customers, shareholders, and the communities we serve.
•
Developing strategic responses to Arizona’s Energy Efficiency Standards that protect the financial stability of our utility businesses and provide benefits to our customers.
RESULTS OF OPERATIONS
Contribution by Business Segment
We conduct our business through three primary business segments - TEP, UNS Gas, and UNS Electric. The table below shows the contributions to our consolidated after-tax earnings by these business segments.
(1) Includes: UNS Energy parent company expenses, Millennium, and UED.
Revision for Prior Period Financial Statements
In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012, as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011, and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 1.
Executive Overview
2012 Compared with 2011
TEP
TEP reported net income of $65 million in 2012 compared with $85 million in 2011. The decrease in net income was due primarily to: a decrease in retail kWh sales and margin revenues due in part to fewer Cooling Degree Days during the summer months compared with 2011, as well as the effects of the ACC’s energy efficiency and distributed generation requirements; a decrease in long-term wholesale margin revenues related to a change in the price of energy sold under TEP’s largest wholesale sales contract; higher depreciation and amortization expense due to an increase in plant-in-service; and a partial write-off of transmission-related assets. These factors were partially offset by a decrease in TEP’s Base O&M, resulting primarily from fewer planned generating plant outages. Net income in 2011 included the recognition of a gain related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations, below, for more information.
UNS Gas and UNS Electric
UNS Gas reported net income of $9 million in 2012 compared with net income of $10 million in 2011. See UNS Gas, Results of Operations, below, for more information.
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UNS Electric reported net income of $17 million in 2012 compared with net income of $18 million in 2011. See UNS Electric, Results of Operations, below, for more information.
Other Non-Reportable Segments
Millennium’s financial results are included in UNS Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in both 2012 and 2011. See Other Non-Reportable Segments, Results of Operations, below, for more information.
2011 Compared with 2010
TEP
TEP reported net income of $85 million in 2011 compared with $108 million in 2010. The decrease in net income was due primarily to: a decline in long-term wholesale margin revenues due to a change in the price of energy sold under TEP’s largest wholesale sales contract; a decrease in wholesale transmission revenues due in part to a temporary increase in wholesale transmission revenues in 2010; an increase in Base O&M due in part to an increase in planned generating plant outages; higher depreciation expense related to an increase in plant-in-service; and an increase in interest expense. Those factors were partially offset by the recognition of a gain in 2011 related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations, below, for more information.
UNS Gas and UNS Electric
UNS Gas reported net income of $10 million in 2011 compared with net income of $9 million in 2010. See UNS Gas, Results of Operations, below, for more information.
UNS Electric reported net income of $18 million in 2011 compared with net income of $15 million in 2010. The increase is due in part to a Base Rate increase that took effect in October 2010. See UNS Electric, Results of Operations, below, for more information.
Other Non-Reportable Segments
Millennium’s financial results are included in UNS Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in 2011 compared with a net loss of $13 million in 2010. Millennium’s results in the 2010 reflect losses related to the write-off of deferred taxes and impairment losses. See Other Non-Reportable Segments, Results of Operations, below, for more information.
O&M
The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense.
(1) Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with generally accepted accounting principles (GAAP). We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.
(2) Includes Millennium, UED, and UNS Energy stand-alone O&M, and inter-company eliminations.
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LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Dividends from UNS Energy’s subsidiaries represent the parent company’s primary source of liquidity. Under UNS Energy’s tax sharing agreement, subsidiaries make income tax payments to UNS Energy, which makes payments on behalf of the consolidated group to taxing authorities. See Income Tax Position, below, for more information.
The table below provides a summary of the liquidity position of UNS Energy and each of its segments:
(1) Includes Letters of Credit (LOCs) issued under revolving credit facilities.
(2) Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million.
(3) Includes cash and cash equivalents at Millennium and UED.
Short-term Investments
UNS Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. As of December 31, 2012, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet.
Access to Revolving Credit Facilities
We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP and UNS Gas/UNS Electric Credit Agreements may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Gas, and UNS Electric each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.
We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide support, as necessary, under energy procurement and hedging agreements. See Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk.
Fair Value Measurements
TEP’s income statement exposure to risk is mitigated as TEP reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability, or as a component of accumulated other comprehensive income (AOCI) rather than in the income statement. See Note 11 for more information.
LIQUIDITY AND CAPITAL RESOURCES
TEP Cash Flows
The table below shows the cash available to TEP after capital expenditures, scheduled debt payments, and payments on capital lease obligations:
(1) 2010 includes a $51 million payment for the purchase of Sundt Unit 4 lease equity.
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(2) Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows-Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required principal payments on debt and capital lease obligations (net), and pay dividends to UNS Energy.
Liquidity Outlook
During 2013, TEP expects to generate sufficient internal cash flows to fund the majority of its capital expenditures and operating activities. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to fund its business activities.
Operating Activities
In 2012, net cash flows from operating activities were the same when compared with 2011. Net operating cash flows in 2012 were impacted by: the collection of under-recovered fuel and purchased power costs; a decrease in purchased power costs due in part to lower market prices for power; lower O&M costs due in part to fewer scheduled outages at TEP’s generating facilities; a decrease in income tax refunds received due to overestimated payments made in 2010 and refunded in 2011; higher fuel costs paid due in part to an increase in coal inventory at Sundt Unit 4 and an increase in the output of gas-fired generating units; an increase in property tax payments due to higher rates and property values; and a decrease in interest received due to the declining balance of TEP’s investment in lease debt.
Investing Activities
Net cash flows used for investing activities decreased by $84 million in 2012 compared with 2011. A decrease in capital expenditures of $99 million was partially offset by a $19 million decrease in proceeds from the return of investment in Springerville lease debt.
Capital Expenditures
TEP’s forecasted capital expenditures are summarized below:
TEP’s estimated capital expenditures in 2015 exclude the potential $159 million purchase of interests in Springerville Unit 1 and the potential $120 million purchase of interests in Springerville Coal Handling Facilities upon the expiration of their respective leases in 2015. See Capital Lease Obligations, below, for more information.
TEP’s estimated capital expenditures include approximately $25 million for TEP’s share of potential environmental expenditures related to the installation of SNCR at San Juan Unit 1. TEP estimates its share of capital expenditures would be approximately $200 million if SCR technology were to be installed at San Juan Units 1 and 2 instead of SNCR at San Juan Unit 1. See Item. 1 Business, TEP, Environmental Matters, Regional Haze Rules, San Juan, for more information.
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All of these estimates are subject to continuing review and adjustment. Actual capital expenditures may be different from these estimates due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations, and other factors.
Financing Activities
In 2012, net cash from financing activities was $39 million lower than in 2011 due to: higher dividends paid to, and lower capital contributions from, UNS Energy; lower borrowings (net of repayments) made under TEP’s Revolving Credit Facility; and an increase in scheduled payments on TEP’s capital lease obligations. These cash outflows were partially offset by an increase in proceeds from the issuance of long-term debt (net of repayments).
TEP Credit Agreement
The TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $186 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016 and is secured by $386 million of Mortgage Bonds. As of December 31, 2012, there were no outstanding borrowings and less than $1 million of LOCs issued under the TEP Revolving Credit Facility.
In 2011, TEP reduced its LOC facility from $341 million to $186 million, following the repurchase of $150 million of variable rate IDBs and the cancellation of $155 million of LOCs supporting those bonds. See 2011 Bond Issuances, Purchase and Redemptions, below.
The TEP Credit Agreement contains restrictions on liens, mergers, and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UNS Energy. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement.
2010 TEP Reimbursement Agreement
In 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt pollution control bonds that were issued on behalf of TEP in 2010.
The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2012, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.
Capital Contribution from UNS Energy
In 2011, UNS Energy contributed $30 million of capital to TEP. TEP used the proceeds to partially fund the purchase of its headquarters building.
In 2010, UNS Energy contributed $15 million of capital to TEP. TEP used the proceeds to partially fund the purchase of Sundt Unit 4.
2012 Bond Issuances and Redemptions
In March 2012, $177 million of unsecured tax-exempt pollution control bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in March 2030 and may be redeemed at par on or after March 1, 2022. In April 2012, the proceeds of the bond issuance, as well as $7 million of internal cash, were used to redeem $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6.
In June 2012, approximately $16 million of unsecured tax-exempt IDBs were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in June 2030 and may be redeemed at par on or after June 1, 2022.
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In July 2012, the proceeds of the bond issuance were used to redeem approximately $16 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6.
In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the remaining proceeds used for general corporate purposes. See Note 6.
2011 Bond Issuances, Purchases, and Redemptions
In November 2011, TEP issued $250 million of 5.15% Notes due November 2021. TEP may call the debt anytime before August 15, 2021, with a make-whole premium plus accrued interest. After August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the sale to: repurchase $150 million of variable rate bonds; redeem $22 million of 6.1% fixed rate bonds; and repay $78 million of outstanding revolving credit facility balances.
The $150 million of tax-exempt variable rate debt purchased by TEP was not retired but will be held in treasury and may be reissued or refunded in the future. See Note 6.
2010 Bond Issuances
In 2010, $137 million of tax-exempt bonds were issued on behalf of TEP, with $37 million of such bonds being applied to redeem a corresponding amount of outstanding tax-exempt bonds. In addition, in 2010 TEP converted the interest rate mode on $130 million of tax-exempt bonds from a variable rate to a fixed rate.
Tax-Exempt Bonds
TEP has financed a substantial portion of utility plant assets with revenue bonds issued by governmental entities on TEP’s behalf. The interest on these bonds is excluded from gross income of the bondholder for federal income tax purposes. The proceeds of the bonds are loaned to TEP, with TEP agreeing to repay the loans by making payments in amounts and at times to enable payments of principal and of interest on the tax-exempt bonds to be paid when due. Of the $824 million of tax-exempt bonds outstanding as of December 31, 2012, $609 million are unsecured and bear interest at fixed rates and $215 million are variable rate bonds. The variable rate bonds accrue interest at a weekly rate, with bondholders having the right to require their bonds to be purchased upon demand at a purchase price of par plus accrued interest. Variable rate bonds which have been put for purchase are generally remarketed to third parties to pay the purchase price. Payments of principal, interest, and purchase price on the variable rate bonds are supported by direct-pay LOCs, with TEP being required to reimburse the LOC banks for drawings on the LOCs. See TEP Credit Agreement and TEP Reimbursement Agreement for more information.
Mortgage Indenture
TEP’s mortgage indenture creates a lien on and security interest in most of TEP’s utility plant assets. Springerville Unit 2, which is owned by San Carlos, is not subject to this lien and security interest. The mortgage indenture allows TEP to issue additional mortgage bonds on the basis of a percentage of net utility property additions and/or the principal amount of retired mortgage bonds. The amount of bonds that TEP may issue is also subject to a net earnings test under the mortgage indenture.
At December 31, 2012, TEP had a total of $423 million in outstanding Mortgage Bonds, consisting of $386 million in bonds securing the TEP Credit Agreement and $37 million in bonds securing the 2010 TEP Reimbursement Agreement.
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Capital Lease Obligations
At December 31, 2012, TEP had $353 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts in each of the obligations:
(1) The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities.
(2) See Item 3. - Legal Proceedings, Springerville Unit 1 Appraisal for information on a dispute related to the purchase option.
(3) TEP agreed with Tri-State, the lessee of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either (1) buy a portion of these facilities; or (2) continue making payments to TEP for the use of these facilities.
(4) The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.
TEP’s capital lease obligation balances decline over time due to the normal capital lease payments made by TEP. See Note 6 for more information about the fixed purchase price amounts.
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Contractual Obligations
The following chart displays TEP’s contractual obligations as of December 31, 2012 by maturity and by type of obligation:
See UNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations.
We have reviewed our contractual obligations and provide the following additional information:
•
TEP’s Credit Agreement contains pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility.
•
TEP’s Credit Agreement contains certain financial and other restrictive covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2012, TEP was in compliance with these covenants. See TEP Credit Agreement, above.
•
TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of December 31, 2012, TEP had posted less than $1 million in LOCs as collateral with counterparties for credit enhancement.
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Dividends on Common Stock
TEP paid $30 million of dividends to UNS Energy in 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010.
TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement, and certain financial covenants. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement.
The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings.
UNS GAS
RESULTS OF OPERATIONS
UNS Gas reported net income of $9 million in 2012, $10 million in 2011, and $9 million in 2010. We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months.
The table below provides summary financial information for UNS Gas:
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The table below shows UNS Gas’ therm sales and revenues:
(1) Percent change calculated on unrounded data and may not correspond exactly to data shown in table.
(2) Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business.
Retail therm sales during 2012 decreased by 8.5% compared with 2011 due in part to an 11.4% decrease in Heating Degree Days. Retail margin revenues decreased by 2.7%, or $2 million. UNS Gas had approximately 149,000 retail customers, which represents an increase of less than 1% compared with the end of 2011.
UNS Gas supplies natural gas to some of its large transportation customers. Approximately one half of the margin earned on these NSP sales is retained by UNS Gas while the remainder benefits retail customers through a credit to the Purchase Gas Adjustor (PGA) mechanism which reduces the gas commodity price.
FACTORS AFFECTING RESULTS OF OPERATIONS
Competition
New technological developments and the implementation of Gas EE Standards may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas. See Item 1. Business, UNS Gas, Rates and Regulation, Gas Energy Efficiency Standards and Decoupling, above, for more information.
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Rates
2012 UNS Gas Rate Order
In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a LFCR mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012.
The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills is offset by a temporary credit adjustment to the PGA. See Item 1. Business, UNS Gas, Rates and Regulation, Purchased Gas Adjustor.
Purchased Gas Adjustor
See Item 1. Business, UNS Gas, Rates and Regulation, Purchased Gas Adjustor.
Interest Rates
UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.
Fair Value Measurements
UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11 for more information.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Gas’ capital requirements consist primarily of capital expenditures. In 2012, capital expenditures were $16 million. UNS Gas expects operating cash flows to fund its future operating activities and a large portion of its construction expenditures. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements. Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.
Operating Cash Flow
The table below provides summary cash flow information for UNS Gas:
Operating Activities
Operating cash flows decreased by $4 million in 2012 when compared with 2011 due in part to a $4 million decrease in total gas revenues.
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Investing Activities
UNS Gas incurred capital expenditures of $16 million in 2012 compared with $13 million in 2011.
Financing Activities
Cash used for financing activities at UNS Gas was $9 million higher in 2012 than in 2011 due in part to an increase of $10 million in dividends paid to UNS Energy.
UNS Gas/UNS Electric Revolver
The UNS Gas/UNS Electric Revolver consists of a $100 million unsecured revolving credit and revolving letter of credit facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The UNS Gas/UNS Electric Revolver expires in November 2016.
UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver. UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue LOCs to provide credit enhancement for its natural gas procurement and hedging activities. As of December 31, 2012, UNS Gas had no outstanding borrowings or LOCs under the UNS Gas/UNS Electric Revolver.
The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. As of December 31, 2012, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Gas has $100 million of senior unsecured notes outstanding, of which $50 million matures in 2015 and $50 million matures in 2026.
All of UNS Gas’ senior unsecured notes are guaranteed by UES. The note purchase agreements for UNS Gas restrict transactions with affiliates, mergers, liens, restricted payments, and incurrence of indebtedness. The agreements also contain a minimum net worth test. As of December 31, 2012, UNS Gas was in compliance with the terms of its note purchase agreements.
UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.
Note Issuance
In August 2011, UNS Gas issued $50 million of 5.39% senior unsecured notes. The proceeds were used to pay off $50 million of senior unsecured notes that matured in August 2011.
Contractual Obligations
UNS Gas Supply Contracts
UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased. UNS Gas has firm transportation agreements with capacity sufficient to meet its current load requirements. These contracts expire in various years between 2013 and 2024. These costs are passed through to UNS Gas’ customers via the PGA.
UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month. UNS Gas hedged approximately 55% of its expected monthly consumption for the 2012/2013 winter season (November through March). Additionally, UNS Gas has approximately 37% of its expected gas consumption hedged for April through October 2013, and 30% hedged for the 2013/2014 winter season.
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The following table displays UNS Gas’ contractual obligations as of December 31, 2012 by maturity and by type of obligation:
UNS Gas conducts certain of its gas procurement and risk management activities under agreements whereby UNS Gas may be required to post margin due to changes in contract values, a change in UNS Gas’ creditworthiness, or exposures exceeding credit limits provided to UNS Gas. As of December 31, 2012, UNS Gas had not posted any such credit enhancements.
Dividends on Common Stock
UNS Gas paid dividends to UNS Energy of $20 million in 2012, and $10 million in both 2011 and 2010. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i) no default or event of default exists and (ii) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Gas was in compliance with the terms of its note purchase agreement. See Senior Unsecured Notes, above.
UNS ELECTRIC
RESULTS OF OPERATIONS
UNS Electric had net income of $17 million in 2012, compared with net income of $18 million in 2011.
As with TEP, UNS Electric’s operations are generally seasonal in nature, with peak energy demand occurring in the summer months.
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The table below provides summary financial information for UNS Electric:
The table below summarizes UNS Electric’s kWh sales and margin revenues:
(1) Percent change calculated on unrounded data and may not correspond exactly to data shown in table.
(2) Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business.
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In 2012, retail kWh sales decreased by 5.3% compared with 2011 due to a large customer generating a portion of its own electricity needs.
As of December 31, 2012, UNS Electric had approximately 92,000 retail customers, which was an increase of less than 1% compared with 2011.
Wholesale revenues increased by $11 million in 2012 due to an increase in short-term wholesale sales. All revenues from wholesale sales are credited against costs recovered through UNS Electric’s PPFAC.
FACTORS AFFECTING RESULTS OF OPERATIONS
2012 UNS Electric Rate Case
In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric’s 2010 Rate Order.
The key provisions of UNS Electric’s rate request include:
• an increase in non-fuel retail Base Rates of $7.5 million, or 4.6%, over adjusted test year revenues;
• an original cost rate base of approximately $217 million, which includes approximately $13 million of post test year adjustments for utility plant that is expected to be in service by June 30, 2013;
• a capital structure of approximately 47% debt and 53% equity; and
• a cost of long-term debt of 5.97% and return on equity of 10.50%.
Lost Fixed Cost Recovery Mechanism
UNS Electric proposed a LFCR mechanism that would allow UNS Electric to recover non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC’s Electric EE Standards and distributed generation requirements under the ACC’s RES. The LFCR is not a full decoupling mechanism and is not intended to recover lost fixed costs attributable to weather or economic conditions.
Transmission Cost Adjustment Mechanism
UNS Electric proposed a Transmission Cost Adjustment Mechanism (TCA) that would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers. UNS Electric’s proposed retail Base Rates include a transmission cost reflective of the current FERC rate. As the FERC rate changes, the TCA will result in a corresponding adjustment to the transmission component of retail Base Rates.
Energy Efficiency Resource Plan
UNS Electric proposed a three-year pilot program that would allow it to invest in energy efficiency programs in order to meet the ACC’s Electric EE Standards in the most cost-effective manner. Electric EE Standards investments would be considered regulatory assets and amortized over a four-year period. UNS Electric would earn a return on its investments and recover the return and amortization expense through the existing demand-side management surcharge.
UNS Electric requested new rates be effective no later than January 1, 2014. We cannot predict the outcome of this proceeding or whether UNS Electric’s rate request will be adopted by the ACC in whole or in part.
Competition
New technological developments and the implementation of Electric EE Standards may reduce energy consumption by UNS Electric’s retail customers. UNS Electric’s customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on UNS Electric’s services. Self-generation by UNS Electric’s customers has not had a significant impact to date. See Item 1. Business, UNS Electric, Rates and Regulation, Energy Efficiency Standards and Decoupling, above, for more information.
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Rates
See Item 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Order.
Large Customers
One of UNS Electric’s largest retail customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric’s retail rate structure and the customer’s peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer shut down its operations in UNS Electric’s service territory. As a result of these two events, we estimate UNS Electric’s non-residential retail margin revenues will be approximately $4 million lower in 2013 than in 2012.
Renewable Energy Standard and Tariff
See Item 1. Business, UNS Electric, Rates and Regulation, 2010 Renewable Energy Standard and Tariff.
Interest Rates
UNS Electric is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Electric may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.
Fair Value Measurements
UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11 for more information.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
In 2012, UNS Electric’s capital expenditures were $38 million. In 2011, UNS Electric had capital expenditures of $96 million, which included the purchase of BMGS for $63 million from an affiliate, UED. Going forward, UNS Electric expects operating cash flows to fund a large portion of its construction expenditures. Additional sources of funding future capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.
Operating Cash Flow
The table below provides summary cash flow information for UNS Electric:
Operating Activities
Cash provided by operating activities increased by $7 million in 2012 compared with 2011 due primarily to higher cash receipts from electric sales (net of fuel and purchased energy costs paid) partially offset by higher operations and maintenance costs.
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Investing Activities
UNS Electric had capital expenditures of $38 million in 2012 compared with $96 million in 2011. Capital expenditures in 2011 included $63 million related to the acquisition of BMGS from UED.
Financing Activities
Cash provided by financing activities at UNS Electric in 2012 decreased by $54 million compared with 2011. Financing activities in 2012 included $10 million in dividends paid to UNS Energy. Financing activities in 2011 included the following items related to the acquisition of BMGS: the issuance of $30 million of long-term debt; a $20 million equity investment from UNS Energy; and a $6 million payment to UED.
UNS Gas/UNS Electric Revolver
See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver, above, for a description of UNS Electric’s unsecured revolving credit agreement.
UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At December 31, 2012, UNS Electric had less than $1 million of outstanding LOCs under the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Electric has $100 million of senior unsecured notes outstanding, consisting of $50 million of 6.50% notes due in 2015 and $50 million of 7.10% notes due in August 2023. The notes are guaranteed by UES. The note purchase agreement for UNS Electric contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. As of December 31, 2012, UNS Electric was in compliance with the terms of its note purchase agreement.
Under the note purchase agreement, UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.
UNS Electric Credit Agreement
In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending in August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.
The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens, and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement. As of December 31, 2012, UNS Electric was in compliance with the terms of the credit agreement.
Contractual Obligations
UNS Electric Power Supply and Transmission Contracts
UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.
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UNS Electric’s power purchase contracts and risk management activities are subject to master agreements that may require UNS Electric to post margin due to changes in contract values or if there has been a material change in UNS Electric’s creditworthiness, or exposures exceeding credit limits provided to UNS Electric. As of December 31, 2012, UNS Electric had posted less than $1 million of such credit enhancements in the form of LOCs.
UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. See Item 1. Business, UNS Electric, Power Supply and Transmission, Transmission for more information.
The following table displays UNS Electric’s contractual obligations as of December 31, 2012 by maturity and by type of obligation:
See UNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations.
Dividends on Common Stock
UNS Electric paid $10 million of dividends to UNS Energy in 2012. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (i) no default or event of default exists and (ii) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Electric was in compliance with the terms of its note purchase agreement. See Senior Unsecured Notes, above.
OTHER NON-REPORTABLE BUSINESS SEGMENTS
RESULTS OF OPERATIONS
The table below summarizes the income (loss) for the other non-reportable segments in the last three years:
(1) Includes parent company expenses, UED, and reconciling adjustments.
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Millennium
Millennium’s net loss in 2010 resulted primarily from the write-off of deferred tax assets and impairment losses on certain investments.
UNS Energy Parent Company
UNS Energy parent company expenses in 2012, 2011, and 2010 primarily include interest expense (net of tax) related to the UNS Energy Convertible Senior Notes and the UNS Credit Agreement. During the first six months of 2012, UNS Energy converted or redeemed all $150 million of outstanding Convertible Senior Notes.
UED
In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. The FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million in July 2011.
UED did not pay any dividends to UNS Energy in 2012. In 2011, UED paid a $39 million dividend to UNS Energy, of which $28 million represented a return of capital. In 2010, UED paid a $9 million dividend to UNS Energy, of which $4 million represented a return of capital.
FACTORS AFFECTING RESULTS OF OPERATIONS
Millennium Investments
At December 31, 2012, Millennium had assets of $7 million including a cash balance of $4 million.
In July 2011, Millennium sold a building for $3 million resulting in an after-tax gain of approximately $1 million.
Note Receivable
In 2009, Millennium sold an equity investment, receiving an upfront payment of $5 million in 2009 and a $15 million promissory note. Millennium received the remaining principal amount of $15 million in 2012.
Dividends on Common Stock
Millennium made $14 million in dividend payments to UNS Energy in 2012, $3 million in 2011, and $8 million in 2010. All of these dividends represented return of capital distributions.
CRITICAL ACCOUNTING POLICIES
The preparation of the financial statements in accordance with GAAP requires management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. UNS Energy considers the areas described in the Critical Accounting Policies as those that could yield materially different financial statement results based on application and interpretation of accounting policy. Since making estimates and assumptions are subjective and complex, actual results could differ in subsequent periods. For additional information on UNS Energy’s other significant accounting policies and recently issued accounting standards see Note 1.
Accounting for Rate Regulation
We generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. However, sometimes these principles require special accounting treatment for regulated companies to show the effect of regulation. For example, the ACC can determine that we are allowed to recover certain expenses at a designated time in the future. In this situation, we defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when we are allowed to recover the costs from customers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until the rates charged to retail customers are reduced. We evaluate regulatory assets each period and believe recovery is probable.
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If in the future a portion of operations no longer meets regulatory accounting criteria, the impact would be material to the financial statements. If we stopped applying regulatory accounting to all our regulated operations, we would write off the related balances of regulatory assets as an expense and record the regulatory liabilities as revenue in the income statement or in AOCI.
At December 31, 2012, regulatory liabilities net of regulatory assets totaled $50 million at TEP and $35 million at UNS Gas. Regulatory assets net of regulatory liabilities totaled $5 million at UNS Electric. We regularly assess whether we can continue to apply regulatory accounting to cost-based rate regulated operations. Expectations of future recovery are generally based on orders issued by regulatory commissions and historical experience. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. See Note 2.
Accounting for Asset Retirement Obligations
TEP
TEP is required to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. TEP incurs legal obligations as a result of environmental and other governmental regulations, contractual agreements and other factors. To estimate the liability, management must use significant judgment and assumptions in: determining whether a legal obligation exists to remove assets; estimating the probability of a future event for a conditional obligation; estimating the fair value of the cost of removal; estimating when final removal will occur; and estimating the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations.
A liability for the fair value of a legal asset retirement obligation (ARO) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to depreciation expense over the useful life of related tangible assets, or when applicable the terms of a lease subject to ARO requirements. Upon retirement of the asset, TEP either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount.
TEP identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations. The land on which these stations reside is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Additionally, TEP entered into ground lease agreements with certain land owners for the installation of photovoltaic (PV) assets. The provisions of the PV ground leases require TEP to remove the PV facilities upon expiration of the leases. The ARO related to the PV assets is estimated to be approximately $9 million at the retirement date. TEP also has certain environmental obligations at the Luna, San Juan, Sundt and Springerville Generating Stations. TEP estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt and Springerville environmental obligations will be approximately $159 million at the retirement dates. No other legal obligations to retire generation plant assets were identified.
TEP has various transmission and distribution lines that operate under leases and rights-of-way that contain end dates and restorative clauses. TEP operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As such, there are no AROs for these assets. However, TEP has identified in its distribution equipment certain AROs for which the accrual amount is less than $1 million at December 31, 2012.
The total net present value of the ARO accrual was $14 million and reported in Deferred Credits and Other Liabilities-Other on the balance sheets at December 31, 2012.
Nevertheless, included in the revenue requirement underlying TEP’s retail electric service rates is a component of depreciation expense intended to enable TEP to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balance of $231 million at December 31, 2012 representing non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, was included in Deferred Credits and Other Liabilities, Regulatory Liabilities - Noncurrent on TEP’s balance sheet See Note 2 for details regarding net cost of removal for interim retirements.
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UNS Gas and UNS Electric
UNS Gas and UNS Electric have various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses. UNS Gas and UNS Electric operate their transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, UNS Gas and UNS Electric are not recognizing the cost of final removal of the transmission and distribution lines in the financial statements.
The net present value of AROs related to the Generation and PV assets of UNS Electric was included in the Deferred Credits and Other Liabilities, Other on UNS Energy’s consolidated balance sheet on December 31, 2012. Both UNS Electric and UNS Gas accrue the future costs of retiring assets, for which no legal obligation exist through their own rate recovery mechanisms. The total accumulated balance of $36 million including UNS Electric’s and UNS Gas’ non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, was reported in Deferred Credits and Other Liabilities, Regulatory Liabilities - Noncurrent on UNS Energy’s consolidated balance sheet on December 31, 2012. See Note 2.
Pension and Other Retiree Benefit Plan Assumptions
TEP, UNS Gas, and UNS Electric record plan assets, obligations, and expenses related to pension and other retiree benefit plans based on actuarial valuations, which include key assumptions on discount rates, expected returns on plan assets, compensation increases, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally recorded or amortized over future periods. We believe that the assumptions used in recording obligations are reasonable based on prior experience, market conditions, and the advice of plan actuaries. Note 9 discusses the rate of return and discount rate used in the calculation of pension plan and other retiree plan obligations for TEP, UNS Gas, and UNS Electric.
TEP is required to recognize the underfunded status of its defined benefit pension and other retiree plans as a liability. The underfunded status is the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated retiree benefit obligation for other retiree benefit plans. As the funded status, discount rates, and actuarial facts change, the liability will vary significantly in future years. TEP records the underfunded amount for its pension and other retiree obligations as a liability and a regulatory asset to reflect expected recovery of pension and other retiree obligations through the rates charged to retail customers.
At December 31, 2012, TEP discounted its future pension plan obligations at 4.1% and its other retiree plan obligations at a rate of 3.8%. The discount rate for future pension plan and other retiree plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point change in the discount rate would increase or decrease the Projected Benefit Obligation (PBO) by approximately $12 million and the 2013 plan expense by $1 million. For TEP’s other retiree benefit plan, a 25-basis point change in the discount rate would increase or decrease the Accumulated Postretirement Benefit Obligation (APBO) by approximately $2 million. A 25-basis point change in the discount rate would impact plan expense by $1 million.
TEP calculates the market-related value of pension plan assets using the fair value of the assets on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2012. In establishing its assumption as to the expected return on assets, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. Pension expense decreases as the expected rate of return on assets increases. A 25-basis point change in the expected return on assets would impact pension expense in 2013 by $1 million.
TEP used a current year health care cost trend rate of 6.9% in valuing its retiree benefit obligation at December 31, 2012. This rate reflects both market conditions and historical experience. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage point change in assumed health care cost trend rates would change the retiree benefit obligation by approximately $5 million and the related plan expense in 2013 by $1 million.
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In 2013, TEP will incur pension costs of approximately $14 million and other retiree benefit costs of approximately $6 million. TEP expects to charge approximately $15 million of these costs to O&M expense, $4 million to capital, and $1 million to Other Expense. TEP expects to make pension plan contributions of $22 million in 2013. In 2009, TEP established a VEBA trust to fund its other retiree benefit plan. In 2013, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $4 million and contributions to the VEBA trust of $3 million.
UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 4.3% at December 31, 2012. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2013 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2013, of which less than $1 million will be capitalized. UNS Gas and UNS Electric expect to make combined pension plan contributions of $2 million in 2013.
UNS Gas and UNS Electric discounted their other retiree plan obligations using a rate of 3.8% at December 31, 2012. UNS Gas and UNS Electric will record retiree medical benefit expense and make benefit payments to retirees under the retiree benefit plan of less than $0.5 million in 2013.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP, UNS Gas, and UNS Electric enter into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, or one year, within established limits to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. TEP and UNS Gas enter into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted summer gas purchases.
Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability on the balance sheets of TEP, UNS Gas, and UNS Electric. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC or PGA mechanisms.
The market prices used to determine fair values for TEP’s, UNS Gas’, and UNS Electric’s derivative instruments at December 31, 2012, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP, UNS Gas, and UNS Electric manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.
Interest Rate Swaps
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to LIBOR on the Springerville Common Facilities Lease. As of December 31, 2012, approximately $25 million of variable rate lease debt for the Springerville Common Facilities Lease had been hedged through an interest rate swap agreement through July 1, 2014, and $34 million had been hedged through January 2, 2020. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable-rate IDBs to a fixed rate from September 2009 through September 2014.
In August 2011, UNS Electric entered into an interest rate swap with the effect of converting the variable interest rate for their $30 million term loan to a fixed rate from August 2011 through August 2015. See Note 6.
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Commodity Cash Flow Hedge
TEP hedges the cash flow risk associated with a six-year power wholesale supply agreement using a six-year power purchase swap agreement. Unrealized gains and losses are recorded in AOCI. See Note 1 for additional details regarding cash flow hedges. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk.
Unbilled Revenue
TEP, UNS Gas, and UNS Electric’s retail revenues, which are recognized in the period that electricity or energy is delivered and consumed by customers, include unbilled revenue based on an estimate of MWh/therms delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated MWh/therms delivered to the MWh/therms billed to our retail customers. The excess of estimated MWh/therms delivered over MWh/therms billed is then allocated to the retail customer classes based on estimated usage by each customer class. We then record revenue for each customer class based on the various Retail Rates for each customer class. Due to the seasonal fluctuations of TEP and UNS Electric’s actual load, the unbilled revenue amount increases during the spring and summer and decreases during the fall and winter. Conversely the unbilled revenue amount for UNS Gas sales increases during the fall and winter and decreases during the spring and summer. A provision for uncollectible accounts is recorded as a component of O&M expense.
Plant Asset Depreciable Lives
TEP, UNS Gas, and UNS Electric have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. Useful life of plant assets is further detailed in Note 5. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statements. The ACC approves depreciation rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without ACC approval. For current approved ACC depreciation rates see Note 1. TEP and UNS Electric transmission assets are subject to the jurisdiction of the FERC.
In January 2010, TEP obtained an updated depreciation study which indicated that its transmission assets’ depreciable lives should be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010, which have the effect of reducing depreciation expense by approximately $14 million annually.
Income Taxes
Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate at our balance sheet date.
Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income and deductions as reported in the consolidated tax return.
A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. At December 31, 2012, UNS Energy had a $7 million valuation allowance. The valuation allowances related to unregulated investments’ losses are treated as capital losses for income tax purposes. If UNS Energy incurs additional capital losses in the future, a valuation allowance will be recorded against the deferred tax asset unless management can identify future capital gains to offset the losses. For additional information see Note 8.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board (FASB) issued authoritative guidance that will require entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013 and do not expect this pronouncement to have a material impact on our disclosures.
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The FASB issued authoritative guidance which amends the guidance for impairment testing of indefinite-lived intangible assets. An entity will have the option to perform qualitative analysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative impairment test. We will be required to comply in the first quarter of 2013; however, we do not expect this pronouncement to have a material impact on our financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to comply with renewable resources requirements.
The FASB decided to require new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. This information can be presented parenthetically on the face of the financial statements or in the footnotes. We plan to present this information in a footnote. We will be required to comply in the first quarter of 2013 and do not expect this decision to have a material impact on our financial statements.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UNS Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UNS Energy or TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts”, “projects”, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other parts of this report: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; cyber attacks or challenges to our information security; and the performance of TEP’s generating plants.
ITEM 7A. - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
We are exposed to various forms of market risk. Changes in interest rates, returns on marketable securities, and changes in commodity prices may affect our future financial results.
For additional information concerning risk factors, including market risks, see Safe Harbor for Forward-Looking Statements, above.
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Risk Management Committee
We have a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to the wholesale energy marketing activities of TEP and the fuel and power procurement activities at TEP, UNS Gas, and UNS Electric. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, and generation operations departments of UNS Energy. To limit TEP, UNS Gas, and UNS Electric’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP, UNS Gas, and UNS Electric’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.
Interest Rate Risk
Long-Term Debt
TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. TEP had $215 million at December 31, 2012 in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest rate payable under the indentures for these bonds is 10% for $37 million of variable rate IDBs, and 20% on the remaining $178 million in variable rate IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.17% in 2012 and 0.18% in 2011. The average weekly interest rate ranged from 0.06% to 0.26% in 2012 and 0.05% to 0.34% during 2011. Although short-term interest rates have been relatively low and stable in 2012 and 2011, TEP may still be subject to volatility in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve month period, would result in a decrease in TEP’s pre-tax net income of approximately $2 million.
TEP manages its exposure to variable interest rate risk by entering into interest rate swaps and financing transactions to rebalance its mix of variable rate and fixed rate long-term debt.
TEP has fixed-for-floating interest rate swaps in place to hedge floating rate interest rate risk associated with $59 million of Springerville Common Facilities lease debt and $50 million of its variable rate IDBs. TEP also entered into the following transactions to change its mix of fixed and floating rate debt.
• TEP issued $250 million of 5.15% fixed-rate unsecured notes in 2011, and used a portion of the proceeds to repurchase $150 million of variable rate IDBs to hold in treasury.
• In 2010, TEP converted the interest rate on $130 million of IDBs from a variable rate to a fixed rate of 5.75% through maturity in 2029.
As a result of these transactions, TEP’s un-hedged variable rate debt comprised approximately 13% of its total long-term debt at December 31, 2012 and 15% at December 31, 2011.
In August 2011, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount through August 2015 to hedge the interest rate risk associated with its $30 million credit agreement.
Interest Rate Swaps
To adjust the value of TEP’s interest rate swaps, classified as cash flow hedges, to fair value in Other Comprehensive Income (Loss), TEP recorded the following net unrealized gains (losses):
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Revolving Credit Facilities
UNS Energy, TEP, UNS Gas, and UNS Electric are also subject to interest rate risk resulting from changes in interest rates on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on the basis of a spread over LIBOR or an Alternate Base Rate. As a result, UNS Energy, TEP, UNS Gas, and UNS Electric may experience significant volatility in the rates paid on LIBOR borrowings under their revolving credit facilities.
Marketable Securities Risk
UNS Energy has a short-term investment policy which governs the investment of excess cash balances by UNS Energy and its subsidiaries. We review this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio. As of December 31, 2012, UNS Energy’s short-term investments consisted of liquid, highly-rated money market funds and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the balance sheet.
TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $32 million at December 31, 2012, and $50 million at December 31, 2011. At December 31, 2012, the carrying value exceeded fair value by $13 million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future rates charged to retail customers. At December 31, 2011, the fair value exceeded the carrying value by $16 million. These securities represent TEP’s investments in lease debt and equity underlying certain of TEP’s capital lease obligations. Changes in the fair value of such debt securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity.
Commodity Price Risk
TEP
TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, and coal. This risk is mitigated through a PPFAC mechanism which fully recovers the actual retail fuel and purchased power costs incurred on a timely basis from TEP’s retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, TEP is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference.
Purchases and Sales of Energy
To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future delivery period. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified market approach to provide a balance between long-term, mid-term, and spot energy sales. TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve requirements, and account for other contracts and resource contingencies. TEP also enters into limited forward purchases and sales to optimize its resource portfolio and take advantage of geographical differences in price. These positions are managed on both a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk Management Committee. For example, the risk management policies provide that TEP should not take a short physical position in the third quarter and must have owned generation backing up all physical forward sales positions at the time the sale is made. TEP’s risk management policies also restrict entering into forward positions with maturities extending beyond the end of the next calendar year except for approved hedging purposes.
TEP’s risk management policies also allow for financial purchases and sales of energy subject to specified risk parameters established and monitored by the Risk Management Committee. These include financial trades in a futures account on an exchange, with the intent of optimizing market opportunities.
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TEP enters into forward contracts considered to be “normal purchases and sales” of electric energy and are therefore not accounted for as derivatives. TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered. TEP also enters into forward contracts that are not considered to be “normal purchases and sales” and therefore are accounted for as derivatives. When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other Southwestern U.S. trading hubs. TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market.
Long-Term Wholesale Sales
Prior to June 1, 2011, under the terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 1, 2011 to December 31, 2011, SRP was required to purchase 73,000 MWh per month. From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on the Palo Verde Market Index. As of February 13, 2013, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2013 was $36 per MWh.
The chart below summarizes the annual change in pre-tax income if the market price of on-peak power on the Palo Verde Market Index changes by $5 per MWh.
Natural Gas
TEP is also subject to commodity price risk from changes in the price of natural gas. In addition to energy from its coal-fired facilities, TEP typically uses power purchases, supplemented by generation from its gas-fired units to meet the summer peak demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are price indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed power purchases, and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.
As required by fair value accounting rules, for the year ended December 31, 2012, TEP considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for TEP was less than $0.5 million at December 31, 2012.
To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, TEP recorded the following net unrealized gains (losses):
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The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts.
Sensitivity Analysis of Derivatives
TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. TEP records unrealized gains and losses as either a regulatory asset or regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%.
Coal
TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants.
In 2003, TEP amended and extended the long-term coal supply contract for Springerville Units 1 and 2 through 2020 and expects coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives. During the extension period from 2011 through 2020, the coal price is determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling. This range would be from $19.30 to $26.15 per ton.
TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for Sundt Unit 4 on the spot market and can supply that unit with natural gas when the price is competitive with coal. Coal burned at Sundt Unit 4 represents less than 10% of TEP’s total coal consumption. In December 2011, the take-or-pay obligations under a coal transportation agreement previously effective through December 2015 were terminated. As a result, TEP was relieved of a $4 million obligation recognized under this contract in December 2010. TEP reversed a $4 million regulatory asset.
TEP also participates in jointly-owned generating facilities at Four Corners, Navajo, and San Juan, where coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations.
The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an estimated average annual cost of $21 million for the next five years. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations and Note 4.
UNS Gas
UNS Gas is subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its customers. This risk is mitigated through the PGA mechanism which provides an adjustment to UNS Gas’ Retail Rates to recover the actual costs of gas and transportation. UNS Gas further reduces this risk by purchasing forward fixed price contracts or entering into financial gas swaps for a portion of its projected gas needs under its Price Stabilization Plan. UNS Gas purchases at least 45% of its estimated gas needs in this manner.
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As required by fair value accounting rules, for the year ended December 31, 2012, UNS Gas considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Gas was less than $0.5 million at December 31, 2012.
To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, UNS Gas recorded the following net unrealized gains (losses):
For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $2 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $2 million.
UNS Electric
UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated through a PPFAC mechanism which allows for the recovery of costs from retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, UNS Electric is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference.
UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. Because a portion of the costs under these contracts will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under these new contracts on a timely basis.
For UNS Electric’s forward power sales and purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $5 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $5 million.
UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchased power agreements with fixed price contracts. In addition, UNS Electric hedges a portion of its anticipated natural gas exposure from plant fuel. UNS Electric currently has approximately 45% of this aggregate summer exposure hedged for the summer of 2013. UNS Electric will satisfy its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets.
As required by fair value accounting rules, for the year ended December 31, 2012, UNS Electric considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Electric was less than $0.5 million at December 31, 2012.
To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, UNS Electric recorded the following net unrealized gains (losses):
For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $1 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $1 million.
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Credit Risk
UNS Energy is exposed to credit risk in its energy-related marketing activities related to potential non-performance by counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. We calculate counterparty credit exposure by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. A positive number means that we are exposed to the creditworthiness of our counterparties. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or a letter of credit. Conversely, a negative exposure means that a counterparty is exposed to the creditworthiness of TEP, UNS Gas, or UNS Electric. If such exposure exceeds credit limits or collateral thresholds, we may be required to post collateral in the form of cash or LOCs.
TEP, UNS Gas, and UNS Electric each have entered into short-term and long-term transactions with several financial institution counterparties with terms of one month through five years. As of December 31, 2012, the combined credit exposure to TEP, UNS Gas, and UNS Electric from financial institution counterparties was approximately $3 million.
As of December 31, 2012, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $15 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $3 million. TEP’s total exposure to non-investment grade counterparties was $3 million.
At December 31, 2012, TEP posted no cash collateral and less than $1 million in LOCs as credit enhancements with its counterparties, and did not hold any collateral from its counterparties.
UNS Gas is subject to credit risk from non-performance by its supply and hedging counterparties to the extent that these contracts have a mark-to-market value in favor of UNS Gas. As of December 31, 2012, UNS Gas had purchased under fixed price contracts approximately 30% of its expected consumption for the 2013/2014 winter season. At December 31, 2012, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts. As of December 31, 2012, UNS Gas had posted no cash collateral and no LOCs as credit enhancements with its counterparties, and did not hold any collateral from counterparties.
UNS Electric enters into energy purchase agreements as well as gas hedging contracts to hedge the risk in its gas-indexed power purchase agreements. To the extent that such contracts have a positive mark-to-market value, UNS Electric is exposed to credit risk under those contracts. At December 31, 2012, UNS Electric had less than $1 million in credit exposure under such contracts. As of December 31, 2012, UNS Electric had posted less than $1 million in LOCs and no cash collateral as credit enhancements with its counterparties, and had not collected any collateral margin from its counterparties.
ITEM 8.
ITEM 8. - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
UNS Energy-Management’s Report on Internal Controls Over Financial Reporting
UNS Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.
Based on management’s assessment using those criteria management has concluded that, as of December 31, 2012, UNS Energy’s internal control over financial reporting was effective.
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The effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report in Item 8 of this Annual Report on Form 10-K.
Tucson Electric Power Company-Management’s Report on Internal Controls Over Financial Reporting
TEP’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of TEP’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the COSO Internal Control - Integrated Framework.
Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2012, TEP’s internal control over financial reporting was effective.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
UNS Energy Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of UNS Energy Corporation and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Phoenix, Arizona
February 26,
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of
Tucson Electric Power Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Phoenix, Arizona
February 26,
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UNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
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UNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
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UNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Note 15 for supplemental cash flow information.
See Notes to Consolidated Financial Statements.
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UNS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
(Consolidated Balance Sheets Continued)
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UNS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
(Consolidated Balance Sheets Concluded)
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UNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
See Notes to Consolidated Financial Statements.
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UNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
* UNS Energy has 75 million authorized shares of Common Stock.
We describe limitations on our ability to pay dividends in Note 7.
See Notes to Consolidated Financial Statements.
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Note 15 for supplemental cash flow information.
See Notes to Consolidated Financial Statements.
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
(Consolidated Balance Sheets Continued)
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TUCSON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
(Consolidated Balance Sheets Concluded)
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
See Notes to Consolidated Financial Statements.
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TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
We describe limitations on our ability to pay dividends in Note 7.
See Notes to Consolidated Financial Statements.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP generates, transmits and distributes electricity to approximately 406,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).
UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits and distributes electricity to approximately 92,000 retail customers in Mohave and Santa Cruz counties.
UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2012.
Our business is comprised of three reporting segments - TEP, UNS Gas, and UNS Electric.
References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS
In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts, which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012 as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011 and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 17 for the quarterly impact of the revisions on the years presented. The interim financial data is unaudited. The revisions noted above impacted UNS Energy’s statements of income as shown in the tables below:
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(1) Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board issued authoritative guidance that eliminated the option to report other comprehensive income in the statement of changes in equity. Rather, an entity must elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive statements. In 2012, we elected to include two separate but consecutive statements.
We implemented accounting guidance in 2012 which enhances our disclosures regarding unobservable inputs in calculating the fair market value of certain assets and liabilities. The guidance requires additional quantitative analysis of inputs when we use significant unobservable inputs to measure the fair value of our derivatives and financial instruments. See Note 11.
BASIS OF PRESENTATION
We consolidate our investments in subsidiaries when we hold a majority of the voting stock and we can exercise control over the operations and policies of the company. Consolidation means accounts of the parent and subsidiary are combined and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 2.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
USE OF ACCOUNTING ESTIMATES
Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles (GAAP) in the United States. These estimates and assumptions affect:
• Assets and liabilities on our balance sheets at the dates of the financial statements;
• Our disclosures about contingent assets and liabilities at the dates of the financial statements; and
• Our revenues and expenses in our income statements during the periods presented.
Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.
ACCOUNTING FOR RATE REGULATION
We generally use the same accounting policies and practices used by unregulated companies. However, sometimes GAAP requires that rate-regulated companies apply special accounting treatment to show the effect of rate regulation. For example, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers. Our Retail Rates are designed to allow TEP, UNS Gas, and UNS Electric an opportunity to recover reasonable operating and capital costs and earn a return on utility plant in service. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through billing reductions. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings.
TEP, UNS Gas, and UNS Electric apply regulatory accounting as the following conditions exist:
• An independent regulator sets rates;
• The regulator sets the rates to recover the specific enterprise’s costs of providing service; and
• Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.
CASH AND CASH EQUIVALENTS
We define Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with an original maturity of three months or less.
As of December 31, 2012, we include $7 million of restricted cash in Investments and Other Property-Other on the balance sheets, of which $2 million has been legally restricted as to its use. At December 31, 2011, we included $9 million of restricted cash in Investments and Other Property - Other on the balance sheets, of which $3 million had been legally restricted as to its use.
UTILITY PLANT
Utility Plant includes the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC).
We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statements as costs are incurred.
When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
AFUDC and Capitalized Interest
AFUDC reflects the cost of debt or equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts capitalized are included in rate base for establishing Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt reduces Other Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.
The average AFUDC rates on regulated construction expenditures are included in the table below:
UNS Energy did not capitalize interest in 2012. UNS Energy capitalized interest at a rate of 3.30% for 2011 and 1.96% for 2010.
Depreciation
We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and reflect estimated removal costs, net of estimated salvage value for interim retirements. Below are the summarized average annual depreciation rates for all utility plant, which reflect immaterial adjustments in the calculation of rates in the years presented to exclude allocated depreciation (the adjustment did not affect Depreciation Expense recorded in the income statements).
Computer Software Costs
We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.
TEP Utility Plant Under Capital Leases
TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense-Capital Leases. The lease terms are described in Note 6.
INVESTMENTS IN LEASE DEBT AND EQUITY
TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a one-half interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 11. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.
TEP accounts for its equity interest in the Springerville Unit 1 Lease trust using the equity method.
K-99
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
JOINTLY-OWNED FACILITIES
TEP has investments in several generation and transmission facilities jointly-owned with other companies. These projects are accounted for on a proportionate consolidation basis based on our ownership percentage. See Note 5.
ASSET RETIREMENT OBLIGATIONS
TEP and UNS Electric record a liability for the estimated present value of a conditional Asset Retirement Obligation (ARO) as follows:
• When it is able to reasonably estimate the fair value of any future obligation to retire as a result of an existing or enacted law, statute, ordinance, or contract; or
• If it can reasonably estimate the fair value.
When the liability is initially recorded at net present value, TEP and UNS Electric capitalize the cost by increasing the carrying amount of the related long-lived asset. TEP and UNS Electric adjust the liability to its present value by recognizing accretion expense in O&M expense, and the capitalized cost is depreciated in Depreciation and Amortization expense over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements.
Based on the decommissioning studies to estimate timing and amount of future retirement of certain generation assets, both TEP and UNS Electric record legal AROs for these assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases.
TEP and UNS Electric record cost of removal for generation assets that are recoverable through the rates charged to retail customers. See Note 2.
We record cost of removal for transmission and distribution assets through depreciation rates and recover those amounts in the rates charged to retail customers. There are no legal obligations associated with transmission and distribution assets. We have recorded an obligation for estimated costs of removal as regulatory liabilities.
EVALUATION OF ASSETS FOR IMPAIRMENT
We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.
DEFERRED FINANCING COSTS
We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.
UTILITY OPERATING REVENUES
We record utility operating revenues when services or commodities are delivered to customers. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period.
We determine amounts delivered through periodic readings of customer meters. At the end of the month, the usage since the last meter reading is estimated and the corresponding unbilled revenue is calculated. Unbilled revenue is estimated based on daily generation or purchased volumes, estimated usage by customer class, estimated line losses, and estimated average customer Retail Rates. Accrued unbilled revenues are reversed the following month when actual billings occur. The accuracy of the unbilled revenue estimate is affected by factors that include fluctuations in energy demands, weather, line losses, customer Retail Rates, and changes in the composition of customer classes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The ACC authorized a rate-adjustment mechanism for TEP, UNS Gas, and UNS Electric that provides for the recovery of actual fuel, transmission, and purchased power/energy cost. The revenue surcharge or surcredit adjusts the customers’ retail rate for delivered electricity or gas to collect or return under- or over-recovered energy costs. The ACC revises these rate-adjustment mechanisms periodically (annually for TEP and UNS Electric; monthly for UNS Gas) and may increase or decrease the costs recovered through Retail Rates for any difference between the total amount collected under the mechanisms and the recoverable costs incurred. See Note 2.
Arizona’s mandatory Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy and allows recovery of compliance costs through a RES surcharge to customers. We charge customers a Demand Side Management (DSM) surcharge to recover the cost of ACC-approved Electric Energy Efficiency Programs (Electric EE Programs) or Gas Energy Efficiency Programs (Gas EE Programs). We defer differences between actual RES or DSM qualified costs incurred and the recovery of such costs from retail customers through the RES and DSM surcharges. Cost over-recoveries (the excess of cost recoveries through the RES and DSM surcharges over actual qualified costs incurred) are deferred as regulatory liabilities and cost under-recoveries (the excess of actual qualified costs incurred over cost recoveries through the RES and DSM surcharges) are deferred as regulatory assets. The surcharges typically reset annually and incorporate an adjustor mechanism that, upon approval of the ACC, allows us to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s RES or DSM surcharge. See Note 2.
For purchased power and wholesale sales contracts that are not settled with energy, TEP and UNS Electric net the sales contracts with the purchase power contracts and reflect the net amount as Electric Wholesale Sales. The corresponding cash receipts are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales, while cash payments are recorded as Purchased Energy/Power Costs Paid.
We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. We refer uncollected accounts to external collection agencies after 90 days.
TEP earns and recognizes Other Revenues monthly as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Tri-State and SRP reimburse TEP for various operating expenses at Springerville, which are recorded in the respective line item of the income statements based on the nature of service or materials provided. Tri-State and SRP also pay TEP for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities which are recorded as Other Revenues.
INVENTORY
Materials and Supplies consist of transmission, distribution, and generation construction and repair materials. We record fuel, materials, and supply inventories at the lower of weighted average cost or market prices. We capitalize handling and procurement costs (such as materials, labor, overhead costs, and transportation costs) as part of the cost of the inventory.
RECOVERY OF FUEL AND PURCHASED ENERGY COSTS
TEP and UNS Electric Purchased Power and Fuel Adjustment Clause
TEP and UNS Electric record the actual fuel, transmission, and purchased power costs incurred on a monthly basis. Retail customers are billed monthly for the cost of fuel, transmission, and purchased power in Base Rates and via the current Purchased Power and Fuel Adjustment Clause (PPFAC) rate. The difference between the costs billed to customers (recoveries) and actual fuel costs incurred to provide retail electric service is deferred. Cost over-recoveries (excess of fuel cost recoveries) are deferred as regulatory liabilities and cost under-recoveries (excess of actual costs incurred over fuel costs recovered) are deferred as regulatory assets. See Note 2.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
UNS Gas Purchased Gas Adjustor
UNS Gas defers the difference between actual gas costs incurred and the recovery of such costs under a Purchased Gas Adjustor (PGA) mechanism. Gas cost over-recoveries (the excess of gas costs recovered under the PGA mechanism over actual gas costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of actual gas costs incurred over gas costs recovered via the PGA mechanism) are deferred as regulatory assets. See Note 2.
RENEWABLE ENERGY CREDITS
The ACC uses Renewable Energy Credits (RECs) to measure compliance with the RES requirements. A REC equals one kWh generated from renewable resources. The cost of REC purchases are qualified renewable expenditures recoverable through the RES surcharge. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power is the REC cost and the remaining cost is recoverable through the PPFAC.
When RECs are purchased, TEP and UNS Electric record the cost of the unretired RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount, in the income statements. See Note 2.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.
Tax benefits are recognized as reductions to Deferred Income Taxes - Noncurrent/Other Current Liabilities when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Tax benefits taken on returns which do not meet these requirements are recorded in Deferred Income Taxes - Noncurrent/Other Liabilities - Noncurrent. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.
Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets - Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 2.
We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated in 2012 are deferred as Regulatory Liabilities - Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.
Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TAXES OTHER THAN INCOME TAXES
We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable, on the balance sheet, to governmental agencies for these taxes and assessments. These amounts are not reflected in the income statements.
DERIVATIVE FINANCIAL INSTRUMENTS
Risks and Overview
We are exposed to energy price risk associated with gas and purchased power requirements, volumetric risk associated with seasonal load, and operational risk associated with power plants, transmission, and transportation systems. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability, ensuring we can meet load and reserve requirements, and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.
We present cash collateral and derivative assets and liabilities associated with the same counterparty separately in our financial statements, and we separate all derivatives into current and long-term portions on the balance sheet.
In 2010 through 2012, we did not engage in trading of derivative financial instruments.
Cash Flow Hedges
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements relating to the Springerville Unit 1 Leases and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a six-year power supply agreement using a six-year power purchase swap agreement. UNS Electric entered into a cash flow hedge in August 2011 to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:
•
The effective portion of the changes in the fair value of the interest rate swaps and TEP’s six-year power purchase swap agreement are recorded in Accumulated Other Comprehensive Income (AOCI) and the ineffective portion, if any, is recognized in earnings; and
•
When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the changes in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.
We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items. We discontinue hedge accounting when: (1) the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (2) the derivative expires or is sold, terminated, or exercised; (3) it is no longer probable that the forecasted transaction will occur; or (4) we determine that designating the derivative as a hedging instrument is no longer appropriate.
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Subsequent Measurement at Fair Value
•
TEP
TEP’s hedges, such as forward power purchase contracts indexed to gas, short-term forward power sales contracts, or call and put options (gas collars), that did not qualify for either cash flow hedge accounting treatment or the normal scope exception are considered transactions subsequently measured at fair value. TEP hedges a portion of its monthly natural gas exposure for plant fuel, gas-indexed purchased power, and spot market purchases with fixed price contracts for a maximum of three years. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC.
•
UNS Gas
UNS Gas enters into derivative contracts such as forward gas purchases and gas swaps, creating price stability and reducing exposure to natural gas price volatility that may result in delayed recovery under the PGA. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the PGA mechanism permits the recovery of the cost of hedging contracts.
•
UNS Electric
UNS Electric hedges a portion of its purchased power exposure to fixed price and natural gas-indexed contracts with forward power purchases, financial gas swaps, and call and put options. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the PPFAC mechanism allows recovery of the prudent costs of contracts for hedging fuel and purchased power costs.
Normal Purchases and Normal Sales
We enter into forward energy purchase and sales contracts, including call options, with counterparties for load serving requirements or counterparties with generating capacity to support our current load forecasts. These contracts are not required to be measured at fair value and are accounted for on an accrual basis. We evaluate our counterparties on an ongoing basis for non-performance risk to ensure it does not impact our ability to obtain the normal purchases and normal sales scope exception.
PENSION AND OTHER RETIREE BENEFITS
We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on employees’ years of service and average compensation. We also maintain a Supplemental Executive Retirement Plan (SERP) for upper management. TEP also provides limited health care and life insurance benefits for retirees. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.
We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers, and expect to recover these costs over the estimated service lives of employees.
Additionally, we provide supplemental retirement benefits to certain employees whose benefits are subject to IRS benefit or compensation limitations. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and other retiree benefit expense are determined by actuarial valuations, based on assumptions that we evaluate annually. See Note 9.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RECLASSIFICATIONS
UNS Energy and TEP reclassified the following items in the 2011 and 2010 financial statements to be comparable to the presentation in the 2012 financial statements:
•
UNS Energy reclassified $4 million of 2011 trade receivables with credit balances from Accounts Receivable - Customer to Other Current Liabilities;
•
UNS Energy and TEP reclassified $4 million of 2011 and 2010 O&M costs paid from Fuel Costs Paid to Payment of Operations and Maintenance Costs in the statements of cash flows;
•
TEP reclassified $2 million of 2011 trade receivables with credit balances from Accounts Receivable - Customer to Other Current Liabilities;
•
UNS Energy and TEP reclassified $1 million of 2011 payroll withholding taxes from Other Current Liabilities to Accrued Employee Expenses; and
•
UNS Energy and TEP reclassified $35 thousand from Taxes Other Than Income Taxes to Other Expense in the 2011 income statement to conform to current year presentation.
NOTE 2. REGULATORY MATTERS
RATES AND REGULATION
The ACC and the FERC each regulate portions of the utility accounting practices and rates used by TEP, UNS Gas, and UNS Electric. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, and transactions with affiliated parties. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
TEP Rates
TEP 2008 Rate Order
The 2008 TEP Rate Order, issued by the ACC and effective December 1, 2008, provided an average base rate increase of 6% over TEP’s previous Base Rates; an 8% authorized rate of return on Original Cost Rate Base (OCRB) of approximately $1 billion; a 5.6% rate of return on Fair Value Rate Base (FVRB) of approximately $1.5 billion, which did not include a return on the fair value increment of rate base (the fair value increment of rate base represents the difference between the OCRB and FVRB). The ACC authorized a fuel rate included in Base Rates of 2.9 cents per kilowatt-hour (kWh); a PPFAC effective January 1, 2009; and a base rate increase moratorium through January 1, 2013.
Pending TEP Rate Case
In July 2012, TEP filed a general rate case, on a cost-of-service basis, with the ACC requesting a Base Rate increase of approximately 15% to cover a revenue deficiency of $128 million. TEP requested a 7.74% return on an OCRB of $1.5 billion and a 5.68% return on FVRB of $2.3 billion. The return on FVRB includes a 1.56% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million).
TEP requested a Lost Fixed Cost Recovery (LFCR) mechanism to recover non-fuel costs that would go unrecovered due to lost kilowatt-hour (kWh) sales as a result of implementing the ACC’s Electric Energy Efficiency Standards (Electric EE Standards) and the RES. TEP also requested a mechanism, which would be adjusted annually, to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases.
TEP proposed a three-year pilot program allowing for investment in Electric EE Programs to meet the Electric EE Standards in the most cost effective manner. Under TEP’s proposal, energy efficiency investments would be considered regulatory assets and amortized over a four-year period. TEP would earn a return on investment and recover the return and amortization expense through the existing DSM surcharge.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In February 2013, TEP, ACC Staff, and other parties to TEP’s pending rate case proceeding entered into a proposed settlement agreement. The proposed settlement agreement requires the approval of the ACC before new rates can become effective.
UNS Gas Rates
2012 UNS Gas Rate Order
In April 2012, the ACC approved a Base Rate increase of $2.7 million, or 1.8%, and a mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the ACC’s Gas Energy Efficiency Standards (Gas EE Standards). UNS Gas recognized less than $0.1 million of revenue under the LFCR in 2012.
The ACC approved an authorized rate of return of 8.3% on an OCRB of $183 million, and a 1.0% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million). The new rates became effective in May 2012.
UNS Electric Rates
2010 UNS Electric Rate Order
In September 2010, the ACC approved a base rate increase of $7 million, or 4%, including an 8.3% authorized rate of return on an OCRB of $169 million, and a 1.3% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $73 million). The order also authorized new depreciation rates, effective October 2010.
In July 2011, UNS Electric completed the ACC and the FERC approved purchase of BMGS from UED for $63 million, UED’s book value for the assets. BMGS was included in UNS Electric’s Rate Base through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to non-fuel Base Rates.
Pending UNS Electric Rate Case
In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting a non-fuel Base Rate increase of $7.5 million, or 4.6%. UNS Electric requested a rate of return of 8.4% on an OCRB of approximately $217 million and a 6.7% rate of return on a FVRB of $286 million. The return on FVRB includes a 1.6% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $69 million).
UNS Electric requested a LFCR mechanism to recover non-fuel costs that would go unrecovered due to lost kWh sales as a result of implementing Electric EE Standards and the RES. In addition to the LFCR mechanism, UNS Electric requested a Transmission Cost Adjustor (TCA). The TCA is designed to track changes to UNS Electric’s FERC approved Open Access Transmission Tariff (OATT) rate which is updated annually and would allow UNS Electric to recover transmission costs in a timely manner.
COST RECOVERY MECHANISMS
TEP, UNS Gas, and UNS Electric have received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
The PPFAC provides for the adjustment of Retail Rates to reflect variations in retail fuel, transmission, and purchased power costs, including demand charges, and the prudent costs of contracts for hedging fuel. TEP and UNS Electric record deferrals for recovery or refund to the extent actual retail fuel, transmission, and purchased power costs vary from the fuel rate and current PPFAC rates. The TEP PPFAC became effective in January 2009. A PPFAC rate adjustment is made annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period automatically unless suspended by the ACC. UNS Electric’s PPFAC rate adjustment is made annually each June 1st, effective for the subsequent 12-month period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The PPFAC rate includes: 1) a forward component, under which TEP and UNS Electric recover or refund differences between, a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and, b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.
The table below summarizes TEP’s and UNS Electric’s PPFAC rates in cents per kWh that are compared against actual fuel cost to create regulatory assets or liabilities:
(1) Competition Transition Charge
As part of the TEP 2008 Rate Order, TEP was required to credit previously collected revenues to customers through the PPFAC. As a result, the PPFAC charge had been zero since it became effective in January 2009. In November 2011, the Fixed CTC revenue was fully refunded to customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate was approved by the ACC in April 2012.
UNS Gas Purchased Gas Adjustor
The PGA mechanism allows UNS Gas to adjust Retail Rates to reflect variations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed-to-customer basis. In 2012, the ACC approved a PGA temporary surcredit of 4.5 cents per therm effective for the period from May 2012 through April 2014, or when the PGA balance reaches zero, whichever comes first. At December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis, an increase of $2 million from December 31, 2011.
The PGA rate ranged from $0.5202 to $0.6501 cents per therm in 2012, and ranged from $0.6593 to $0.7296 cents per therm in 2011.
RES and Energy Efficiency Standards
The ACC has a mandatory RES that requires TEP and UNS Electric to expand their use of renewable energy through efforts funded by customer surcharges. TEP and UNS Electric are required to file five-year implementation plans with the ACC and annually seek approval for the upcoming year’s RES funding amount. Similarly, TEP, UNS Gas, and UNS Electric recover the cost of ACC-approved energy efficiency programs through DSM surcharges established by the ACC.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table shows RES and DSM tariffs collected:
Renewable Energy Standard
The following table summarizes TEP’s authorized 2010-2012 RES programs:
(1) The authorized program budget for 2010 includes $12 million in carryforward of 2008 and 2009 RES funds.
(2) TEP met the 2012 renewable energy target of 3.5%.
The funding mechanism allows TEP to use RES funds to recover operating costs, depreciation, and property taxes, and to earn a return on company-owned solar projects until the projects can be incorporated in Base Rates.
In January 2013, the ACC approved TEP’s 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2013 on solar investments made in 2010, 2011, and 2012.
The following table summarizes UNS Electric’s authorized 2010-2012 RES programs:
(1) UNS Electric met the 2012 renewable energy target of 3.5%.
UNS Electric will invest up to $5 million per year in company-owned renewable assets (between 2013 and 2014) subject to an annual prudency review and approval by the ACC. UNS Electric will recover the associated operating costs, depreciation, and property taxes under the RES program until the next rate case is filed and the assets are incorporated in the Base Rates.
In January 2013, the ACC approved UNS Electric’s 2013 RES implementation plan. UNS Electric’s will collect approximately $7 million from retail customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on investment to UNS Electric for company-owned solar projects.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEP and UNS Electric entered into multiple ACC-approved long-term purchase power agreements with companies developing renewable energy generation facilities. TEP and UNS Electric are required to purchase the full output of each facility for 20 years. Both utilities are authorized to recover a portion of the cost of renewable energy through the PPFAC, with the balance of costs recoverable through the RES tariff.
Energy Efficiency Standards
In 2010, the ACC approved new Electric EE Standards designed to require TEP and UNS Electric to implement cost-effective DSM programs, effective in 2011. In 2011, the Electric EE Standards targeted total retail kWh savings equal to 1.25% of 2010 sales, increasing to 22% by 2020, and provide for a DSM surcharge to recover the costs to implement DSM programs.
In May 2012, TEP filed a modification to its proposed 2011-2012 Energy Efficiency implementation plan with the ACC. The proposal included a request for a performance incentive for 2012 ranging from approximately $3 million to $4 million and the collection of the performance incentive over a period from October 1, 2012 to December 31, 2012. An administrative law judge issued a recommended opinion and order in August 2012. TEP did not record any income related to the proposed performance incentive in 2012. A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. The proposed settlement agreement requires the ACC’s approval before it becomes effective.
The ACC approved new Gas EE Standards which required UNS Gas to implement cost effective DSM programs to reduce total retail therm sales in 2011, by 701,113 therms, or 0.5% of 2010 sales and to reduce total retail therm sales in 2012 by 1,679,890 therms, or 1.2% of 2011 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.
In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Gas Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Gas Energy Efficiency plan or the subsequent requests.
In January 2012, the ACC granted UNS Electric a waiver from complying with the 2011 and 2012 Electric EE Standards.
In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter.
Lost Fixed Cost Recovery Mechanism
In May 2012, the ACC authorized a mechanism for UNS Gas to recover therm sales lost as a result of implementing programs under the Gas EE Standards. The LFCR mechanism enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards. UNS Gas recorded less than $0.1 million of LFCR revenue in 2012.
Renewable Energy Credits
UNS Electric had $2 million of RECs on December 31, 2012, and $1 million of RECs on December 31, 2011, recorded in Other Assets on the balance sheets. TEP did not have RECs balances at the end of the periods presented since all RECs have been retired for compliance with the RES standard.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Regulatory Assets and Liabilities
The following tables summarize regulatory assets and liabilities:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets and state when we earn a return below:
(1) Property Tax is recovered over an approximate six-month period as costs are paid, rather than as costs are accrued.
(2) Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, as authorized by the ACC. TEP earned a return on this asset and recovered these costs through Retail Rates over a four-year period ended November 2012.
(3) See Cost Recovery Mechanisms discussion above.
(4) TEP’s other assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), and other assets (recovery through 2014). UNS Gas’ other assets consist of rate case costs (recovery over 3 years), and costs of the low income assistance program.
(5) Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.
(6) Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
(7) The Tucson to Nogales Transmission Line regulatory asset does not earn a return. TEP and UNS Electric will request recovery from FERC for the prudent cost incurred to develop a high-voltage transmission line, which we expect to abandon. See Note 4.
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Regulatory liabilities represent items that we either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers, as described below:
(8) See Cost Recovery Mechanisms discussion above.
(9) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future AROs net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, general, and intangible plant which are not yet expended. TEP and UNS Electric have also collected amounts for generation plant, which they have not yet expended.
(10) The Deferred Investment Tax Credit is related to federal energy credits generated in 2012 and are deferred as Regulatory Liabilities - Noncurrent and amortized over the tax life of the underlying asset.
Income Statement Impact of Applying Regulatory Accounting
Regulatory accounting had the following effects on TEP’s net income:
Had UNS Gas and UNS Electric not applied regulatory accounting each would have recognized the difference between expected and actual purchased energy costs and commodity derivative unrealized gains or losses as a change in income statement expense, rather than as a change in regulatory balances. Regulatory accounting had the following effects on UNS Gas’ and UNS Electric’s net income:
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Future Implications of Discontinuing Application of Regulatory Accounting
We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and we have concluded regulatory accounting is applicable. If we stopped applying regulatory accounting to our regulated operations, the following would occur:
•
Regulatory pension assets would be reflected in AOCI;
•
We would write off remaining regulatory assets as an expense and regulatory liabilities as income in the income statements;
•
At December 31, 2012, based on the regulatory assets balances, net of regulatory liabilities:
•
TEP would have recorded an extraordinary after-tax gain of $48 million and an after-tax loss in AOCI of $78 million;
•
UNS Gas would have recorded an extraordinary after-tax loss of $19 million and an after-tax loss in AOCI of $3 million; and
•
UNS Electric would have recorded an extraordinary after-tax gain of $6 million and an after-tax loss in AOCI of $3 million.
While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped applying regulatory accounting to our regulated operations.
NOTE 3. SEGMENT AND RELATED INFORMATION
We have three reportable segments that are determined based on the way we organize our operations and evaluate performance:
(1) TEP, a regulated electric utility business, is our largest subsidiary;
(2) UNS Gas is a regulated gas distribution utility business; and
(3) UNS Electric is a regulated electric utility business.
Results for the UNS Energy and UES holding companies, Millennium, and UED are included in Other below.
We disclose selected financial data for our reportable segments in the following tables:
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(1) The amounts previously reported have been revised.
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Reconciling adjustments consist of the elimination of intersegment revenue resulting from the following transactions, which are eliminated in consolidation:
(1) TEP and UNS Electric sell power to each other at third-party market prices.
(2) UNS Gas provides gas to TEP for generation of power at third-party market prices.
(3) Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
(4) Millennium provides a supplemental workforce and meter-reading services to TEP, UNS Gas, and UNS Electric. Amounts are based on costs of services performed and management believes that the charges for services are reasonable. Millennium charged TEP $17 million in 2012 and 2011, and $16 million in 2010 for these services.
(5) TEP charged UNS Electric for control area services based on a FERC-approved tariff.
TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UNS Energy affiliated entities. Costs are directly assigned to the benefiting entity. Direct costs charged by TEP to affiliates were $10 million in 2012, 2011, and 2010.
UNS Energy incurs corporate costs that are allocated to TEP and its other subsidiaries. Corporate costs are allocated based on a weighted-average of three factors: assets, payroll, and revenues. Management believes this method of allocation is reasonable and approximates the cost that TEP would have incurred as a standalone entity. Charges allocated to TEP were $2 million in 2012 and 2011, and $3 million in 2010.
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Other
Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UNS Energy and reclassifications of deferred tax assets and liabilities.
NOTE 4. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
TEP COMMITMENTS
Firm Purchase Commitments
At December 31, 2012, TEP had the following firm non-cancelable purchase commitments (minimum purchase obligations) and operating leases:
Fuel, Purchased Power, and Transmission Contracts
TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2020. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements.
TEP has agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in various years between 2013 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2012.
Additionally, Purchased Power includes six 20-year Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011 and 2012. TEP is obligated to purchase 100% of the output from these facilities. TEP has additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational.
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Fuel, purchased power, and transmission costs are recoverable from customers through the PPFAC. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2.
RES Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2.
Solar Equipment
TEP committed to purchase 9 MW of photovoltaic equipment through December 2013. TEP spent $11 million in 2012 and $10 million in 2011 under this contract. The ACC approved this purchase under TEP’s RES implementation plan. TEP earns a return on investment in company-owned solar projects. See Note 2.
Operating Leases
TEP’s aggregate operating lease expense is primarily for rail cars, office facilities, and computer equipment, with varying terms, provisions, and expiration dates. This expense totaled $2 million in each of 2012, 2011, and 2010.
Service Agreement
In February 2012, TEP entered into a long-term agreement for information technology services. TEP is obligated to pay $2 million per year through December 2014.
UNS GAS AND UNS ELECTRIC COMMITMENTS
At December 31, 2012, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below:
UNS Gas purchases gas from various suppliers at market prices. However, UNS Gas’ risk of loss due to increased costs (as a result of changes in market prices of fuel) is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas’ forward gas purchase agreements expire through 2015. Certain of these contracts are at a fixed price per Million British Thermal Units (MMBtu) and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2012. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2013 and 2024.
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At December 31, 2012, UNS Electric had various firm non-cancelable purchase commitments as described in the table below:
UNS Electric enters into agreements with various energy suppliers for purchased power at market prices to meet its energy requirements. In general, these contracts provide for capacity payments and energy payments based on actual power taken. These contracts expire in various years through 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2012. Purchased power commitments also include two 20-year PPAs with renewable energy generation facilities that achieved commercial operation in 2011 and 2012. UNS Electric is obligated to purchase 100% of the output from these facilities.
UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. UNS Electric’s transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 2013 and 2016. However, the effects of both purchased power and transmission cost adjustments are mitigated through UNS Electric’s PPFAC.
UNS Gas and UNS Electric have operating leases, primarily for office facilities and computer equipment, with varying terms and expiration dates. The expense was less than $1 million in each of the years 2012, 2011, and 2010. UNS Gas’ and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are less than $1 million per year for 2013 through 2031.
RES Performance-Based Incentives
UNS Electric is contractually obligated to make RES PBI payments to retail customers with solar installations. UNS Electric’s total obligation for RES PBIs is about $6 million with payments required over periods ranging from 10 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2.
Solar Project
In December 2012, UNS Electric entered into an agreement for the construction of a 7.182 MW solar photovoltaic power plant that will be constructed in two phases. The first phase will result in a 4.2 MW plant that UNS Electric expects to be operational in June of 2013. The balance of the project will be completed in 2014. UNS Electric invested $5 million in this project in 2012. The contract requires additional investments of $4 million in each of 2013 and 2014. This is an approved project under UNS Electric’s RES implementation plan. See Note 2.
TEP CONTINGENCIES
Springerville Generating Station Unit 3 Outage
In July 2012, Springerville Unit 3 experienced an unplanned outage. As a result of the outage, TEP recorded a pre-tax loss of $2 million in the third quarter of 2012 as TEP did not meet certain availability requirements under the terms of TEP’s operating agreement with Tri-State.
Claims Related to San Juan Generating Station
San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC has compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
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Claims Related to Four Corners Generating Station
In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants, alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued, and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed Motions to Dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties filed a Joint Motion to Stay in November 2012 in furtherance of settlement talks.
TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim.
Mine Closure Reclamation at Generating Stations Not Operated by TEP
TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of reclamation costs is expected to be $27 million upon expiration of the coal supply agreements, which expire between 2016 and 2019. The reclamation liability (present value of future liability) was $16 million at December 31, 2012, and $13 million at December 31, 2011.
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreement terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
TEP’s PPFAC allows us to pass through most fuel costs (including final reclamation costs) to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and recovering the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
In June 2012, the participants at San Juan executed a Trust Reclamation Agreement requiring each participant to individually establish and fund a trust based on the participant’s share of the estimated final mine reclamation costs. The trust must remain in effect through completion of final mine reclamation activities currently projected to be 2050. TEP established and funded its trust with $1 million in 2012. TEP expects to make additional cumulative deposits to the trust of approximately $1 million over the next five years.
Tucson to Nogales Transmission Line
TEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP had previously capitalized $11 million related to the project, including $2 million to secure land and land rights. UNS Electric had previously capitalized $0.4 million related to the project.
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TEP and UNS Electric expect to abandon the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting the elimination of this project. In TEP’s pending rate case proceeding before the ACC, TEP entered into a proposed settlement agreement in which it agrees to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In the fourth quarter of 2012, TEP and UNS Electric wrote off a portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and $0.2 million, respectively, of costs incurred through 2012.
RESOLUTION OF CONTINGENCIES
In April 2010, the Sierra Club filed a citizens’ suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the United States District Court for the District of New Mexico against Public Service Company of New Mexico (PNM), as operator of San Juan, SJCC, and PNM’s and SJCC’s respective parent companies. The suit alleged that certain activities at San Juan and the San Juan mine associated with the treatment, storage, and disposal of coal and Coal Combustion Residuals (CCRs) violated RCRA and SMCRA. The suit sought an injunction with respect to the placement of CCRs at the mine, the imposition of civil penalties, and attorney’s fees and costs. In March 2012, the parties settled the case. The settlement was approved by the court.
TEP is responsible for its share of the settlement of the San Juan claims. TEP recorded less than $1 million for its share of the costs to fund environmental projects and Sierra Club attorney and expert fees required by the settlement, substantially all of which was recorded in 2011. In addition, TEP paid $1 million for its share of construction costs for a new groundwater recovery system adjacent to San Juan and other environmental projects required by the settlement.
San Juan Mine Fire
In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. The mine resumed production in June 2012. The mine fire did not have a material effect on TEP’s financial condition, results of operations, or cash flows due to the use of on-hand inventory of previously mined coal and the low market price of wholesale power during the closure. TEP awaits final resolution in the matter pending an insurance settlement between the mine operator and its insurance company.
ENVIRONMENTAL MATTERS
Environmental Regulation
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan. TEP expects to capitalize environmental compliance costs of $10 million in 2013 and $27 million in 2014. In addition, TEP recorded O&M expenses of $15 million in 2012, $12 million in 2011, and $14 million in 2010 related to environmental compliance. TEP expects environmental O&M expenses to be $16 million in 2013.
TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
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Hazardous Air Pollutant Requirements
The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules called the Mercury and Air Toxics Standards setting limits for mercury emissions and other hazardous air pollutants from power plants.
Navajo
Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which include the regional haze final Best Available Retrofit Technology (BART) rules.
San Juan
TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards.
Four Corners
Based on the EPA’s final standards, Four Corners may need mercury emission control equipment by 2015. The estimated capital cost of this equipment is less than $1 million. TEP expects the annual operating cost of the mercury emission control equipment to be less than $1 million.
Springerville
Based on the EPA’s final standards, Springerville may need mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.
Sundt Generating Station
TEP expects the final EPA standards will have little effect on capital expenditures at Sundt Generating Station (Sundt).
Regional Haze Rules
The EPA’s regional haze rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight. The EPA oversees regional haze planning for these power plants.
Complying with the EPA’s BART findings, and with other environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.
Navajo
In January 2013, the EPA proposed an alternative BART determination that would require the installation of SCR technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant’s particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP’s share of annual operating costs is estimated at less than $1 million for each of the control technologies (SCR and baghouses).
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San Juan
In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.
In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit United States Court of Appeals (Circuit Court). In addition, PNM filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA’s reconsideration and the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP’s five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the Circuit Court’s decision.
In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million.
TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At December 31, 2012, the book value of TEP’s share of San Juan Units 1 and 2 was $217 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals.
If the proposed plan is not accepted and agreed to by the EPA, the New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in 2013 to meet the FIP compliance deadline. TEP cannot predict the ultimate outcome of this matter.
Four Corners
In August 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly-owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install SCR technology is about $35 million. TEP’s share of annual operating costs for SCR is estimated at $2 million.
Springerville
Regional haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018.
Sundt
In December 2012, the EPA issued a proposed rule on provisions, that had not been previously addressed, in the Arizona State Implementation Plan related to regional haze. Contrary to the Arizona plan the EPA disapproved, among other things, the determination that Sundt Unit 4 is not subject to the BART provisions of the regional haze rule and is therefore subject to BART requirements. If the BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART rule which is likely to be completed in October 2013. The EPA is expected to release a proposed BART requirement for Sundt Unit 4 in March 2013.
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NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Utility Plant in Service by major class:
(1) Unamortized computer software costs were $36 million for UNS Energy and $35 million for TEP as of December 31, 2012, and $43 million for UNS Energy and $42 million for TEP as of December 31, 2011.
(2) The amortization of computer software costs in UNS Energy’s income statements was $13 million in 2012, $10 million in 2011, and $9 million in 2010. The amortization of computer software costs in TEP’s income statements before intercompany allocations was $13 million in 2012, $10 million in 2011, and $9 million in 2010.
TEP Utility Plant under Capital Leases
All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term. See Note 6. At December 31, 2012, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:
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The depreciable lives as of December 31, 2012, were as follows:
See Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 6.
JOINTLY-OWNED FACILITIES
At December 31, 2012, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:
TEP has financed or provided funds for the above facilities and TEP’s share of its operating expenses is reflected in the income statements based on the nature of the expense.
ASSET RETIREMENT OBLIGATIONS
The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:
NOTE 6. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
Long-term debt matures more than one year from the date of the financial statements. We summarize UNS Energy’s and TEP’s long-term debt in the statements of capitalization.
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UNS ENERGY DEBT-CONVERTIBLE SENIOR NOTES
In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. In 2012, UNS Energy converted or redeemed the entire $150 million Convertible Senior Notes outstanding. Holders of the Convertible Senior Notes had the option of converting their interests to Common Stock at a conversion rate applicable at the time of each notice of redemption or receiving the redemption price of par plus accrued interest for the Convertible Senior Notes. In the first quarter of 2012, holders of approximately $73 million of the Convertible Senior Notes converted their interests into approximately 2.1 million shares of Common Stock and $2 million were redeemed for cash. In the second quarter of 2012, holders of approximately $74 million of Convertible Senior Notes converted their interests into approximately 2.2 million shares of Common Stock and $1 million were redeemed for cash.
TEP DEBT
Tax-Exempt Variable Rate Bonds and Interest Rate Swap
TEP had $215 million in tax-exempt variable rate debt outstanding at December 31, 2012 and December 31, 2011. Each series of bonds is supported by a Letter of Credit (LOC) issued under the TEP Credit Agreement or separate TEP Letter of Credit and Reimbursement Agreements. The LOCs are secured by mortgage bonds issued under TEP’s 1992 Mortgage.
In November 2011, TEP repurchased $150 million of variable rate bonds. TEP did not cancel the repurchased bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. See 2011 TEP Unsecured Notes below.
In December 2010, TEP issued $37 million of Coconino County, Arizona, tax-exempt pollution control bonds (2010 Coconino Bonds). The 2010 Coconino Bonds are supported by a LOC, which is secured by $37 million of 1992 Mortgage Bonds and expires December 2014. The bonds accrue interest at a variable weekly rate and are due October 2032. These bonds are multi-modal bonds that allow TEP to change the interest feature of the bonds. They are callable at any time at par plus accrued interest and are subject to mandatory redemption under certain circumstances if the LOC is not extended. The average interest rate on TEP’s 2010 Coconino Bonds was 0.22% in 2012 and 0.23% in 2011. TEP used the proceeds to redeem a corresponding principal amount of fixed rate Coconino pollution control bonds. TEP capitalized less than $1 million in costs related to the issuance of these bonds and will amortize the costs to Interest Expense - Long-Term Debt in the income statements through October 2032, the term of the bonds.
The following table shows interest rates on TEP’s variable rate bonds which are reset weekly by its remarketing agents:
In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.
Unsecured Fixed Rate Bonds
At December 31, 2012, TEP had $609 million in unsecured fixed rate bonds. At December 31, 2011, TEP had $616 million outstanding.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033. TEP’s $8 million payment to the trustee was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized approximately $2 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense - Long-Term Debt in the income statements through March 2030, the term of the bonds.
In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds together with $0.4 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $16 million of outstanding unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized less than $0.5 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense - Long-Term Debt in the income statements through June 2030, the term of the bonds.
In November 2011, TEP redeemed $22 million in unsecured fixed rate bonds. See 2011 TEP Unsecured Notes below.
In October 2010, TEP issued $100 million of Pima County, Arizona tax-exempt IDBs. The IDBs are unsecured, bear interest at a rate of 5.25%, mature in October 2040, and are callable at par on or after October 1, 2020. Net of an underwriting discount, $99 million of proceeds were deposited in a construction fund with the bond trustee. The proceeds were applied to the construction of certain of TEP’s transmission and distribution facilities used to provide electric service in Pima County. TEP drew down $88 million of the proceeds from the construction fund in 2010 and $11 million in 2011. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs to Interest Expense-Long-Term Debt in the income statements through October 2040, the term of the bonds.
2012 TEP Unsecured Notes
In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the remaining proceeds used for general corporate purposes. TEP capitalized approximately $1 million in costs related to the issuance of unsecured notes and will amortize the costs to Interest Expense - Long-Term Debt in the income statements through March 2023, the term of the unsecured notes.
2011 TEP Unsecured Notes
In November 2011, TEP issued $250 million of 5.15% unsecured notes due November 2021. TEP may call the debt any time before August 15, 2021, with a make-whole premium plus accrued interest. After August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the sale to: 1) repurchase $150 million of variable rate bonds; 2) redeem $22 million of 6.1% fixed rate bonds; and 3) repay $78 million of outstanding revolving credit facility balances, with the remaining proceeds applied to general corporate purposes. The variable rate bonds were supported by LOCs issued under TEP’s Credit Facility. As a result of the repurchase of the variable rate bonds, TEP cancelled $155 million of LOCs and reduced its mortgage bonds supporting the LOCs by the same amount. TEP capitalized $2 million in costs related to the issuance of the notes and will amortize the costs to Interest Expense-Long-Term Debt in the income statements through November 2021, the term of the unsecured notes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1992 Mortgage
TEP’s 1992 Mortgage creates liens on and security interests in most of TEP’s utility plant assets, with the exception of Springerville Unit 2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2. Utility Plant under Capital Leases is not subject to such liens nor is it available to TEP creditors, other than the lessors. The net book value of TEP’s utility plant subject to the lien of the indenture was approximately $2 billion at December 31, 2012, and December 31, 2011.
TEP CAPITAL LEASE OBLIGATIONS
Springerville Leases
The terms of TEP’s capital leases are as follows:
• The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. TEP has a fair market value purchase option for facilities under the Springerville Unit 1 Lease. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal process to determine the fair market value purchase price, in accordance with the Springerville Unit 1 Leases agreements. Based on that appraisal, TEP would have to pay $159 million in 2015 for the 86% interest not already owned by TEP. In 2012, TEP initiated a proceeding seeking judicial confirmation of the results of the appraisal process in federal district court. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for the leased interest. In January 2013, the federal district court denied TEP’s petition on the grounds that the court lacks jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit.
• The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for fixed-rate lease renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million. The lease provides for one renewal period of six years beginning in April 2015, with additional renewal periods of five or more years through 2035.
• The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the leases TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of common facilities are $38 million in 2017 and $68 million in 2021.
TEP agreed with Tri-State, the owner of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Facilities Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either: 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities.
In January 2013, through scheduled lease payments, TEP reduced its capital lease obligations by $82 million.
LEASE DEBT AND EQUITY
Investments in Springerville Lease Debt and Equity
TEP’s investments in Springerville Unit 1 lease debt totaled $9 million at December 31, 2012, and $29 million at December 31, 2011. In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2012, and $37 million at December 31, 2011.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Interest Rate Swaps-Springerville Common Facilities Lease Debt
TEP’s interest rate swaps hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month London Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2012, and 1.625% at December 31, 2011.
The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:
TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 16.
UNS ELECTRIC SENIOR UNSECURED NOTES
UNS Electric has $100 million of senior unsecured notes: $50 million at 6.5%, due 2015 and $50 million at 7.1%, due 2023. The UNS Electric long-term notes are guaranteed by UES. The notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity United States Treasury security yield plus 50 basis points.
UNS Electric’s long-term notes contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness.
UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP
In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.
The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens, and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement.
UNS GAS SENIOR UNSECURED NOTES
In August 2011, UNS Gas issued $50 million of senior guaranteed notes at 5.39% due August 2026. UNS Gas used the proceeds to pay in full the $50 million of UNS Gas 6.23% notes that matured in August 2011. UNS Gas has another $50 million of notes at 6.23% due August 2015. The notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity United States Treasury security yield plus 50 basis points. UES guarantees the notes. UNS Gas capitalized less than $0.5 million of costs related to the issuance of the notes and will amortize these costs over the life of the notes.
UNS Gas’ long-term debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
UNS ENERGY CREDIT AGREEMENT
In November 2011, UNS Energy amended its existing credit agreement to extend the expiration date from November 2014 to November 2016.
In November 2010, UNS Energy amended and restated its existing credit agreement. As amended, the agreement consists of a $125 million revolving credit facility and revolving letter of credit facility. UNS Energy’s obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES, and UED.
UNS Energy capitalized less than $0.5 million related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement, and will amortize these costs through November 2016.
UNS Energy had $45 million of outstanding borrowings at December 31, 2012, and $57 million of outstanding borrowings at December 31, 2011, under its revolving credit facility. The weighted average interest rate on the revolver was 1.96% at December 31, 2012, and 2.04% at December 31, 2011. We reflected the revolver borrowings in Long-Term Debt on the balance sheet as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 13, 2013, outstanding borrowings under the UNS Credit Agreement were $45 million.
Interest rates and fees under the UNS Energy Credit Agreement are based on a pricing grid tied to UNS Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.75% for Eurodollar loans or Alternate Base Rate plus 0.75% for Alternate Base Rate loans.
The UNS Energy Credit Agreement contains a number of covenants which restrict UNS Energy and its subsidiaries, including restrictions on additional indebtedness, liens, mergers, and sales of assets. The UNS Energy Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio determined on a UNS Energy standalone basis and not to exceed a maximum leverage ratio determined on a consolidated basis. Under the UNS Energy Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement.
TEP CREDIT AGREEMENT
In December 2011, TEP reduced its letter of credit facility from $341 million to $186 million, following the repurchase of $150 million of variable rate bonds and the cancellation of $155 million of LOCs supporting those bonds.
In November 2011, TEP amended its existing credit agreement to extend the expiration date from November 2014 to November 2016.
In November 2010, TEP amended and restated its existing credit agreement, consisting of a $200 million revolving credit, revolving LOC facility, and a $341 million LOC facility to support tax-exempt bonds.
The TEP credit facility is secured by $386 million of mortgage bonds issued under the 1992 Mortgage, which creates a lien on and security interest in most of TEP’s utility plant assets.
TEP capitalized $1 million related to the 2011 credit agreement amendment and $4 million related to the 2010 credit agreement amendment and restatement, and will amortize these costs through November 2016.
Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $186 million letter of credit facility is 1.125%.
The TEP Credit Agreement contains a number of covenants which restrict TEP and its subsidiaries, including restrictions on liens, mergers, and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. Under the TEP Credit Agreement, TEP may pay dividends to UNS Energy so long as it maintains compliance with the agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2012, TEP had no borrowings outstanding and $1 million in LOCs issued under its revolving credit facility. As of December 31, 2011, TEP had $10 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility. The revolving loan balance was included in Current Liabilities on UNS Energy’s and TEP’s balance sheets. The outstanding LOCs are off-balance sheet obligations of TEP. As of February 13, 2013, TEP had $30 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility.
2010 TEP REIMBURSEMENT AGREEMENT
A $37 million letter of credit was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of credit supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010, see Variable Rate Tax-Exempt Bonds, above.
The 2010 TEP Reimbursement Agreement is secured by $37 million of mortgage bonds issued under TEP’s 1992 Mortgage. Fees are payable on the aggregate outstanding amount of the letter of credit at a rate of 1.50% per annum.
The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above.
UNS GAS/UNS ELECTRIC REVOLVER
In November 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement to extend the expiration date from November 2014 to November 2016.
In November 2010, UNS Gas and UNS Electric amended and restated their existing unsecured credit agreement. As amended, the UNS Gas/UNS Electric Revolver consists of a $100 million revolving credit and revolving letter of credit facility. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Gas and UNS Electric each are liable for only their own individual borrowings under the UNS Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Revolver may be used to issue LOCs, as well as for revolver borrowings. UNS Gas and UNS Electric issue LOCs, which are off-balance sheet obligations, to support power and gas purchases and hedges.
UNS Gas and UNS Electric capitalized less than $0.5 million of costs related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement, and will continue to amortize these costs through November 2016 to Interest Expense - Long-Term Debt in the income statements.
Interest rates and fees under the UNS Gas/UNS Electric Revolver are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.25% for Eurodollar loans or Alternate Base Rate plus 0.25% for Alternate Base Rate loans.
The UNS Gas/UNS Electric Revolver contains a number of covenants which impose restrictions on UNS Gas, UNS Electric, and UES, including restrictions on additional indebtedness, liens, and mergers. The UNS Gas/UNS Electric Revolver also stipulates a maximum leverage ratio. Under the terms of the UNS Gas/UNS Electric Revolver, UNS Gas and UNS Electric may pay dividends so long as they maintain compliance with the agreement.
UNS Electric had less than $0.5 million in outstanding LOCs under the UNS Gas/UNS Electric Revolver as of December 31, 2012, and $6 million outstanding as of December 31, 2011. These balances are not shown on the balance sheet.
OTHER
At December 31, 2012, UNS Energy and its subsidiaries were in compliance with the terms of their respective loan, note purchase, and credit agreements. No amounts of net income were subject to dividend restrictions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DEBT MATURITIES
Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
(1) TEP’s variable rate bonds are backed by $186 million in LOCs issued pursuant to TEP’s Credit Agreement which expires in November 2016 and TEP’s $37 million Reimbursement Agreement which expires in December 2014. Although the variable rate bonds mature between 2018 and 2032, the above table reflects a redemption or repurchase of such bonds in 2014 and 2016 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.
(2) The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.
NOTE 7. STOCKHOLDERS’ EQUITY
DIVIDEND LIMITATIONS
UNS Energy
UNS Energy’s ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium, and UED, as well as compliance with various debt covenant requirements. UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2012; therefore, TEP and the other subsidiaries were not restricted from paying dividends.
In February 2013, UNS Energy declared a first quarter dividend to shareholders of $0.435 per share of UNS Energy Common Stock. The dividend, totaling approximately $18 million, will be paid on March 25, 2013, to common shareholders of record as of March 13, 2013.
In the first half of 2012, $147 million of the Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock equity by $147 million.
TEP
The Federal Power Act states that an electric utility’s dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings. TEP paid dividends to UNS Energy of $30 million in 2012; no dividends were paid in 2011; and $60 million were paid in 2010.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
UNS Energy did not contribute capital to TEP in 2012 but made capital contributions of $30 million in 2011 and $15 million in 2010.
NOTE 8. INCOME TAXES
A reconciliation of the federal statutory income tax rate to each company’s effective income tax rate follows:
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The significant components of deferred income tax assets and liabilities consist of the following:
The net deferred income tax liability on the balance sheet is as follows:
The $9 million unregulated investment loss deferred tax asset includes $7 million of capital loss at December 31, 2012, and December 31, 2011. The deferred tax asset can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UNS Energy recorded a $7 million valuation allowance against the deferred tax asset as of December 31, 2012, and December 31, 2011. Management believes that based on its historical pattern of taxable income, UNS Energy will produce sufficient income in the future to realize all other deferred income tax assets.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Tax Position
As of December 31, 2012, UNS Energy and TEP had the following carryforward amounts:
State Tax Rate Change
In the first quarter of 2011, the Arizona legislature passed a bill reducing the corporate income tax rate from the current rate of 6.968%. The tax rate reduction will be phased in beginning in 2014, with a reduction of approximately 0.5% per year until the income tax rate reaches 4.9% for 2017 and later years. As a result of these tax rate reductions, we reduced the net deferred tax liabilities at UNS Energy and TEP by $13 million, offset entirely by adjustments to regulatory assets and liabilities. The income tax rate change did not have an impact on UNS Energy’s and TEP’s effective tax rate for 2012 or 2011.
Excess Tax Benefit Realized from Share-Based Compensation Plans
UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2012, UNS Energy had $2 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $202 million are used.
Uncertain Tax Positions
In accordance with accounting rules related to uncertain tax positions, we are required to determine whether it is more likely than not that we will sustain an income tax position under examination. Each income tax position is measured to determine the amount of benefit to recognize in the financial statements. The following table shows the changes in unrecognized tax benefits of UNS Energy and TEP:
Unrecognized tax benefits of $1 million, if recognized, would reduce the effective tax rate at December 31, 2012, and December 31, 2011, for both UNS Energy and TEP. The balance in unrecognized tax benefits could change in the next 12 months as a result of ongoing IRS audits, but we are unable to determine the amount of the change.
UNS Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. UNS Energy and TEP did not recognize a reduction to interest expense in 2012. A reduction to Other Interest Expense of $1 million was recorded in 2011. The balance of interest payable for UNS Energy and TEP was $1 million at both December 31, 2012 and December 31, 2011. We have no penalties accrued in the years presented.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
UNS Energy and TEP have been audited by the IRS through tax year 2008 and are currently under audit by the IRS for 2009 and 2010. We are unable to determine when the audits will be completed. UNS Energy and TEP are not currently under audit by any state tax agencies.
NOTE 9. EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
Pension Contributions
The Pension Protection Act of 2006 (The Pension Act) established minimum funding targets for pension plans. A plan’s funding target is the present value of all benefits accrued or earned as of the beginning of the plan year. While the annual targets are not legally required, benefit payment options are limited for plans that do not meet the targets, and a funding deficiency notice must be sent to all plan participants. Our plans are in compliance with The Pension Act.
In 2013, UNS Energy expects to contribute $24 million to the pension plans, including $22 million in contributions by TEP.
OTHER RETIREE BENEFIT PLANS
TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Gas and UNS Electric provide retiree medical benefits for current retirees. UNS Gas and UNS Electric active employees are not eligible for retiree medical benefits.
TEP has a Voluntary Employee Beneficiary Association (VEBA) to fund its other retiree benefit plan related to classified employees. TEP contributed $3 million in 2012, and $2 million in each of 2011 and 2010 to the VEBA. We record changes in other retiree obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Other retiree benefits for unclassified employees are funded on a year-by-year basis.
TEP’s retiree medical plan was amended effective December 31, 2011, to increase the participant contributions for unclassified employees who retire on or after July 1, 2012. TEP’s retiree medical plan was amended in 2012, to increase the participant contributions for classified employees who retire after February 1, 2014.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The pension and other retiree benefit related amounts (excluding tax balances) included on the UNS Energy balance sheet are:
The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $9 million at December 31, 2012, and $8 million at December 31, 2011. The table also includes a retiree benefit liability of $1 million for UNS Gas and UNS Electric for each period presented.
OBLIGATIONS AND FUNDED STATUS
We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2012, and December 31, 2011. The table below includes TEP’s, UNS Gas’, and UNS Electric’s plans. The change in projected benefit obligation and plan assets and reconciliation of the funded status are as follows:
(1) TEP made $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012 and 2011.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table above includes the following for UNS Gas and UNS Electric:
• Pension benefit obligations of $23 million at December 31, 2012, and $18 million at December 31, 2011;
• Plan assets of $14 million at December 31, 2012, and $10 million at December 31, 2011; and
• A retiree benefit obligation of $1 million at December 31, 2012, and at December 31, 2011.
The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:
Information for pension plans with Accumulated Benefit Obligations in excess of pension plan assets follows:
At December 31, 2012, and December 31, 2011, all UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of pension plan assets.
The components of net periodic benefit costs are as follows:
Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in current year earnings.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:
For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $9 million estimated net loss from other regulatory assets and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2013. The estimated net loss for the defined benefit postretirement plans that will be amortized from other regulatory assets into net periodic benefit cost in 2013 is less than $1 million. The estimated prior service benefit that will be amortized is less than $1 million.
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets.
We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow:
Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2012, amounts:
PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS
Pension Assets
We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows:
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 87% of real estate assets tracked by the index in 2012 and comprising 85% in 2011.
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UES pension plan of $14 million at December 31, 2012, and $10 million at December 31, 2011.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
UNS Gas and UNS Electric have no pension assets classified as Level 3 in the fair value hierarchy.
Pension Plan Investments
Investment Goals
Asset allocation is the principal method for achieving each pension plan’s investment objectives, while maintaining an appropriate level of risk. We will consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding will be reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.
Risk Management
We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via annual actuarial valuation.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan as of December 31, 2012, follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds.
Other Retiree Benefit Assets
As of December 31, 2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. As of December 31, 2011, the fair value of VEBA trust assets was $5 million, including $3 million of fixed income investments and approximately $2 million of equity and money market funds. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the defined benefit pension plans and retiree plan, which reflect future service, as appropriate.
TEP’s union plan was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments shown above was approximately $5 million in total. The pension benefit obligation was not materially affected by this amendment.
UNS Gas and UNS Electric expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $2 million in 2013 through 2017, and $9 million in 2018 through 2022.
K-142
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DEFINED CONTRIBUTION PLAN
We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in 2012, $5 million in 2011, and $4 million in 2010. UNS Gas and UNS Electric made matching contributions of less than $1 million in each of 2012, 2011, and 2010.
NOTE 10. SHARE-BASED COMPENSATION PLAN
Under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), the Compensation Committee of the UNS Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted shares/units, and performance shares. The total number of shares which may be awarded under the 2011 Plan cannot exceed 1.2 million shares.
STOCK OPTIONS
Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of the grant. Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement-eligible officers, compensation expense is recorded immediately.
See summary of the stock option activity in the table below:
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
See summary of stock options in the table below:
RESTRICTED STOCK UNITS AND PERFORMANCE SHARE AWARDS
Restricted Stock Units
Restricted stock and stock units are generally granted to non-employee directors. Restricted stock is an award of Common Stock that is subject to forfeiture if the restrictions specified in the award are not satisfied. Stock units are a non-voting unit of measure that is equivalent to one share of Common Stock. The directors may elect to receive stock units in lieu of restricted stock. Restricted stock generally vests over periods ranging from one to three years and is payable in Common Stock. Stock units vest either immediately or over periods ranging from one to three years. The restricted stock units vest immediately upon death, disability, or retirement. In the January following the year the person is no longer a director, Common Stock shares will be issued for the vested stock units. Compensation expense equal to the fair market value on the grant date is recognized over the vesting period. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid.
Common Stock shares totaling 31,058 in 2012, 56,705 in 2011, and 14,866 in 2010 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.
The Compensation Committee granted in total, the following stock units to non-employee directors:
•
2012-15,303 stock units at a weighted average fair value of $35.94 per share;
•
2011-14,655 stock units at a weighted average fair value of $37.53 per share; and
•
2010-15,620 stock units at a weighted average fair value of $31.69 per share.
Performance Share Awards
In 2012, 2011, and 2010, the Compensation Committee granted performance share awards to upper management. Half of the performance share awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Return to the Edison Electric Institute Index during the performance period. The grant date fair value of these awards with a market condition were derived based on a Monte Carlo simulation. Compensation expense equal to the fair value on the grant date is recognized over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half will be paid out in Common Stock based on cumulative net income during the performance period. The grant date fair values of these awards with a performance condition were the closing Common Stock market prices on the dates of grant. Compensation expense equal to the fair value on the grant date is recognized over the requisite service period only for the awards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Vested performance shares are eligible for dividend equivalents during the performance period.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At December 31, 2012, upon completion of the three-year performance period, 76,478 shares were earned and vested; 17,242 shares were unearned and forfeited. The vested performance shares also earned 10,516 in dividend equivalent shares.
SHARE-BASED COMPENSATION EXPENSE (Stock Options, Restricted Stock Units, and Performance Shares)
Annually during 2010 through 2012, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. The actual tax deduction realized from the exercise of share-based payment arrangements totaled less than $1 million in 2012 and $3 million in 2010. UNS Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2011.
At December 31, 2012, the total unrecognized compensation cost related to non-vested share-based compensation was $2 million, which will be recorded as compensation expense over the remaining vesting periods through December 2014. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at December 31, 2012, was 1 million.
NOTE 11. FAIR VALUE MEASUREMENTS
We categorize our assets and liabilities at fair value into the three-level hierarchy based on inputs used to determine the fair value measurement. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable. Level 3 inputs are unobservable and supported by little or no market activity.
K-145
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. There were no transfers between Levels 1, 2, or 3 for either reporting period.
K-146
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(1) Cash Equivalents are based on observable market prices and include the fair value of money market funds and certificates of deposit. These amounts are included in Cash and Cash Equivalents and in Investments and Other Property-Other on the balance sheets.
(2) Rabbi Trust Investments include amounts held in mutual and money market funds related to deferred compensation and SERP benefits. The valuation is based on quoted prices traded in active markets. These investments are included in Investments and Other Property - Other on the balance sheets.
(3) Energy Contracts include gas swap agreements (Level 2), gas and power options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Other Assets and Derivative Instruments on the balance sheets. The valuation techniques are described below. See Note 16.
(4) Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.
Energy Contracts
We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange pricing adjusted for basis differences, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.
For both power and gas prices, we obtain quotes from brokers, major market participants, exchanges, or industry publications, and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.
We estimate the fair value of our options using the Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.
Our assessments of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our contracts monthly.
The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:
(1) TEP comprises $1 million of the forward contract assets and $2 million of the forward contract liabilities.
(2) The option contracts relate to TEP.
Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability. These are recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statements.
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
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UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Financial Instruments Not Carried at Fair Value
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:
•
The carrying amounts of our current assets and liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements, which approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
•
For Investment in Lease Debt, we calculate the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data.
•
For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 in 2011.
•
For Long-Term Debt, we use quoted market prices, where available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
K-149
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying value recorded on the balance sheet and the estimated fair values of our financial instruments were as follows:
TEP held the Investment in Lease Debt to maturity in January 2013. This investment was stated at amortized cost, which means the purchase cost had been adjusted for the amortization of the premium and discount to maturity.
The fair value of TEP’s Long-Term Debt increased from prior year because of a change in valuation methodology concerning the make-whole premium applied to the bonds if they are called early.
NOTE 12. UNS ENERGY EARNINGS PER SHARE
We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options; contingently issuable shares under equity-based awards, or common shares that would result from the conversion of Convertible Senior Notes. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to Common Stock.
K-150
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table shows the effects of potentially dilutive common stock on the weighted average number of shares:
The following table shows the number of stock options excluded from the diluted EPS computation because the stock option’s exercise price was greater than the average market price of the Common Stock:
In the first half of 2012, the entire balance of Convertible Senior Notes was converted to Common Shares or redeemed for cash. See Note 6.
NOTE 13. MILLENNIUM INVESTMENTS
In 2010, Millennium recorded impairment losses of $10 million reducing the book value of its unconsolidated equity and cost method investments to zero. Millennium received notification of valuation changes and ownership percentage reductions as projects lost viability and funding failed. In addition, Millennium sold a wholly-owned subsidiary and recorded a gain of less than $1 million. Gains and losses were included in Other Income or Other Expense in UNS Energy’s income statements. Millennium also wrote off $3 million of Deferred Tax Assets related to its investments.
In 2009, Millennium sold an equity investment, receiving an upfront payment of $5 million in 2009 and a $15 million, 6% secured promissory note. Millennium received the remaining principal amount of $15 million in 2012.
K-151
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The following recently issued accounting standards are not yet reflected in the financial statements:
•
The Financial Accounting Standards Board (FASB) issued a pronouncement that will require entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position (balance sheet) or subject to an agreement similar to a master netting arrangement. In addition, the pronouncement requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013 and do not expect this pronouncement to have a material impact on our disclosures.
•
The FASB issued a rule which amends the guidance for impairment testing of indefinite-lived intangible assets. An entity will have the option to perform qualitative analysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative impairment test. We will be required to comply in the first quarter of 2013; however, we do not expect this pronouncement to have a material impact on our financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to comply with renewable resources requirements.
•
The FASB decided in December 2012 to require new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and the income statement line items affected by the reclassification. We plan to present this information in a footnote. We will be required to comply in the first quarter of 2013 and do not expect this decision to have a material impact on our financial statements.
K-152
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION
A reconciliation of net income to net cash flows from operating activities follows:
K-153
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NON-CASH TRANSACTIONS
In 2012, the following non-cash transactions occurred:
•
UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and
•
TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6.
In 2010, the following non-cash transactions occurred:
•
TEP used a trustee to issue and redeem $37 million tax-exempt bonds. TEP had no cash receipts or payments as a result of this transaction. See Note 6; and
•
TEP deposited proceeds from the issuance of $100 million Pima County tax-exempt IDBs in a construction fund with a trustee. TEP drew down funds as qualified expenditures were incurred. The $11 million remaining in the construction fund at December 31, 2010, affected recognized assets and liabilities but did not result in cash receipts or payments. TEP drew down the remaining funds in the construction fund by March 2011. See Note 6.
K-154
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
(1) The non-cash additions to Utility Plant represent accruals for capital expenditures.
(2) The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.
(3) The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.
(4) The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.
(5) The non-cash UED Secured Term Loan prepayment represents deposits applied to $30 million of loan principal.
NOTE 16. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
See Note 1 for description of our related accounting policies and Note 11 for information related to the fair value of derivatives.
FINANCIAL IMPACT OF DERIVATIVES
Cash Flow Hedges
UNS Energy and TEP had liabilities related to cash flow hedges of $12 million as of December 31, 2012, and $14 million as of December 31, 2011. TEP’s power purchase swap agreement under which these hedges are entered into expires in 2015.
The after-tax unrealized gains and losses on cash flow hedge activity and amounts reclassified to earnings are reported in the statements of other comprehensive income. The amounts reclassified to earnings are reported in Long Term Debt Interest Expense, Capital Leases Interest Expense, and Purchased Power Expense in the statements of income. The amounts expected to be reclassified to earnings within the next twelve months is estimated to be $2 million.
Regulatory Treatment of Commodity Derivatives
We disclose unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than in the statements of other comprehensive income or in the income statements, as shown in the following table:
K-155
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The fair values of derivative assets and liabilities were as follows:
Derivative assets are included in Derivative Instruments and Other Non-Current Assets on the UNS Energy balance sheet and Other Current Assets and Other Non-Current Assets on the TEP balance sheet.
The realized losses on settled gas swaps that are fully recoverable through the PPFAC or PGA were as follows:
At December 31, 2012, UNS Energy and TEP had contracts that will settle through the fourth quarter of 2015.
Other Commodity Derivatives
The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial statements of UNS Energy and TEP as follows:
(1) The amounts previously reported have been revised.
DERIVATIVE VOLUMES
At December 31, 2012, UNS Energy had gas swaps totaling 14,351 billion British thermal units (GBtu) and power contracts totaling 2,228 Gigawatt-hours (GWh), while TEP had gas swaps totaling 6,158 GBtu and power contracts totaling 820 GWh. At December 31, 2011, UNS Energy had gas swaps totaling 14,856 GBtu and power contracts totaling 3,147 GWh, while TEP had gas swaps totaling 6,855 GBtu and power contracts totaling 815 GWh.
CREDIT RISK ADJUSTMENT
When the fair value of our derivative contracts is reflected as an asset, the counterparty owes us and this creates credit risk. We also consider the impact of our own credit risk on instruments that are in a net liability position. The impact of counterparty credit risk and our own credit risk on the fair value of derivative asset contracts was less than $0.5 million at December 31, 2012 and December 31, 2011.
CONCENTRATION OF CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value valuations.
K-156
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Gas, or UNS Electric; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
The following table shows the sum of the fair value of all derivative instruments under contracts with credit-risk related contingent features that are in a net liability position at December 31, 2012. It also shows LOCs posted and additional collateral to be posted if credit-risk related contingent features are triggered.
As of December 31, 2012, TEP had $15 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which two counterparties individually composed greater than 10% of the total credit exposure. UNS Electric and UNS Gas had less than $1 million of such credit exposure related to its supply and hedging contracts.
K-157
UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.
The following tables reflect the quarterly impact of revisions on UNS Energy’s statements of income recorded in the fourth quarter of 2012 (See Note 1):
(1) Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation.
K-158
Schedule II-Valuation and Qualifying Accounts - UNS Energy
(1) TEP, UNS Gas, and UNS Electric record additions to the Reserve for Uncollectible Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesale sales, and in-kind transmission imbalances.
(2) Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. Management believes that it is more likely than not that we will not be able to generate future capital gains to offset the capital losses related to an unregulated investment loss deferred tax asset. As a result, an $8 million valuation allowance was recorded against the deferred tax asset as of December 31, 2010.
(3) Principally reserves for sales tax audits, litigation matters, and damages billable to third parties. As the Other reserves are not individually significant, additions and deductions need not be disclosed.
Schedule II-Valuation and Qualifying Accounts-TEP
(1) TEP records additions to the Reserve for Uncollectible Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.
(2) Principally reserves for sales tax audits, litigation matters, and damages billable to third parties. As the Other reserves are not individually significant, additions and deductions need not be disclosed.
TEP had no deferred tax assets valuation allowance in the periods presented.
K-159
ITEM 9.
ITEM 9. - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. - CONTROLS AND PROCEDURES
UNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UNS Energy and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13(a) - 15(e) or Rule 15(d) - 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2012. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UNS Energy and TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by UNS Energy and TEP in the reports that they file or submit under the Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, UNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UNS Energy and TEP’s disclosure controls and procedures are effective.
While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy or TEP’s internal control over financial reporting during the fourth quarter of 2012, that has materially affected, or is reasonably likely to materially affect, UNS Energy or TEP’s internal control over financial reporting.
UNS Energy’s and TEP’s Management’s Reports on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appear as the first two reports under Item 8 in UNS Energy’s and TEP’s 2012 Annual Report on Form 10-K, the Report of Independent Registered Public Accounting Firm for UNS Energy appears as the third report under Item 8, and the Report of Independent Registered Public Accounting Firm for TEP appears as the fourth report under Item 8.
ITEM 9B.
ITEM 9B. - OTHER INFORMATION
None.
K-160
PART III
ITEM 10.
ITEM 10. - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS
Directors - UNS Energy
* Board Committees
(1) Audit
(2) Compensation
(3) Corporate Governance and Nominating
(4) Finance
(5) Environmental, Safety and Security
K-161
Directors - TEP
Paul J. Bonavia
Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. Prior to joining UNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
Michael J. DeConcini
Mr. DeConcini has served as Senior Vice President, Operations of UNS Energy since May 2010 and Senior Vice President and Chief Operating Officer of TEP from May 2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution.
K-162
Executive Officers of UNS Energy and TEP
See Item 1. Business, Executive Officers of the Registrants.
Information required by Items 401, 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UNS Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
ITEM 11.
ITEM 11. - EXECUTIVE COMPENSATION
Information concerning Executive Compensation will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
ITEM 12.
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
General
At February 13, 2013, UNS Energy had outstanding 41.4 million shares of Common Stock. At February 13, 2013, the number of shares of Common Stock beneficially owned by all directors and officers of UNS Energy as a group amounted to less than 1% of the outstanding Common Stock.
At February 13, 2013, UNS Energy owned 100% of the outstanding shares of common stock of TEP.
Security Ownership of Certain Beneficial Owners
Information concerning the security ownership of certain beneficial owners of UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
Security Ownership of Management
Information concerning the security ownership of the Directors and Executive Officers of UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
K-163
Securities Authorized for Issuance Under Equity Compensation Plans
Information concerning securities authorized for issuance under equity compensation plans will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
ITEM 13.
ITEM 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information concerning certain relationships and related transactions, and director independence of UNS Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks, and Insider Participation in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
ITEM 14.
ITEM 14. - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information concerning principal accountant fees and services will be contained in UNS Energy’s Proxy Statement relating to the 2013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2012, which information is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. - EXHIBITS AND FINANCIAL STATEMENT SCHEDULE
Reference is made to the Exhibit Index commencing on page 167.
K-164
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
K-165
K-166
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TUCSON ELECTRIC POWER COMPANY
Date: February 26, 2013
By:
/s/ Kevin P. Larson
Kevin P. Larson
Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
K-167
EXHIBIT INDEX
K-168
K-169
K-170
K-171
K-172
K-173
K-174
K-175
K-176
K-177
K-178
K-179
K-180
23(b)
-
Consent of Independent Registered Public Accounting Firm - TEP.
24(a)
-
Power of Attorney - UNS Energy.
24(b)
-
Power of Attorney - TEP.
31(a)
-
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UNS Energy, by Paul J. Bonavia.
31(b)
-
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UNS Energy, by Kevin P. Larson.
31(c)
-
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - TEP, by Paul J. Bonavia.
31(d)
-
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - TEP, by Kevin P. Larson.
**32
-
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
***101
-
The following materials from UNS Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language):
(a)
UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Capitalization, (vi) Consolidated Statements of Changes in Stockholders’ Equity; and
(b)
Notes to Consolidated Financial Statements.
(*) Previously filed as indicated and incorporated herein by reference.
(+) Management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601(b)(10)(iii) of Regulation S-K.
** Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
*** XBRL materials for Tucson Electric Power Company are deemed not filed or part of a registration statement or prospectus for the purposes of Section 11 or 12 of the Securities Act of 1933, as amended, and are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.
K-181