ITEM 1. - BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
UniSource Energy is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years. UES was established in 2003, when it acquired the Arizona gas and electric properties from Citizens. UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in Northern and Southern Arizona. Millennium has existing investments in unregulated businesses; no new investments are planned in Millennium. On March 31, 2006, Millennium sold its interest in Global Solar Energy, Inc. (Global Solar), its largest holding. UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to ACC approval, is expected to provide energy to UNS Electric. We conduct our business in three primary business segments - TEP, UNS Gas and UNS Electric.
UniSource Energy was incorporated in the State of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997. In 1998, TEP and UniSource Energy exchanged shares of stock resulting in TEP becoming a subsidiary of UniSource Energy. Following the share exchange, TEP transferred the stock of its subsidiary Millennium to UniSource Energy.
BUSINESS SEGMENT CONTRIBUTIONS
The table below shows the contributions to our consolidated after-tax earnings by our three business segments and Other net income (loss).
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(1) Includes: UniSource Energy parent company expenses; interest expense on the note payable from UniSource Energy to TEP in 2004 and 2005; income and losses from Millennium investments and UED, interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement in 2006 and 2005; and, 2004 includes costs associated with the proposed acquisition of UniSource Energy by an unrelated party.
(2) Relates to the discontinued operations of Global Solar.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Outlook and Strategies, for a discussion of our plans and strategies and Rates and Regulation, below, for the status of competition in Arizona.
References in this report to “we” and “our” are to UniSource Energy and its subsidiaries, collectively.
TEP ELECTRIC UTILITY OPERATIONS
TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UniSource Energy. In 2006, TEP’s electric utility operations contributed 76% of UniSource Energy’s operating revenues and comprised 82% of its assets.
SERVICE AREA AND CUSTOMERS
TEP is a vertically integrated utility that provides regulated electric service to more than 392,000 retail customers in Southeastern Arizona. TEP’s service territory consists of a 1,155 square mile area and includes a population of approximately 1 million in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP holds a franchise to provide electric distribution service to customers in the Cities of Tucson and South Tucson. These franchises expire in 2026 and 2017, respectively. TEP also sells electricity to other utilities and power marketing entities in the Western U.S.
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 seasonal weather patterns and overall economic climate.
Local, regional, and national economic factors can impact the financial condition and operations of TEP’s large industrial customers. Such economic conditions may directly impact energy consumption by large industrial customers and may indirectly impact residential and small commercial sales and revenues if employment levels and consumer spending change.
In 2006, TEP’s number of retail customers increased by 2% and total retail energy consumption increased by approximately 4%. The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years.
TEP expects the number of its retail customers and retail energy consumption to increase 2 - 3% annually through 2010. The retail energy consumption by customer class through 2010 is expected to be similar to the 2006 distribution.
In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however by 2002, none of TEP’s retail customers were served by an alternate ESP. Certain portions of the Arizona Corporation Commission’s (ACC) rules that enabled ESPs to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2005. Unless and until the ACC clarifies the competition rules and ESPs offer to provide energy in TEP’s service area, it is not possible for TEP’s retail customers to use other
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energy providers. Even if some of TEP’s retail customers are, in the future, able to choose other energy providers, the forecasted customer growth rates referred to above would continue to apply to its distribution business. See Rates and Regulation, State, below.
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 Purchases and Interconnections, below.
TEP typically uses its own generation to serve the requirements of its retail and long-term wholesale customers. 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. When TEP expects to have excess coal generating capacity and energy (usually in the first, second and fourth calendar quarters), its wholesale sales consist primarily of two types of sales:
(1) Sales under long-term contracts for periods of more than one year. TEP currently has long-term contracts with three entities to sell firm capacity and energy: Salt River Project Agricultural Improvement and Power District (SRP), which will expire in May 2016, the Navajo Tribal Utility Authority, which expires in December 2009, and the Tohono O’odham Utility Authority, which expires in August 2009.
(2) Short-term sales. Under forward contracts, TEP commits 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. Under short-term sales, TEP sells energy in the daily or hourly markets at fluctuating spot market prices and makes other non-firm energy sales.
TEP participates in the wholesale energy markets, primarily by making sales and purchases in the short-term and forward markets. Over the past three years, both the natural gas and the Western U.S. wholesale electricity markets experienced some price spikes and volatility due to severe winter weather, gas production and storage concerns and, in 2005, hurricane activity in the Gulf of Mexico. TEP cannot predict, however, whether gas and wholesale electricity prices will remain volatile or how these prices will impact TEP’s sales and revenues in the future.
TEP expects the market price in the Western U.S. and the demand for capacity and energy to continue to be influenced by the following factors, among others:
· availability and price of natural gas;
· weather;
· continued population growth in the Western U.S.;
· economic conditions in the Western U.S.;
· availability of generation capacity throughout the Western U.S.;
· the extent of electric utility restructuring in Arizona, California and other Western states;
· FERC regulation of wholesale energy markets;
· availability of hydropower;
· transmission constraints; and
· environmental regulations and the cost of compliance.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Western Energy Markets, for additional discussion of TEP’s wholesale marketing activities.
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GENERATING AND OTHER RESOURCES
At December 31, 2006, TEP owned or leased 2,194 MW of net generating capability, as set forth in the following table:
(1) Leased assets.
(2) Excludes 719 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2006, total owned capacity was 1,658 MW and leased capacity was 536 MW.
Springerville Generating Station
Springerville Unit 1 is leased by TEP. The Springerville Generating Station also includes the Springerville Coal Handling Facilities and the Springerville Common Facilities.
The terms of the Springerville Unit 1 Leases, which include a 50% interest in the Springerville Common Facilities, expire in 2015, but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back its remaining 50% interest in the Springerville Common Facilities. The terms of the Springerville Common Facilities Leases expire in 2017 and 2021, but have a fixed price purchase provision. In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in 2015, but have a fixed price purchase provision.
Since entering into the Springerville leases, TEP has purchased a 14% equity ownership in the Springerville Unit 1 Leases and a 13% equity ownership in the Springerville Coal Handling Facilities Leases.
Sundt Generating Station
The Sundt Generating Station 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.
Sundt Unit 4 is leased by TEP. The terms of the Sundt Lease expire in 2011, but have optional fair market value renewal and purchase provisions.
See Note 8 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, and Capital Lease Obligations, 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 and Sundt leases.
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Luna Energy Facility
The Luna Energy Facility (Luna), located in southern New Mexico, is a 570 MW combined cycle plant and was completed in April 2006. TEP’s one-third share of the plant’s capacity is 190 MW. Luna allows TEP to displace some of its less efficient gas-fired generation and purchased power requirements and to make additional short-term energy sales in the wholesale market. TEP’s total investment of $49 million was funded with internal cash.
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. Finally, TEP may purchase energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when it is more economical than generating its own energy.
TEP is a member of various regional reserve sharing, reliability and power sharing organizations. 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.
Springerville Units 3 and 4
In conjunction with the expansion of the Springerville Generating Station, TEP entered into a contract to purchase up to 100 MW of capacity of system resources from Tri-State Generation and Transmission Association (Tri-State), which leases 100% of the 400 MW Springerville Unit 3 from a financial owner. In May 2006, SRP announced its intention to build Springerville Unit 4, a 400 MW coal-fired plant at the Springerville site. Under certain conditions, TEP would be required to purchase 100 MW of Unit 4 capacity from SRP. See Item 7. - Management’s Discussion and Analysis of Financial Condition. Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units and 4.
Peak Demand and Resources
(1) Other Resources include firm power purchases and interruptible retail and wholesale loads.
Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand has grown at an average annual rate of approximately 6% from 2002 to 2006.
The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s 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 maintains a minimum reserve margin in excess of 7% to comply with reliability criteria set forth by the Western Electricity Coordinating Council. TEP’s actual reserve margin in 2006 was 8%.
Forecasted retail peak demand for 2007 is approximately 2,476 MW, compared with actual peak demand of 2,365 MW in 2006. Except for certain peak hours during the summer, TEP believes it will have sufficient resources to meet expected demand in 2007 with its existing generation capacity and power purchase agreements.
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Future Generating Resources
TEP will continue to add peaking resources to serve the Tucson area as needed based upon our forecasts of retail and firm wholesale load, as well as statewide transmission infrastructure. TEP currently forecasts that it may need additional peaking resources of 150 MW in 2015.
FUEL SUPPLY
Fuel Summary
Fuel cost and usage information is provided below on a delivered to the boiler basis:
Coal
TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado. The majority of its coal supplies are purchased under long-term contracts, which result in more predictable prices. The average cost per ton of coal, including transportation for 2006, 2005, and 2004 was $32.36, $32.43, and $30.20, respectively.
(A) Substantially all of the suppliers’ mining leases extend at least as long as coal is being mined in economic quantities.
TEP Operated Generating Facilities
TEP is the sole owner (or lessee) and operator of the Springerville Units 1 and 2 and Sundt Unit 4 Generating Stations. The coal supplies for the 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 Units 1 and 2 for their presently estimated remaining lives.
The coal supply agreement for Sundt Unit 4 expired on December 31, 2006. On December 28, 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through 2008. The coal supplies are transported approximately 1,300 miles by railroad from Colorado. The cost of coal and transportation under the new agreements will increase approximately 60%, primarily due to significantly higher rail costs. TEP expects to pay approximately $20 million annually, compared with approximately $14 million annually under the old agreement, however the total amount paid under these agreements depends on the number of tons of coal purchased and transported.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations and Note 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.
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Generating Facilities Operated by Others
TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan. These are mine mouth generating stations located adjacent to the coal reserves. 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 lives of the stations.
Natural Gas Supply
TEP typically uses generation from its facilities fueled by natural gas and purchased power, in addition to energy from its coal-fired facilities, to meet the summer peak demands of its retail customers and 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 purchased power and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs from the Permian Basin, and purchased power in the spot and short-term markets.
TEP entered into a Gas Procurement Agreement with Southwest Gas Corporation (SWG) in 2001, with a primary term of five years. Starting January 1, 2006, interim supply terms were put into place on a month-to-month basis until terminated by either party with 30 days’ notice and did not include a minimum volume obligation. SWG provided notice to TEP to terminate this agreement effective February 28, 2007. TEP is currently negotiating a new contract and tariff terms with SWG for supply to its Tucson gas plants starting March 1, 2007, as well as evaluating other supply options. TEP does not expect any gas supply disruptions to its plants.
TEP purchased gas transportation for Luna from El Paso Natural Gas (EPNG) from the Permian basin to the plant site. The initial term of this agreement is from February 2006 to January 2009, with rights of first refusal for continuation thereafter.
WATER SUPPLY
The Four Corners region of New Mexico, where the San Juan and Four Corners Generating Stations are located, experienced drought conditions in 2002 through 2004 that could have affected the water supply for these plants. TEP has a 50% ownership interest in each of San Juan Units 1 and 2 (322 MW capacity) and a 7% ownership interest in each of Four Corners Units 4 and 5 (110 MW capacity). In future years, drought conditions may affect the water supply of the plants if adequate moisture is not received in the watershed that supplies the area. The operating agents for San Juan and Four Corners have negotiated supplemental water contracts with BHP Billiton and the Jicarilla Apache Nation to assist the generating plants in meeting their water requirements in the event of a shortage.
Drought conditions within the southwestern region, combined with increased water usage in Arizona, Nevada and Southern California, have caused water levels to recede at Lake Powell, which supplies operating water for the Navajo Generating Station. TEP has a 7.5% ownership interest in Navajo Units 1, 2 and 3 (168 MW capacity). The operating agent for Navajo, along with the other plant owners, are evaluating options to ensure adequate water supply is available in the event drought conditions adversely affect the water level at Lake Powell.
TRANSMISSION ACCESS
TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers. TEP is taking steps to increase the capacity and reliability of its transmission and distribution system. In 2004, TEP completed a 500 kV connection that increased its energy import capability from the region, allowing TEP to decrease the use of its less efficient gas generating units in favor of more economical purchases of energy in the wholesale market. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability and efficiency of its existing transmission and distribution systems.
Tucson to Nogales Transmission Line
TEP and UNS Electric are parties to a project development agreement for the joint construction of a 62-mile transmission line from Tucson to Nogales, Arizona. The project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona.
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In 2002, the ACC approved the location and construction of the proposed 345-kV transmission line along the Western Corridor route subject to a number of conditions, including obtaining all required permits from state and federal agencies. TEP is currently seeking approvals for the project from the Department of Energy (DOE), the U.S. Forest Service, the Bureau of Land Management, and the International Boundary and Water Commission.
The DOE has completed a Final Environmental Impact Statement (EIS) for the project in which it would accept any of the routes in the EIS but the U.S. Forest Service has indicated the Central route as its preferred alternative, rather than the Western Corridor route.
Based on the alternative proposals and passage of time since it approved the location of the line, the ACC, in 2005, ordered TEP to review the status of electric service reliability in Nogales, Arizona and the need for the 345-kV transmission line. The ACC also indicated that it would review any new information regarding the location of the proposed transmission line.
In 2005, an Administrative Law Judge (ALJ) for the ACC issued a recommended opinion and order reaffirming the ACC’s original position requiring the construction of the Tucson to Nogales transmission line. After a hearing on the issue in February 2006, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona. TEP expects the ALJ to issue, and the ACC to address, an amended recommended opinion and order related to the Nogales transmission line in 2007.
RATES AND REGULATION
The FERC and the ACC regulate portions of TEP’s utility accounting practices and electricity rates. The FERC regulates the terms and prices of TEP’s transmission services and wholesale electricity sales. In 1996, TEP filed a tariff at FERC governing the rates, terms and conditions of open access transmission services. In 1997, TEP was granted a FERC tariff to sell power at market based rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.
State
Historically, the ACC determined TEP’s rates for retail sales of electric energy on a “cost of service” basis, which was designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable rate of return on TEP’s “fair value rate base.” Fair value rate base was generally determined by reference to the original cost and the reconstruction 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 increased rate base and depreciation and retirements of utility plant reduced rate base.
Settlement Agreement
In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Rates, for more information.
Arizona Court of Appeals Decision Invalidating Certain Retail Electric Competition Rules
In 2004, an Arizona Court of Appeals decision held invalid certain portions of the ACC rules on retail competition and related market pricing. Based on this decision, we expect that the ACC will address the competition rules in an administrative proceeding. We cannot predict what changes, if any, the ACC will make to the competition rules. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Competition, for more information.
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TEP’S UTILITY OPERATING STATISTICS
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ENVIRONMENTAL MATTERS
Air and water quality, resource extraction, waste disposal and land use are regulated by federal, state and local authorities. TEP believes that all existing facilities are in compliance and will be in compliance with expected environmental regulations.
Federal Clean Air Act Amendments
The 1990 Federal Clean Air Act Amendments (CAAA), through the Acid Rain Program, requires reductions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions; this affects all of TEP’s generating facilities (except 142 MW of its internal combustion turbines).
TEP’s generating units affected by CAAA Phase II have been allocated SO2 Emission Allowances based on past operational history. Each allowance gives the owner the right to emit one ton of SO2. Generating units subject to CAAA Phase II must hold Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. TEP has Emission Allowances in excess of what is required to comply with the CAAA Phase II SO2 regulations. The excess results primarily from a higher removal rate of SO2 emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations. Potential changes to the allocation of SO2 allowances may impact these expectations in future years.
Title V of the CAAA requires that all of TEP’s generating facilities obtain more stringent air quality permits. All TEP facilities (including those jointly owned and operated by others) have obtained these permits. TEP received a new Title V permit for the Springerville generating station in 2006. TEP expects that a new Title V permit will be issued for the Sundt generating station in 2007. Because TEP has submitted a permit renewal application for the Sundt facility, under its Title V permit, TEP can continue to operate the plant. TEP must pay an annual emission-based fee for each generating facility subject to a Title V permit. These emission-based fees are included in the CAAA compliance expenses discussed below. The CAAA also requires multi-year studies of visibility impairment in specified areas and studies of hazardous air pollutants. The results of these studies will impact the development of future regulation of electric utility generating units.
Mercury Emissions
In 2005, the EPA adopted regulations relating to mercury emissions requiring states to develop rules for implementing federal requirements. Arizona adopted its mercury emission limits in 2007 and TEP must meet these limits by 2013. TEP is analyzing the potential impact of the Arizona regulations on its operations but does not expect the capital costs to exceed $5 million.
TEP is also monitoring the New Mexico and Navajo Nation mercury emission regulations affecting plants for which TEP has an ownership share. Until these state procedures are adopted, TEP cannot determine if it will be significantly affected.
Greenhouse Gas Emissions
Federal, state and local legislative and regulatory bodies are considering the regulation of greenhouse gas emissions. At this time, we do not know whether any such regulations will be adopted, the scope of such regulations or how any such regulations could affect our operations.
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Regional Haze
The EPA's Regional Haze Rule requires states to develop plans to restore visibility in Federal Class I Areas (such as parks, monuments and wilderness areas) to their natural conditions by 2064. State plans must be submitted to the EPA in December 2007, could require pollution control upgrades at some of TEP's power plants. The level of control required, if any, will not be known until the state plans are submitted and approved by EPA. If required, controls would need to be in place by 2013 or later.
TEP may incur additional costs to comply with recent and future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.
State Regulations
Arizona and New Mexico have adopted regulations restricting the emissions from existing and future coal, oil and gas-fired plants. TEP believes that all existing generating facilities are in compliance with all existing state regulations. These regulations are in some instances more stringent than those adopted by the EPA. The principal generating units of TEP are located relatively close to national parks, monuments, wilderness areas and Indian reservations. These areas have relatively high air quality and TEP could be subject to control standards that relate to the “prevention of significant deterioration” of visibility and tall stack limitation rules. See Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies, TEP Contingencies, Litigation and Claims Related to San Juan Generating Station.
In October 2006, the ACC approved new Renewable Energy Standard and Tariff rules (REST rules) designed to require TEP, UNS Electric and other affected utilities to generate 15% of their total energy requirements from renewable energy technologies by 2025. To offset the increased costs of meeting the more aggressive standard, the REST rules allow a change in the existing Environmental Portfolio Surcharge. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, TEP, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff, for more information.
Capital and Operating Costs
TEP capitalized $1 million in 2006, $1 million in 2005 and $9 million in 2004 in construction costs to comply with environmental requirements and expects to capitalize $18 million in 2007 and $42 million in 2008. The increase in environmental capital expenditures in 2007 and 2008 is due primarily to pollution control upgrades to be made at San Juan.
TEP recorded expenses of $10 million in 2006, $11 million in 2005 and $9 million in 2004 related to environmental compliance, including the cost of lime used to scrub the stack gas. TEP expects environmental expenses to be $11 million in 2007. TEP may incur additional costs to comply with recent and future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may result in a reduction in operating efficiency.
In order to meet Title V permit requirements in connection with the construction of Springerville Unit 3, the Unit 3 project paid approximately $90 million for upgrades to pollution control equipment on Springerville Units 1 and 2 and common facilities. See Note 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, Resolution of Springerville Generating Station Complaint.
UNS GAS
SERVICE TERRITORY AND CUSTOMERS
UNS Gas is a gas distribution company serving approximately 145,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in Southeast Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 773,000 in 2006.
UNS Gas’ customer base is primarily residential. Total revenues derived from residential customers were approximately 61% in 2006, while sales to other retail customer classes accounted for approximately 30% of total revenues. Approximately 9% of total revenues in 2006 were derived from gas transportation services and a Negotiated Sales Program (NSP). UNS Gas supplies natural gas transportation service to the 600 MW Griffith Power Plant located near Kingman, Arizona, under a 20-year contract which expires in 2021. UNS Gas also supplies natural gas to some of its large transportation customers through an NSP approved by the ACC. One half
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of the margin earned on these NSP sales is retained by UNS Gas, while the other half benefits retail customers through a credit to the purchased gas adjustor (PGA) mechanism which reduces the gas commodity price.
GAS SUPPLY AND TRANSMISSION
UNS Gas has a natural gas supply and management agreement with BP Energy Company (BP). Under the contract, BP manages UNS Gas’ existing supply and transportation contracts and its incremental requirements. The initial term of the agreement expired in August 2005, but the agreement automatically extends for one year on an annual basis unless either party provides 180 days notice of its intent to terminate. No termination notice has been tendered by either party. The market price for gas supplied by BP will vary based upon the period during which the commodity is delivered. UNS Gas hedges its gas supply prices by entering into fixed price forward contracts at various times during the year to provide more stable prices to its customers. These purchases 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 buys most of the gas it distributes from the San Juan Basin in the Four Corners region. The gas is delivered on the El Paso and Transwestern interstate pipeline systems. UNS Gas has firm transportation agreements with EPNG and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its 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, Arizona, and also delivers gas to UNS Gas’ facilities serving the Griffith Power Plant in Mohave County.
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
The ACC regulates UNS Gas with respect to retail gas rates, the issuance of securities, and transactions with affiliated parties. UNS Gas’ retail gas rates include a monthly customer charge, a base rate charge for delivery services and the cost of gas (expressed in cents per therm), and a PGA.
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 gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or returned to customers through the PGA mechanism. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, for more information.
General Rate Case
In July 2006, UNS Gas filed a general rate case to recover the costs related to serving its growing customer base. UNS Gas also requested modifications to its PGA mechanism to help address problems posed by volatile gas prices. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Rates, for more information.
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 believes that all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.
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UNS ELECTRIC
SERVICE TERRITORY AND CUSTOMERS
UNS Electric is an electric transmission and distribution company serving approximately 93,000 retail customers in Mohave and Santa Cruz Counties. These counties had a population of approximately 240,000 in 2006.
UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 2006 was 417 MW.
POWER SUPPLY AND TRANSMISSION
Power Supply
UNS Electric has a full requirements power supply agreement with Pinnacle West Marketing and Trading (PWMT) which expires in May 2008. The agreement obligates PWMT to supply all of UNS Electric’s power requirements at a fixed price. Payments under the contract are usage based, with no fixed customer or demand charges.
UNS Electric 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 68 MW of peaking resources. This includes a 20 MW unit installed in 2006. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas. Under the PWMT agreement, Valencia will be dispatched by PWMT when needed for local reliability or when it is economic relative to other PWMT resources.
Transmission
UNS Electric imports the power it purchases from PWMT into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric is currently negotiating a network transmission service agreement to replace its primary transmission capacity agreement with WAPA for the Parker-Davis system that expires in February 2008. The new agreement is expected to have no expiration date and be effective by the end of the first quarter of 2007. UNS Electric also has a long-term electric point to point transmission capacity agreement with WAPA for the Southwest Intertie system that expires in 2011.
UNS Electric plans to upgrade its existing 115 kV transmission line over time to improve the reliability of service in Santa Cruz County.
Future Power Supply
UNS Electric is in the process of evaluating and securing power supply resources to ensure adequate resources are in place when its PWMT agreement expires in May 2008. In 2006, UNS Electric entered into various power supply agreements for periods for one to five years beginning in June 2008. In addition, as part of its general rate case filing, UNS Electric included a proposal to purchase the 90 MW Black Mountain Generating Station (BMGS) in 2008, which is under development by UED. As of February 23, 2007, UNS Electric had 28% of its total expected resource needs for June 2008; this includes purchased power contracts as well as generating assets. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resources, Contractual Obligations and Other, UED, below for more information.
RATES AND REGULATION
UNS Electric is regulated by the ACC with respect to retail electric rates, quality of service, the issuance of securities, and transactions with affiliated parties, and by the FERC with respect to wholesale power contracts and interstate transmission service. UNS Electric’s retail electric rates include a purchased power and fuel adjustment clause (PPFAC), which allows for UNS Electric to recover the actual costs of its power purchases.
General Rate Case
In December 2006, UNS Electric filed a general rate case to recover the costs related to serving its growing customer base. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Rates, for more information.
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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 all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.
Like TEP, UNS Electric is subject to the ACC’s REST rules. See TEP Electric Utility Operations, Environmental Matters, State Regulation, above.
OTHER
UED
UED facilitated the expansion of the Springerville Generating Station and is currently developing the 90 MW gas-fired BMGS in Kingman, Arizona. In October 2006, UED purchased two electric generating gas turbines that will be part of the BMGS. Completion of the project is estimated to occur in May 2008. Pending ACC approval, BMGS is expected to be used as a resource for UNS Electric.
Millennium Investments
Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies. At December 31, 2006, Millennium’s assets represented 3% of UniSource Energy’s total assets. UniSource Energy has ceased making loans or equity contributions to Millennium. We anticipate that the funding for Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other, Liquidity and Capital Resources.
Consolidated Millennium Investments
Southwest Energy Solutions, Inc. (SES), a wholly-owned Millennium subsidiary, provides electrical contracting services in Arizona to commercial, industrial and governmental customers in both high voltage and inside wiring capacities. SES also provides meter reading services to TEP and UNS Electric.
Millennium Environmental Group, Inc. (MEG), a wholly-owned Millennium subsidiary, manages and trades emission allowances and other environmental-related products, including derivative instruments. MEG is in the process of winding down its activities and does not anticipate engaging in any significant new activities.
Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary of Millennium, has been inactive since 2001.
Equity Method Millennium Investments
Haddington Energy Partners II, LP (Haddington) is a limited partnership that funds energy-related investments. A member of the UniSource Energy Board of Directors has an investment in Haddington, has a non-management advisory role with respect to Haddington Ventures, LLP, a limited partnership that is the general partner of Haddington, and also is a voting member of the investment committee that makes decisions with respect to investments in Haddington. Millennium committed $15 million in capital, excluding fees, to Haddington in exchange for approximately 31% ownership. As of December 31, 2006, Millennium had invested $15 million in Haddington since its inception, and received distributions of $15 million. Millennium has no remaining commitment to Haddington. Millennium’s total investment balance in Haddington at December 31, 2006 was $5 million.
Valley Ventures III, LP (Valley Ventures) is a venture capital fund that focuses on investments in information technology, microelectronics and biotechnology, primarily within the southwestern U.S. Another member of the UniSource Energy Board of Directors was a general partner of the company that manages the fund until January 1, 2006, at which time the Board member terminated his role and interest as a general partner but maintained a non-voting financial interest in the company. Millennium committed $6 million, including fees, to the fund and owns approximately 15% of the fund. As of December 31, 2006, Millennium has not received any distributions from Valley Ventures and had $1 million remaining on this commitment, which is expected to be funded over the next two to three years. Millennium’s total investment balance in Valley Ventures at December 31, 2006 was $4 million.
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Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 MW of coal-fired generation in the Sabinas region of Coahuila, Mexico. Sabinas also owns 19.5% of Minerales de Monclova, S.A. de C.V. (Mimosa). Mimosa is an owner of coal and associated gas reserves and a supplier of metallurgical coal to the Mexican steel industry and thermal coal to the major electric utility in Mexico. Millennium owns 50% of Sabinas. Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates own the remaining 50%. UniSource Energy’s Chairman, President and Chief Executive Officer is a member of the Board of Directors of AHMSA. Since 1999, both AHMSA and Mimosa are parties to a suspension of payments procedure, under applicable Mexican law, which is the equivalent of a U.S. Chapter 11 proceeding. Under certain circumstances, Millennium has the right to sell (a put option) its interest in Sabinas to an AHMSA affiliate for $20 million plus any accrued service fee. Millennium's remaining investment balance in Sabinas at December 31, 2006 was $14 million.
Discontinued Operations - Global Solar Energy
On March 31, 2006, Millennium completed the sale of its interest in Global Solar. The operating results of Global Solar are reported as discontinued operations.
EMPLOYEES (As of December 31, 2006)
TEP had 1,260 employees, of which approximately 54% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A collective bargaining agreement between the IBEW and TEP was ratified in January 2006 and expires in January 2009.
UNS Gas had 214 employees, of which 126 employees were represented by IBEW Local No. 1116 and employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2009 and February 2010, respectively.
UNS Electric had 164 employees, of which 28 employees were represented by the IBEW Local No. and 109 employees were represented by the IBEW Local No. 769. The existing agreement with the IBEW Local No. 387 expires in February 2010 and the agreement with IBEW Local No. 769 expires in July 2007.
SES had 258 employees, of which approximately 96% are represented by unions. Of the employees represented by unions, 224 are represented by IBEW Local No. 1116, by IBEW Local No. 769 and 13 by IBEW Local No. 570. The existing agreements expire as follows: IBEW Local No. 1116, January 2009; IBEW Local No. 769, July 2007; and IBEW Local No. 570, May 2009.
SEC REPORTS AVAILABLE ON UNISOURCE ENERGY’S WEBSITE
UniSource 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 practicable after they electronically file them with, or furnish them to, the Securities and Exchange Commission (SEC). These reports are available free of charge through UniSource Energy’s website address: http://www.uns.com. A link from UniSource Energy’s website to these SEC reports is accessible as follows: At the UniSource Energy main page, select Investor Relations from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page. UniSource Energy’s code of ethics, and any amendments made to the code of ethics, is also available on UniSource Energy’s website.
Information contained at UniSource Energy’s website is not part of any report filed with the SEC by UniSource Energy or TEP.
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ITEM 1A.
ITEM 1A. - RISK FACTORS
The business and financial results of UniSource 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.
Regulatory and other restrictions limit the ability of TEP, UNS Gas and UNS Electric to make distributions to UniSource Energy.
UniSource Energy is a holding company that 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 or transferring funds or issuing securities without ACC approval;
·
The Federal Power Act restricts electric utilities’ ability to pay dividends out of funds that are properly included in their capital account. 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. However, the FERC could attempt to stop TEP from paying further dividends or could seek to impose additional restrictions on the payment of dividends; and
·
TEP, UNS Gas and UNS Electric must be in compliance with their respective debt agreements to make dividend payments to UniSource Energy.
UniSource Energy does not expect to receive distributions from UNS Gas or UNS Electric before 2008 due to the need to apply internally generated funds to the growth of these businesses.
TEP’s retail rates are capped through 2008, which could negatively impact TEP’s results of operations, net income and cash flows.
TEP’s current retail rates were established under a Settlement Agreement approved by the ACC in 1999. Under the Settlement Agreement, TEP’s rates are capped until December 31, 2008. Operational failures or unscheduled outages at TEP’s generating stations, especially during peak seasons, could result in unanticipated power purchases which could significantly increase the cost of serving TEP’s retail load. Operational failures or damage to TEP’s facilities, from storms or other events, could result in increased operating and capital expenses.
In the event that any power purchase, natural gas or coal costs, operation and maintenance or other expenses increase, TEP could be adversely affected unless it were able to find ways of offsetting these increased costs with other cost reductions or increases in income and cash flow or otherwise seek rate recovery of such increased costs under emergency provisions of the Settlement Agreement. TEP may not be able to recover such costs.
Uncertainty exists as to what methodology the ACC will use to set TEP’s retail rates after December 31, 2008, which could negatively impact TEP’s results of operations, net income and cash flows.
There is disagreement between the participants in TEP’s regulatory proceedings about what is to happen to the rates TEP charges for generation service after December 31, 2008. TEP believes the Settlement Agreement requires it to charge market-based generation service rates while other participants, including ACC staff, disagree.
The Settlement Agreement also requires TEP to record and amortize a $450 million transition recovery asset (TRA) and collect the balance from customers though a Fixed Competition Transition Charge (Fixed CTC). Based on current projections of retail sales, the TRA is expected to be fully amortized by mid-2008. The Fixed CTC currently produces revenues of slightly less than one cent per kWh sold, or approximately $90 million annually. If TEP is required to reduce its retail rates by the amount of the Fixed CTC, and is not allowed to charge market rates for its generation services or to adjust other rate components to reflect a higher cost of service, TEP’s retail revenues will decrease approximately 12% relative to 2006 revenues from current retail rates.
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Restrictions on rate increases and the ability to recover fuel costs at UNS Gas could negatively impact its liquidity, cash flows and net income.
UNS Gas filed a general rate case in July 2006. Under the terms of an ACC order, any resulting rate increase may not become effective until August 1, 2007.
UNS Gas is subject to operational risks, including operational failures or damage to facilities which could result in unplanned operation, maintenance and capital expenditures. UNS Gas could be adversely affected unless it was able to find ways of offsetting these increased costs.
UNS Gas has an automatic gas price adjustment mechanism, known as the Purchased Gas Adjustor (PGA), through which increases or decreases in the cost of gas can be passed on to customers. The PGA is subject to a cap on how much the factor can change in a 12-month period and anything above the cap must be approved by the ACC.
In 2006, the cost of gas represented more than 77% of UNS Gas’ total operating costs. Natural gas prices may fluctuate substantially over relatively short periods of time and expose UNS Gas to commodity price risks to the extent they cannot be collected from customers in a timely manner.
If UNS Gas is unable to recover its fuel costs or other costs of providing service in a timely manner, its liquidity could be adversely affected and it may be more difficult for UNS Gas to satisfy its obligations, including purchasing and paying for gas. In addition, it may be more difficult for UNS Gas to comply with the obligations and restrictive covenants of its debt agreements, which limit its ability to borrow money, and could result in an event of default.
Restrictions on rate increases and the ability to recover purchased power and fuel costs at UNS Electric could negatively impact its liquidity, cash flows and net income.
UNS Electric filed a general rate case in December 2006. Under the terms of an ACC order, any resulting rate increase may not become effective until August 1, 2007.
Operational failures or damage to UNS Electric’s facilities from storms or other events could result in increased operating and capital expenditures. UNS Electric could be adversely affected unless it was able to find ways of offsetting these increased costs.
The expiration of UNS Electric’s power supply agreement will require UNS Electric to find alternate sources for its energy needs, which may not be recovered through rates.
UNS Electric has a full requirements power supply agreement for 100% of its customers’ energy needs that expires May 2008. UNS Electric pays a fixed price per MWh for the power it purchases under the agreement. In 2006, UNS Electric sold approximately 1.6 million MWh to its retail customers. In 2008, UNS Electric will need a replacement source of energy for its customer base, which grew at 4% in 2006.
UNS Electric has a purchased power and fuel adjustment clause (PPFAC) through which increases or decreases in the cost of power and fuel can be passed on to customers. The cost of UNS Electric’s existing power supply agreement is being fully recovered through the PPFAC. The ACC must approve any change to the PPFAC.
UNS Electric may be required to post margin under its power supply agreements which could negatively impact its liquidity.
UNS Electric is in the process of evaluating and securing power supply resourced to replace the full requirements power supply agreement which expires in May 2008. The agreements under which UNS Electric contracts for such resources include requirements to post credit enhancement in the form of cash or letters of credit under certain circumstances, including changes in market prices which affect contract values, or a change in the creditworthiness of UNS Electric.
In order to post such credit enhancement, UNS Electric would have to use available cash, draw under its revolving credit agreement, or issue letters of credit under its revolving credit agreement. As of February 23, 2007, the maximum amount that UNS Electric may use under its revolving credit facility is $30 million (to be increased to $45 million upon approval of a matter pending before the ACC).
K-17
TEP’s, UNS Gas’ and UNS Electric’s revenues, results of operations and cash flows are seasonal, and are subject to weather conditions, economic conditions and customer usage patterns, which are beyond the Company’s control.
TEP typically earns the majority of its operating revenue and net income in the third quarter because of higher air conditioning usage by its retail customers due to hot summer weather. Furthermore, TEP typically reports limited net income in the first quarter because of relatively mild winter weather in its retail service territory. UNS Gas’ peak sales occur in the winter; UNS Electric’s peak sales occur in the summer. Cool summers or warm winters may adversely affect the utility subsidiaries’ operating revenues and net income by reducing sales.
Changes in federal energy regulation may affect TEP, UNS Gas and UNS Electric’s results of operations, net income and cash flows.
TEP, UNS Gas and UNS Electric are subject to 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. UniSource Energy’s utility subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (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.
Deregulation or restructuring of the electric utility industry may result in increased competition resulting in an erosion of TEP and UNS Electric’s retail customer base and a reduction in TEP’s wholesale revenues.
In 1999, the ACC approved rules providing a framework for the introduction of retail electric competition in Arizona. As a result of the energy crisis in California in 2000 and 2001 and the volatility of natural gas prices, the competitive retail market in Arizona that was anticipated in 1999 did not materialize. In addition, a 2005 Arizona Court of Appeals ruling held certain portions of the ACC’s retail competition rules invalid.
Currently, none of TEP or UNS Electric’s customers are receiving energy from other providers; however we cannot predict if retail competition will enter the Arizona market.
Competition in wholesale markets has greatly escalated due to increased participation by utilities, non-utility generators, independent power producers and other wholesale power marketers and brokers. Since 2001, electric generating capacity in Arizona has increased 61% to 25,600 MW, of which approximately 9,700 MW is from gas-fired generators.
Increased competition combined with increased supply and fewer creditworthy counterparties could reduce the prices at which TEP sells electricity in the wholesale market. In 2006, TEP’s wholesale revenues were $188 million or 19% of TEP’s total revenues.
UniSource Energy and its subsidiaries have a substantial amount of indebtedness which could adversely affect its business and results of operations.
UniSource Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 2006, total debt (including capital lease obligations) to total capitalization for UniSource Energy and its subsidiaries was 72%. The substantial amount of indebtedness of UniSource Energy and its subsidiaries could:
·
require UniSource Energy and its subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on its debt, which could reduce the funds available for working capital, capital expenditures, acquisitions and other general corporate purposes;
·
make UniSource Energy and its subsidiaries more vulnerable to restrictions imposed by new governmental regulations as well as changes in general economic, industry and competitive conditions;
·
limit UniSource Energy and its subsidiaries’ ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of its business strategy or other purposes;
·
limit the ability of the subsidiaries to pay dividends to UniSource Energy; and
·
make it more difficult for UniSource Energy and its subsidiaries to comply with the obligations of its debt instruments, and any failure to comply with the obligations of any debt instruments, including financial and other restrictive covenants, could result in an event of default under the agreements.
K-18
The terms of UniSource Energy’s and its subsidiaries’ existing debt instruments and future debt instruments may restrict UniSource Energy’s current and future operations, particularly the ability to respond to changes in its business or to take certain actions.
The UniSource Energy Credit Agreement, the TEP Credit Agreement and other existing debt instruments contain a number of restrictive covenants that impose significant operating and financial restrictions on UniSource Energy, including restrictions on the ability to engage in acts that may be in UniSource Energy’s best long-term interests. The TEP Credit Agreement includes financial covenants, including requirements to maintain certain minimum cash coverage ratios and not to exceed certain maximum total leverage ratios. The UniSource Credit Agreement contains similar financial covenants.
The operating and financial restrictions and covenants in UniSource Energy’s and its subsidiaries’ existing debt agreements and any future financing agreements may adversely affect UniSource Energy’s ability to finance future operations or capital needs or to engage in other business activities.
The cost of renewing or purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power, could adversely affect TEP’s results of operations, net income and cash flows.
TEP, under separate sale and leaseback arrangements, leases the following generation facilities:
·
Springerville Unit 1;
·
Sundt Unit 4;
·
Springerville Coal Handling Facilities; and
·
Springerville Common Facilities.
.
TEP may renew the leases or purchase the assets when the leases expire at various times between 2011 and 2021. The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, whereas fixed purchase price options exist for the coal handling and common facilities leases. Upon expiration of the 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 Springerville Units 3 and 4 owners to purchase such facilities, and the owners of Springerville Units 3 and 4 have the obligation to purchase from TEP a 14% and 17% interest, respectively, in these facilities.
UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations which may increase their cost of operations or expose them to environmentally-related litigation and liabilities.
UniSource Energy’s utility subsidiaries are subject to numerous federal, state and local environmental regulations affecting present and future operations, including regulations regarding air emissions, water quality, wastewater discharges, solid waste and hazardous waste. Many of these regulations arise from TEP’s use of coal as the primary fuel for energy generation.
Existing environmental regulations may be revised or new regulations may be adopted or become applicable to UniSource Energy’s utility subsidiaries. Compliance with existing or new environmental laws and regulations can result in increased capital, operating and other costs. The U.S. Congress is considering the regulation of greenhouse gas emissions. At this time, we do not know whether any such regulations will be adopted, the scope of such regulations or how any such regulations could affect our operations.
TEP is also contractually obligated to pay a portion of its environmental reclamation costs at generating stations in which it has a minority interest and possibly 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.
TEP may be required to redeem significant amounts of its outstanding tax-exempt bonds.
TEP has financed a portion of its utility plant assets with tax-exempt bonds for which the exemption from income taxes requires that the financed facilities be used for the local furnishing of electric energy. Approximately $359 million of these bonds were outstanding as of December 31, 2006. Various events, including, in certain
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circumstances, the formation of an RTO or an independent system operator, asset divestitures, changes in tax laws or changes in system operations, could require TEP to redeem or defease some or all of these bonds which would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater principal amount.
TEP may not be permitted to construct a Tucson to Nogales transmission line and TEP or UNS Electric may be required to find alternate ways to improve reliability in UNS Electric’s Santa Cruz service area.
In 2001, TEP entered into an agreement to build an approximately 60-mile transmission line from Tucson to Nogales, Arizona, in response to an order from the ACC to improve reliability to UNS Electric’s retail customers in Nogales. Required regulatory approvals have delayed the construction of the transmission line, and in 2005, the ACC initiated proceedings to review the status of service in Nogales and need for the 345-kV line.
If TEP does not receive required approvals or if we abandon the project, it may be required to expense a portion of the $11 million it has incurred through December 31, 2006, in land acquisition, engineering and environmental expenses. In such an event, TEP or UNS Electric may be required to make additional expenditures to improve reliability. In the event TEP or UNS Electric are not able to recover such expenditures, their results of operations and net income could be adversely affected.
ITEM 2.
ITEM 2. - PROPERTIES
TEP PROPERTIES
TEP’s transmission facilities, located in Arizona and New Mexico, transmit electricity 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 - Generating and Other Resources). The transmission system is interconnected at various points in Arizona and New Mexico with a number of regional utilities. TEP has arrangements with approximately 120 companies to interchange generation capacity and transmission of energy.
As of December 31, 2006, TEP owned or participated in an overhead electric transmission and distribution system consisting of:
·
circuit-miles of 500-kV lines;
·
1,098 circuit-miles of 345-kV lines;
·
circuit-miles of 138-kV lines;
·
circuit-miles of 46-kV lines; and
·
2,631 circuit-miles of lower voltage primary lines.
The underground electric distribution system is comprised of 4,201 cable-miles. TEP owns approximately 60% of the poles on which the lower voltage lines are located. Electric substation capacity consisted of 101 substations with a total installed transformer capacity of 6,738,947 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 Resources Inc., a wholly-owned subsidiary of TEP (San Carlos), is not subject to the lien.
The electric generating stations (except as noted below), operating 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 public places, the public domain and 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 land parcels 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, respectively. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired easements and leases for transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP has also acquired easements for transmission facilities, related to San Juan, Four Corners, and Navajo, across the Zuni, Navajo and Tohono O’odham Indian Reservations. TEP, in conjunction with PNM and Phelps Dodge, 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 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):
·
coal handling facilities at Springerville;
·
a 50% undivided interest in the Springerville Common Facilities;
·
Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities; and
·
Sundt Unit 4 and related common facilities.
See Note 8 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, and Capital Lease Obligations 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, 2006, UNS Gas’ transmission and distribution system consisted of approximately 78 miles of steel transmission mains, 4,223 miles of steel and plastic distribution mains, and 148,432 customer service lines.
UNS Electric
As of December 31, 2006, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 236 circuit-miles of 69-kV transmission lines, and 3,432 circuit-miles of underground and overhead distribution lines. UNS Electric also owns 39 substations having a total installed capacity of 1,641,250 kilovolt amperes and the 65 MW Valencia plant.
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 public places, the public domain and 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.
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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ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Operations, for litigation related to ACC orders and retail competition.
We discuss other legal proceedings in Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies.
City of Tacoma
In June 2004, the City of Tacoma, Washington filed a lawsuit (City of Tacoma v. American Electric Power Services Corporation, et al. (U.S. District Ct. W.D. Wash.)) against TEP and various other electricity generators and marketers alleging that the defendants violated antitrust laws by colluding to affect the price of electricity in the Pacific Northwest from May 2000 through 2001. In September 2004, the case was transferred to the United States District Court for the Southern District of California. TEP, along with other defendants, filed a joint motion to dismiss, which was granted on February 11, 2005. The City of Tacoma appealed the dismissal to the Ninth Circuit and the appeal is now pending.
TEP believes these claims are without merit and intends to vigorously contest them.
ITEM 4.
ITEM 4. - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
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
UniSource Energy’s Common Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 23, 2007, the closing price was $38.31, with 11,314 shareholders of record. UniSource Energy did not purchase any shares of its Common Stock during the fourth quarter of 2006.
Dividends
UniSource Energy’s Board of Directors currently expects to continue to pay regular quarterly cash dividends on our Common Stock subject, however, to the Board’s evaluation of our financial condition, earnings, cash flows and dividend policy. On February 9, 2007, UniSource Energy’s Board of Directors indicated its desire to target, over the next several years, a dividend payout level of approximately 50% of net income.
TEP pays dividends on its common stock after its Board of Directors declares them. UniSource Energy is the sole shareholder of TEP’s common stock and relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends.
See Item 7.
Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Dividends on Common Stock.
Common Stock Dividends and Price Ranges
(1) UniSource Energy’s Common Stock price as reported in the consolidated reporting system.
On February 9, 2007, UniSource Energy declared a cash dividend of $0.225 per share on its Common Stock. The dividend will be paid March 14, 2007 to shareholders of record at the close of business February 20, 2007.
TEP declared and paid cash dividends to UniSource Energy of $62 million in 2006, $46 million in 2005 and $32 million in 2004.
Convertible Senior Notes
In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of our Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Financing Activities.
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(1) In 2003, Operating Revenues, Income Before Extraordinary Item and Accounting Change and Net Income include results from UES for the period from August 11, 2003 to December 31, 2003.
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(2) Net Income includes an after-tax loss for discontinued operations of $2 million in 2006, $5 million in 2005, $5 million in 2004, $7 million in 2003 and $13 million in 2002. Net income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005 and an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the implementation of FAS 143 in 2003.
(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 and expense on indebtedness.
See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations.
(1) Net Income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005 and an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the implementation of FAS 143 in 2003.
(2) 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 and expense on indebtedness.
Note: Disclosure of earnings per share information for TEP is not presented as the common stock of TEP is not publicly traded.
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See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations.
NON-GAAP MEASURES
Adjusted EBITDA
Adjusted EBITDA represents EBITDA excluding the cumulative effect of accounting change which is a non-cash item. EBITDA is earnings before interest, taxes, depreciation and amortization. Adjusted EBITDA is presented here as a measure of liquidity because it can be used as an indication of a company’s ability to incur and service debt and is commonly used as an analytical indicator in our industry. Adjusted EBITDA measures presented may not be comparable to similarly titled measures used by other companies. Adjusted EBITDA is not a measurement presented in accordance with United States generally accepted accounting principles (GAAP), and we do not intend Adjusted EBITDA to represent cash flows from operations as defined by GAAP. Adjusted EBITDA should not be considered to be an alternative to cash flows from operations or any other items calculated in accordance with GAAP or an indicator of our operating performance.
UniSource Energy and TEP believe Adjusted EBITDA, which is a non-GAAP financial measure, provides useful information to investors as a measure of liquidity. The most directly comparable GAAP measure to Adjusted EBITDA is Net Cash Flows from Operating Activities.
Adjusted EBITDA and Net Cash Flows from Operating Activities
Reconciliation of Adjusted EBITDA to Cash Flows from Operations
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(1) Adjusted EBITDA was calculated as follows:
Net Debt and Total Debt and Capital Lease Obligations - TEP
Net Debt represents the current and non-current portions of TEP’s long-term debt and capital lease obligations less investment in lease debt. We have subtracted investment in lease debt because it represents TEP’s ownership of the debt component of its own capital lease obligations. Net Debt measures may not be comparable to similarly titled measures used by other companies. Net Debt is not a measurement presented in accordance with GAAP and we do not intend Net Debt to represent debt as defined by GAAP. You should not consider Net Debt to be an alternative to debt or any other items calculated in accordance with GAAP. We believe Net Debt, which is a non-GAAP measure, provides useful information to investors as a measure of TEP’s debt and capital lease obligations.
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Reconciliation of Total Debt and Capital Lease Obligations to Net Debt
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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 UniSource Energy and its three primary business segments and includes the following:
·
outlook and strategies,
·
operating results during 2006 compared with 2005, and 2005 compared with 2004,
·
factors which affect our results and outlook,
·
liquidity, capital needs, capital resources, and contractual obligations,
·
dividends, and
·
critical accounting estimates.
UniSource Energy is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years. UES was established in 2003, when it acquired the Arizona gas and electric properties from Citizens. UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in Northern and Southern Arizona. Millennium has existing investments in unregulated businesses; however no new investments are planned at Millennium. UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to approval, is expected to provide energy to UNS Electric. We conduct our business in three primary business segments - TEP, UNS Gas and UNS Electric.
On March 31, 2006, Millennium sold its interest in Global Solar Energy, Inc. (Global Solar), its largest holding. At December 31, 2006, the investment in Millennium represented 3% of UniSource Energy’s Total Assets.
UNISOURCE ENERGY CONSOLIDATED
OUTLOOK AND STRATEGIES
Our financial prospects and outlook for the next few years will be affected by many competitive, regulatory and economic factors. Our plans and strategies include the following:
·
Efficiently manage our generation, transmission and distribution resources and seek ways to control our operating expenses while maintaining and enhancing reliability and profitability;
·
Expand TEP’s portfolio of generating and purchased power resources to meet growing retail energy demand and respond to wholesale market opportunities;
·
Expand UNS Electric’s portfolio of generating and purchased power resources to meet growing retail energy demand upon the expiration of the full requirements contract with PWMT;
·
Resolve the uncertainty surrounding TEP’s rates for generation service after 2008, while preserving TEP’s benefits under the Settlement Agreement;
·
Receive ACC approval of rate increases for UNS Gas and UNS Electric to provide adequate revenues to cover the rising cost of providing service to their customers;
·
Enhance the value of existing generation assets by working with Salt River Project to support the construction of Springerville Unit 4;
·
Enhance the value of TEP’s transmission system while continuing to provide reliable access to generation for TEP and UNS Electric’s retail customers and market access for all generating assets;
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·
Continue to develop synergies between UNS Gas,UNS Electric and TEP;
·
Improve capital structure; and
·
Promote economic development in our service territories.
To accomplish our goals, during 2007 we expect to spend the following on capital expenditures:
(1) Represents capital expenditures by UED related to the 90 MW BMGS to be constructed in Kingman, Arizona, in UNS Electric’s service area. The project is expected to be completed in 2008.
While we believe that our plans and strategies will continue to have a positive impact on our financial prospects and position, we recognize that we continue to be highly leveraged, and as a result, our access to the capital markets may be limited or more expensive than for less leveraged companies.
RESULTS OF OPERATIONS
Executive Overview
UniSource Energy recorded Income Before Discontinued Operations and Cumulative Effect of Accounting Change of $69 million in 2006, $52 million in 2005 and $51 million in 2004. Net Income of $67 million in 2006 includes a $2 million loss from discontinued operations; net income of $46 million in 2005 includes a $5 million loss from discontinued operations and a $1 million loss from the cumulative effect of an accounting change; and net income of $46 million in 2004 includes a $5 million loss from discontinued operations.
Compared With 2005
The improvement in UniSource Energy’s results in 2006 is due primarily to: the higher availability of TEP’s coal-fired generating plants; the start of commercial operations at Luna in April 2006; retail customer growth at TEP; interest savings related to various financing activities in 2005 and 2006; and the commencement of commercial operation of Springerville Unit 3 in August 2006. See Tucson Electric Power Company, Results of Operations, below, and Tucson Electric Power Company, Liquidity and Capital Resources, Financing Activities, below.
On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar in the future. In 2006, UniSource Energy recorded an after-tax loss of approximately $2 million related to the discontinued operations and disposal of Global Solar. See Other Non-Reportable Segments, Results of Operations, Discontinued Operations - Global Solar, below.
Compared With 2004
UniSource Energy’s results in 2005 were negatively impacted by planned and unplanned outages at several of TEP’s coal plants. One of TEP’s largest coal plants suffered a nearly month-long outage in August 2005, during a period when customer demand was high and energy prices were boosted by the impact of hurricane activity in the Gulf of Mexico. Higher natural gas prices and the cost of purchasing replacement power during the outage contributed to an 82% increase in TEP’s purchased power expense. See Tucson Electric Power Company, Results of Operations, below.
Also in 2005, UniSource Energy completed a financial restructuring, issuing $240 million of debt and using the proceeds to repay an inter-company note and infuse capital into its subsidiaries. TEP retired approximately $321 million of debt and capital lease obligations (net of proceeds received from TEP’s investment in lease debt). See
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Liquidity and Capital Resources, Financing Activities, below, and Tucson Electric Power Company, Liquidity and Capital Resources, Financing Activities, Bond Repurchases and Redemptions, below.
CONTRIBUTION BY BUSINESS SEGMENT
The table below shows the contributions to our consolidated after-tax earnings by our three business segments and Other net income (loss).
(1) Includes: UniSource Energy parent company expenses; in 2005 and 2006, UniSource Energy parent company interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement; in 2004 and in the first nine months of 2005, interest expense (net of tax) on the note payable from UniSource Energy to TEP; income and losses from Millennium investments and UED; and in 2004 costs associated with the proposed acquisition of UniSource Energy.
(2) Relates to the discontinued operations of Global Solar.
LIQUIDITY AND CAPITAL RESOURCES
UniSource Energy Consolidated Cash Flows
UniSource Energy’s consolidated cash flows are provided primarily from retail and wholesale energy sales at TEP, UNS Gas and UNS Electric, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load.
We use our available cash primarily to:
·
fund capital expenditures at TEP, UNS Gas and UNS Electric;
·
pay dividends to shareholders; and
·
reduce leverage.
The primary source of liquidity for UniSource Energy, the parent company, is dividends it receives from its subsidiaries, primarily TEP. Also, under our tax sharing agreement, our subsidiaries make income tax payments to UniSource Energy, which makes payments on behalf of the consolidated group. The table below provides a summary of the liquidity position of UniSource Energy on a stand-alone basis and each of its segments.
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(1) Currently, either UNS Gas or UNS Electric may borrow up to a maximum of $30 million, but the total combined amount borrowed cannot exceed $40 million. Upon ACC approval of the increase in the UNS Gas/UNS Electric Revolver, either borrower may borrow up to a maximum of $45 million so long as the combined amount borrowed does not exceed $60 million. The matter is pending before the ACC.
(2) Includes cash and cash equivalents at Millennium.
Executive Overview
Operating Activities
In 2006, net cash flows from operating activities were $283 million or $9 million higher than 2005. The increase is due primarily to: an increase in TEP’s cash receipts from electric retail and wholesale sales, net of fuel and purchased energy costs; higher UNS Gas retail revenues; and the wind down of activity at MEG; partially offset by a $32 million payment made to the IRS and state tax authorities related to a notice of a proposed adjustment to previously filed tax returns and an increase in federal and state extension and estimated tax payments.
Investing Activities
Net cash used for investing activities was $76 million higher in 2006 primarily due to: TEP’s purchase of a 14% equity interest in Springerville Unit 1 Lease; growth and maintenance of TEP’s electric system; utility system growth at UNS Gas and UNS Electric; the purchase of two gas turbines by UED; and TEP’s share of the construction costs of Luna.
Forecasted Capital Expenditures
Capital expenditures of $1.2 billion for 2007 through 2010 are expected to be $331 million, or 39% higher than forecasted amounts reported in 2006. This increase is the result of several factors including: higher material and construction costs; the need to increase high-voltage transmission capacity into TEP’s service territory; generation needs for UNS Electric; and continued strong customer growth in UniSource Energy’s utility service territories.
Financing Activities
Net cash flows used for financing activities were $36 million lower in 2006 compared with 2005. Factors impacting cash used for financing activities in 2006 include: an increase in net revolving credit facility borrowings and lower debt issuance costs; partially offset by an increase in net repayments of long-term debt; higher payments on capital lease obligations by TEP; higher dividends paid by UniSource Energy to its shareholders. In 2005, UniSource Energy issued $240 million of debt, which it used to repay an inter-company note to TEP and infuse
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capital into its subsidiaries. TEP used the proceeds from the inter-company note repayment and capital infusion to retire $282 million of debt.
As a result of the activities described above, our consolidated cash and cash equivalents decreased to $104 million at December 31, 2006, from $145 million at December 31, 2005. We invest cash balances in high-grade money market securities with an emphasis on preserving the principal amounts invested.
Liquidity Outlook
As a result of growing capital expenditures at UniSource Energy’s subsidiaries, the revolving credit facilities at UniSource Energy, TEP, UNS Gas and UNS Electric may be used on a more frequent basis. Other funding sources to meet the capital requirements of the strong utility customer growth could include the issuance of long-term debt, as well as capital contributions from UniSource Energy to its subsidiaries. The need for external funding sources is partially dependent on the outcome of rate-related proceedings at TEP, UNS Gas and UNS Electric.
For more information concerning liquidity and capital resources, see Tucson Electric Power Company, Liquidity and Capital Resources, below, UNS Gas, Liquidity and Capital Resources, UNS Electric, Liquidity and Capital Resources, and Other Non-Reportable Segments, Liquidity and Capital Resources, below.
Convertible Senior Notes
In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035, which are unsecured and are not guaranteed by TEP or any other UniSource Energy subsidiary.
Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of our Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.
Beginning in March 2010, UniSource Energy will have the option to redeem the notes, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued and unpaid interest. Holders of the notes will have the right to require UniSource Energy to repurchase the notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain specified fundamental changes involving UniSource Energy occur. The repurchase price will be 100% of the principal amount of the notes plus accrued and unpaid interest.
In the event of a fundamental change that occurs prior to March 2010, UniSource Energy may be required to pay a make-whole premium on notes converted in connection with the fundamental change. The make-whole premium will be payable in shares of UniSource Energy Common Stock or the consideration into which UniSource Energy Common Stock has been converted or exchanged in connection with such fundamental change.
A fundamental change involving UniSource Energy will be deemed to have occurred if: (1) certain transactions occur as a result of which there is a change in control of UniSource Energy; or (2) UniSource Energy Common Stock ceases to be listed on a national securities exchange or quoted on The Nasdaq National Market or another established automated over-the-counter trading market in the United States.
The notes may be accelerated upon the occurrence and continuance of an event of default under the indenture governing the notes. The failure to make required payments on the notes or comply with the terms of the indenture may constitute an event of default. In addition, events of default may arise upon the acceleration of $50 million of indebtedness for borrowed money of UniSource Energy or TEP, or certain events of bankruptcy involving UniSource Energy or TEP.
UniSource Energy Credit Agreement
In August 2006, UniSource Energy amended and restated its existing credit agreement (UniSource Credit Agreement). The amendment extended the maturity from April 2010 to August 2011, reduced the interest rate payable on borrowings, and changed the amounts available under the term loan and the revolving credit facilities. As amended, the UniSource Credit Agreement consists of a $30 million term loan facility and a $70 million revolving credit facility. Prior to the amendment, the UniSource Credit Agreement included a $90 million term loan facility ($84 million outstanding) and a $15 million revolving credit facility (zero outstanding). On August 11, 2006, UniSource Energy repaid the $84 million outstanding term loan with $30 million of available cash, $30 million drawn under the new term loan and $24 million drawn under the revolving credit facility.
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Quarterly principal payments of $1.5 million on the outstanding term loan are due beginning in September 2006, with the balance due at maturity. At December 31, 2006, there was $27 million outstanding under the term loan facility and $20 million outstanding under the UniSource Energy revolving credit facility at a weighted average interest rate of 6.67%. In January 2007, UniSource Energy repaid the $20 million outstanding on the revolving credit facility.
We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.
The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, sales of assets, and certain investments and acquisitions. We must also meet: (1) a minimum cash flow to debt service coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis. We may pay dividends if, after giving effect to the dividend payment, we have more than $15 million of unrestricted cash and unused revolving credit. As of December 31, 2006, we were in compliance with the terms of the UniSource Credit Agreement.
If an event of default occurs, the UniSource Credit Agreement may become immediately due and payable. An event of default includes failure to make required payments under the UniSource Credit Agreement, failure of UniSource Energy or certain subsidiaries to make payments or default on debt greater than $20 million, or certain bankruptcy events at UniSource Energy or certain subsidiaries.
Guarantees and Indemnities
In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We entered into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. The most significant of these guarantees at December 31, were:
·
UES’ guarantee of $160 million of aggregate principal amount of senior unsecured notes issued by UNS Gas and UNS Electric to purchase the Citizens’ Arizona gas and electric system assets;
·
UES’ guarantee of a $40 million revolving credit facility available to UNS Gas and UNS Electric; and
·
UniSource Energy’s guarantee of approximately $5 million in natural gas and supply payments and building lease payments for UNS Gas and UNS Electric.
To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated balance sheets.
In addition, UniSource Energy and its subsidiaries have indemnified the purchasers of interests in certain investments from additional taxes due for years prior to the sale. The terms of the indemnifications provide for no limitation on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations. We have not made any payments under the terms of these indemnifications to date.
We believe that the likelihood that UniSource Energy would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.
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Contractual Obligations
The following charts display UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2006.
(1) Includes quarterly principal payments due on the term loan facility in UniSource Energy’s Credit Agreement and amounts outstanding under the UNS Electric revolving credit facility. TEP’s Variable Rate IDBs are backed by LOCs issued pursuant to TEP’s Credit Agreement which expires in August 2011. Although the Variable Rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.
(2) Includes letter of credit and remarketing fees on variable rate debt. The interest rates for variable rate debt are estimated using Eurodollar futures rates for an approximation of LIBOR. For variable rate IDBs, a discount is applied to estimated LIBOR based on the historical discount the IDBs have had to LIBOR.
(3) Beginning with commercial operation of Springerville Unit 3 in September 2006, Tri-State is reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% of the Springerville Common Lease payments and 17% of the Springerville Coal Handling Facilities Lease payments. Similar reimbursement obligations are required after Unit 4 is constructed. TEP remains the obligor under these capital leases. Capital Lease Obligations do not reflect any reduction associated with this reimbursement.
(4) Annual payments under the Springerville Unit 1 lease vary in accordance with the amortization schedules of the debt underlying the capital lease, with significantly larger principal payments occurring in 2007, 2008 and 2011.
(5) Purchase obligations reflect the minimum contractual obligation under legally enforceable contracts with contract terms that are both fixed and determinable. The total amount paid under these contracts depends on the quantity purchased and transported. TEP and UES’ requirements are expected to be in excess of
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these minimums. UniSource Energy has excluded open purchase orders of approximately $13 million expected to be fulfilled in 2007.
(6) Based on prior years’ expenditures, TEP expects to spend approximately $200 million annually for the purchase and transportation of coal through 2010. TEP is unable to estimate how much it will spend under these contracts beyond 2010 due to the impact of the amended Springerville coal contract.
(7) Includes TEP and UNS Electric’s forward power purchases. TEP has not included capacity payments under TEP’s purchased power agreement with Tri-State which may be reduced in increments of 25 MW with 90 days notice. To date, TEP has received no such notice. If Tri-State does not give notice to reduce capacity, the minimum capacity payments will be $31 million annually in 2007 through 2010 and $21 million in 2011. UniSource Energy also has not included amounts payable to PWMT under UNS Electric’s full requirements power supply agreement as payments under this contract are usage based with no fixed demand charges and are recovered through the purchased power and fuel adjustment clause (PPFAC) mechanism. We expect to spend approximately $100 million annually under this contract through May 2008.
(8) Amounts include UNS Gas’ fixed price forward gas purchases and firm transportation agreements with EPNG and Transwestern. Incremental gas purchases are excluded as prices and volumes vary. Amounts also exclude swap agreements which are marked to market on a monthly basis and do not include any minimum payment obligation. UNS Gas entered into forward gas purchases for through 2010 totaling $9 million subsequent to December 31, 2006, which are excluded from the table above.
(9) Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the remote generating stations. TEP estimates its undiscounted final reclamation liability is $41 million with reclamation beginning in 2028. See Note 6. Also excludes asset retirement obligations expected to occur through 2066. See Note 3. Also, excludes Millennium’s equity commitments totaling $1 million over two years to fund subsidiaries (Valley Ventures) as suitable investments are identified.
(10) These obligations represent TEP and UES’ minimum required contributions to pension plans in 2007 and TEP’s expected postretirement benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. TEP and UES do not know and have not included pension contributions beyond 2007 due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts. TEP funds the postretirement benefit plan on a pay-as-you-go basis.
(11) These obligations represent TEP’s share of the cost of new pollution control equipment based on its ownership of San Juan. Under a settlement agreement signed in March 2005 with the New Mexico Environmental Department and environmental activist groups, the co-owners of San Juan will install new technology at the generating station to reduce mercury, particulate matter, NOx, and SO2 emissions. In addition, TEP’s share of increased operating and maintenance costs associated with the new technologies is expected to be approximately $12 million over the next 10 years.
(12) TEP has agreed with the owners of Springerville Units 3 and 4 that, upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP is obligated to acquire the facilities at fixed prices of $120 million in 2015, $38 million in 2017, and $68 million in 2021. Upon such acquisitions by TEP, each of the owners of Unit 3 and Unit 4 have the obligation to purchase from TEP a 17% and 14% interest, respectively, in such facilities.
We have reviewed our contractual obligations and provide the following additional information:
·
We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
·
None of our contracts or financing structures contains provisions or acceleration clauses due to changes in our stock price.
Dividends on Common Stock
On February 9, 2007, UniSource Energy declared a first quarter cash dividend of $0.225 per share on its Common Stock. The first quarter dividend, totaling approximately $8 million, will be paid March 14, 2007 to shareholders of record at the close of business February 20, 2007. During 2006, UniSource Energy paid quarterly dividends to its shareholders of $0.21 per share, totaling approximately $29 million. In 2005, UniSource Energy paid quarterly dividends to its shareholders of $0.19 per share, totaling approximately $26 million.
Income Tax Position
At December 31, 2006, UniSource Energy and TEP had, for federal and state income tax filing purposes, the following carryforward amounts:
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Internal Revenue Service Matters
On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets. The new accounting method was also used on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.
In August 2005, the IRS issued a ruling which draws into question the ability of electric and gas utilities to use the new accounting method. As a result, TEP, UNS Gas and UNS Electric have filed amended returns for 2002, 2003 and 2004 to remove the benefit previously claimed using the accounting method. In 2006, TEP and UNS Electric remitted tax and interest of $23 million and $1 million respectively to the IRS; and TEP, UNS Gas and UNS Electric remitted $8 million to state authorities. In December 2006, the IRS issued a final notice to the company disallowing the use of the accounting method. We are in the process of filing a protest and will proceed to appeals.
TUCSON ELECTRIC POWER COMPANY
RESULTS OF OPERATIONS
The financial condition and results of operations of TEP are currently the principal factors affecting the financial condition and results of operations of UniSource Energy on an annual basis. The following discussion relates to TEP’s utility operations, unless otherwise noted.
Compared With 2005
TEP recorded net income of $67 million in 2006 compared with $48 million in 2005. The following factors contributed to the improvement:
included:
·
a $53 million increase in total operating revenues less fuel and purchased power expense due to the following:
·
a $28 million increase in retail revenues due to warm weather during the second quarter and retail customer growth;
·
a $9 million increase in wholesale revenues due primarily to $3 million of transmission revenues related to Springerville Unit 3 and a $6 million increase in unrealized gains related to mark-to-market adjustments on forward sales. Margins on wholesale sales were lower than last year due to a decline in the average market price for power;
·
a $23 million increase in other revenues due primarily to fees and reimbursements received from Tri-State for fuel and O&M costs related to Springerville Unit 3;
·
a $24 million decrease in purchased power expense due to increased production at TEP’s coal-fired generating plants and the availability of Luna to offset some of the wholesale purchases to meet retail customer demand during peak summer periods. Purchased power expense also reflects a $4 million increase in unrealized losses due to mark-to-market adjustments on forward purchases of energy; offset by
·
a $31 million increase in fuel expense due to increased generation at TEP’s coal-fired plants, gas-related fuel expense at Luna and $8 million of fuel costs associated with Springerville Unit 3;
·
a $31 million increase in O&M expense. TEP’s O&M includes $9 million of expenses related to Springerville Unit 3. In addition, pre-tax gains related to the sale of excess SO2 emission allowances were $7 million lower than 2005. Other factors contributing to higher O&M include operating expenses at Luna; generating plant maintenance; and higher payroll expenses;
·
a $10 million increase in the amortization of TEP’s TRA; and
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·
a $13 million decrease in total interest expense due primarily to lower interest on long-term debt and capital lease obligations, which was partially offset by interest paid to the IRS related to a notice of a proposed adjustment to previously filed tax returns and fees incurred in the third quarter of 2006 related to amending TEP’s Credit Agreement.
In 2006, the net pre-tax benefit recognized by TEP related to Springerville Unit for transmission revenues, operating fees and its share of the common costs was $8 million.
Compared With 2004
TEP recorded income before cumulative effect of accounting change of $49 million in 2005 compared with $46 million in 2004. The following factors contributed to the improvement:
Included:
·
a $26 million decrease in TEP’s total operating revenue less fuel and purchased power expense due to the following:
·
a $60 million increase in TEP’s purchased power expense resulting primarily from an extended unplanned outage of Springerville Unit 2 in August 2005, planned maintenance outages at San Juan Unit 2 and Four Corners Unit 5 during the second quarter and higher wholesale power prices;
·
a $14 million increase in TEP’s fuel expense due to a $3 million increase in natural gas costs primarily from higher gas prices and an $11 million increase in coal costs;
·
a $28 million increase in retail revenues due to warm weather and a 3% increase in TEP’s customer base; and
·
a $19 million increase in TEP’s wholesale revenues due to higher market prices for power compared to last year.
·
a $22 million decrease in O&M. Higher maintenance costs at TEP’s coal-fired plants were offset by an increase of $10 million in pre-tax gains on the sale of excess SO2 Emission Allowances by TEP;
·
a $6 million increase in the amortization of TEP’s TRA; and
·
a $17 million decrease in total interest expense related to the financial restructuring of TEP in May 2005.
Included:
·
expenses of $8 million related to a proposed but terminated acquisition of UniSource Energy.
Utility Sales and Revenues
Customer growth, weather and other consumption factors affect retail sales of electricity. Electric wholesale revenues are affected by market prices in the wholesale energy market, the availability of TEP generating resources, and the level of wholesale forward contract activity.
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The table below provides trend information on retail sales by major customer class and electric wholesale sales made by TEP in the last three years as well as weather data for TEP’s service territory.
Compared with 2005
Total revenues from kWh sales to retail customers increased by $28 million, or 4%, in 2006 compared with 2005, due primarily to customer growth.
Wholesale revenues increased $9 million in 2006 compared with last year. In 2006, wholesale revenues included $3 million in transmission revenues related to Springerville Unit 3 and a $6 million increase in net unrealized gain due to mark-to-market adjustments on forward sales. Wholesale kWh sales increased 8% primarily due to the higher availability of TEP’s coal plants; however, margins on wholesale sales were lower due to a 16% decrease in the average market price of wholesale energy. TEP’s margins on wholesale sales were higher in 2005, as hurricane activity in the Gulf of Mexico boosted market prices for wholesale energy in the last six months of the year. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.
Mark-to-Market Adjustments on Trading Activity
The table below summarizes the net unrealized gains (losses) on TEP’s forward sales and purchases of energy. Net unrealized gains (losses) on forward sales of energy are presented on the income statement in wholesale revenues. Net unrealized gains (losses) on forward purchases of energy are presented on the income statement in purchased power expense. Amounts for 2006 are based on the market price of energy as of December 31, 2006.
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Compared with 2004
Total revenues from sales to retail customers increased by $28 million, or 4%, in 2005 compared with 2004, due primarily to customer growth and warm summer weather. Residential kWh sales increased 5% and commercial kWh sales increased 4% during 2005.
Despite lower coal plant availability and a 3% decrease in wholesale kWh sales, wholesale revenues increased $18 million, or 11%, in 2005 compared with 2004. The average wholesale market price of energy was $59 per MWh in 2005, compared with $44 per MWh in 2004. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.
Operating Expenses
Compared with 2005
Fuel and Purchased Power
TEP’s fuel and purchased power expense, and energy resources for 2006, 2005 and 2004 are detailed below:
(1) Fuel expense in 2006 excludes $8 million related to Springerville Unit 3; the fuel costs incurred on behalf of Unit 3 are recorded in Fuel Expense and the reimbursement by Tri-State is recorded in Other Revenue.
The start of commercial operation of Luna and higher coal plant availability in the summer months led to a $24 million increase in fuel expense in 2006 (excluding fuel expenses at Springerville Unit 3); however, purchased power expense decreased $24 million as these same factors reduced TEP’s need to purchase power during the summer months to meet retail demand. Gas-fired generation more than doubled in 2006, causing gas-related fuel expense to increase $19 million, or 53%. Coal-fired generation increased 1%, leading to a $5 million increase in coal-related fuel expense. Luna’s generation output reported in the table above includes energy generated during its test phase, but does not include any associated fuel costs which were capitalized and reported as project costs.
Despite a 4% increase in purchased energy volumes, purchased power expense was $24 million, or 18%, lower due to a decrease in average wholesale energy prices in 2006 as well as fewer short-term purchases during the summer months when market prices for wholesale energy are typically higher. In September 2006, TEP began purchasing energy from Tri-State under a 100 MW purchased power agreement.
The table below shows TEP’s average resource cost per kWh generated:
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*In 2006, the average cost of gas generation per kWh excludes test energy produced at
Luna and its associated fuel costs.
TRA amortization increased $10 million in 2006. Amortization of the TRA is the result of the Settlement Agreement with the ACC, which changed the accounting method for TEP’s generation operations. This item reflects the recovery, through 2008, of transition recovery assets which were previously regulatory assets of the generation business. The amount of amortization is a function of the TRA balance and total kWh consumption by TEP’s distribution customers.
The table below shows estimated annual TRA amortization and unamortized TRA year-end balances for 2007 and 2008.
Other Income (Deductions)
In 2005, TEP’s Income Statement included inter-company Interest Income of $2 million. This represented Interest Income on a promissory note TEP received from UniSource Energy in exchange for the transfer to UniSource Energy of its stock in Millennium in 1998. UniSource Energy repaid the inter-company promissory note on March 1, 2005. On UniSource Energy’s Consolidated Statement of Income, this Interest Income, as well as UniSource Energy’s related interest expense, was eliminated as an inter-company transaction. See Liquidity and Capital Resources, TEP Cash Flows, Inter-Company Note from UniSource Energy, below.
Operating Expenses
Compared with 2004
Fuel and Purchased Power
During 2005, planned outages at Springerville Unit 2, San Juan Unit 2 and Four Corners Unit and an extended unplanned outage at Springerville Unit 2 during the third quarter led to higher gas-related fuel costs and an 82% increase in purchased power expense. Purchased power expense increased $60 million compared with 2004, due to a 19% increase in MWhs purchased and an increase in wholesale market prices for power. The average market price for around-the-clock energy based on the Palo Verde Index increased 34% in 2005 compared with average prices in 2004. A combination of higher coal and natural gas costs contributed to a $13 million increase in total fuel expense at TEP’s generating plants in 2005.
Cumulative Effect of Accounting Change
TEP adopted FIN 47 in December 2005 and recorded a one-time $1 million after-tax cost. See Note 3 of Notes to Consolidated Financial Statements, Accounting Change: Accounting for Asset Retirement Obligations, and Critical Accounting Estimates, Accounting for Asset Retirement Obligations, below.
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FACTORS AFFECTING RESULTS OF OPERATIONS
Competition
In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however, only a small number of commercial and industrial customers initially chose an ESP. By 2002, none of TEP’s retail customers were served by an alternative ESP.
In 2004, an Arizona Court of Appeals decision held invalid certain portions of the ACC rules on retail competition and related market pricing. In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition. We cannot predict what changes, if any, the ACC will make to the competition rules. TEP has met all conditions required by the ACC to facilitate electric retail competition, including ACC approval of TEP’s direct access tariffs. See Rates, ACC Order to Review the Settlement Agreement, below.
TEP competes against gas service suppliers and others that provide energy services. Other forms of energy technologies may provide competition to TEP’s services in the future, but to date, are generally not financially viable alternatives for its retail customers. Self-generation by TEP’s large industrial customers could also provide competition for TEP’s services in the future, but has not had a significant impact to date.
In the wholesale market, TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy.
ACC Order to Review the Settlement Agreement
Beginning in May 2005, TEP filed a series of pleadings requesting the ACC to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008. TEP filed the pleadings in response to the Arizona Court of Appeals ruling related to retail competition and market pricing and a lack of agreement as to the interpretation of the Settlement Agreement by a number of participants in TEP’s rate proceedings. TEP believes that the Settlement Agreement contemplated market based rates for generation service after 2008. See Competition, above for information regarding the recent court ruling.
In April 2006, the ACC ordered that a procedure be established to allow for an expeditious and complete review of, among other things, the Settlement Agreement and its effect on how TEP’s rates for generation services will be determined after December 31, 2008.
The testimony filed by a number of participants in this proceeding, including the ACC Staff and Residential Utility Consumer Office (RUCO), reflect differing interpretations of the Settlement Agreement and a belief that TEP is required to charge cost-of-service rates for generation service in 2009.
According to testimony filed by TEP, its average retail rate would increase approximately 23% over current rates if 2009 generation service rates are market based. TEP also proposed two alternatives to charging market-based rates for generation in 2009: a market phase-in proposal with an initial rate increase capped at 12%; and a cost-of-service (including an $850 million regulatory asset and energy cost adjustment clause) proposal that would increase average retail rates in 2009 approximately 26% over current rates. See TEP Testimony, The Market-Phase-in Proposal, and The Cost-of-Service (including Regulatory Asset and Energy Cost Adjustment Clause) Proposal, below for more information.
In February 2007, parties in this proceeding participated in settlement discussions, however were unable to reach a settlement.
A public hearing before an ACC Administrative Law Judge (ALJ) is scheduled to begin on March 6, 2007. Following the public hearing, the ALJ will propose a recommended opinion and order for consideration by the ACC. We expect the ALJ to issue a recommendation in the second quarter of 2007.
If the ACC does not honor the Settlement Agreement allowing TEP to charge market-based rates for generation service in 2009 and orders TEP to return to cost-of-service generation rates without compensating TEP for financial impacts of the Settlement Agreement, TEP will file a lawsuit to preserve its right to declaratory relief and damages.
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Rates
Settlement Agreement
In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.
The Rules and the Settlement Agreement established:
·
a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;
·
the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (Fixed CTC);
·
capped rates for TEP retail customers through 2008;
·
an ACC interim review of TEP retail rates in 2004;
·
unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;
·
a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers;
·
access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs);
·
transmission and distribution services would remain subject to regulation on a cost of service basis; and
·
beginning in 2009, TEP’s generation would be market-based and its retail customers would pay the market rate for generation services.
Track A and Track B Proceedings
During 2002 and 2003, the ACC reexamined circumstances that had changed since it approved the Rules in 1999. The outstanding issues were divided into two groups. Track A related primarily to the divestiture of generation assets while Track B related primarily to the competitive energy bidding process.
Under the ACC’s Rules, TEP and other utilities were required to divest their generation assets. TEP later requested a waiver of the divestiture requirement. The Track A order granted TEP’s request and eliminated the divesture requirement. As a result, generation assets remain at TEP. At the same time, the ACC ordered the parties, including TEP, to develop a competitive bidding process and reduced the minimum amount of power to be acquired in the competitive bidding process to only that portion not supplied by TEP’s existing resources.
The ACC Track B order defined the competitive bidding process TEP must use to obtain capacity and energy requirements. The Track B order did not address TEP’s purchased power or asset acquisitions occurring subsequent to the 2003 competitive solicitation.
General Rate Case Information
In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC. TEP’s filing did not propose any change in retail rates and, under the terms of the Settlement Agreement, no rate case filed by TEP through 2008 may result in a net rate increase. However, absent the restriction on raising rates, TEP believes that the data in its filing would have justified an increase in retail rates of 16%.
The general rate case information used a historical test year ended December 31, 2003 and established, based on TEP’s standard offer service, that TEP was experiencing a revenue deficiency of $111 million. None of the intervenor testimony filed proposed any decrease to TEP’s rates. Testimony filed by the ACC Staff, Residential Utility Consumer Office and Arizonans for Electric Choice and Competition indicated revenue deficiencies for TEP of $67 million, $32 million and $38 million, respectively. In 2005, the ALJ issued a procedural order suspending the remaining testimony filing deadlines and hearing in the 2004 rate review.
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TEP Testimony
In August 2006, TEP filed testimony in the ACC proceedings to review the Settlement Agreement.
TEP’s testimony states its belief that it is entitled to charge market based generation service rates in 2009 and has complied with its obligations under the Settlement Agreement.
TEP testimony states that the Settlement Agreement provided the terms and conditions by which TEP is to transition into the competitive electric marketplace. The rate impact of charging market based generation service rates in 2009 would vary with market conditions which are influenced by the cost of natural gas. Assuming a natural gas cost of $7 per MMBtu, which equates to a wholesale power price of approximately $60 per MWh, TEP’s average retail rate would be expected to increase approximately 23% over current rates if 2009 generation service rates are market based.
The Settlement Agreement required TEP to significantly change the way it conducted business. Under the terms of the Settlement Agreement, TEP agreed to: (i) rate reductions in 1999 and 2000; (ii) a rate freeze from July 1, 2000 through December 31, 2008, taking all the risk of inflation and cost increases; (iii) unbundled tariffed rates; (iv) accelerate depreciation of certain generation-related assets; (v) offset the standard offer generation rate (Market Generation Credit) by the amount of the Floating Competition Transition Charge; (vi) open its exclusive service territory to competition for generation service; (vii) assume the volatility and risk of market rates in 2009; and (viii) a rate check in when rates could not increase but could actually decrease.
In the testimony, TEP states that if the ACC or other parties to the Settlement Agreement seek to unilaterally change the contract and order TEP back to cost-of-service, which is a breach that will force TEP to protect its rights in court and seek an order, which may include an award for damages. TEP states that, if the ACC does not honor the Settlement Agreement, does not agree to one of TEP’s alternative proposals, and orders that TEP’s generation service rates will be based on traditional cost-of-service ratemaking without compensating TEP for the financial impacts of the Settlement Agreement, then TEP must: (1) file a rate case and (2) immediately file a lawsuit to preserve its right to declaratory relief and damages arising from the ACC’s breach of the Settlement Agreement. TEP states that the financial impacts and costs directly attributable to the Settlement Agreement exceed $850 million.
In the testimony, TEP offered alternatives to charging market based generation service rates after December 31, 2008, as described below.
The Market Phase-In Proposal
TEP proposed a market rate phase-in plan in the event that the ACC desires to maintain a competitive wholesale generation market, but wants to mitigate the immediate impact of market rates. Elements of the market rate phase-in include:
·
A cap would be set such that no customer class would realize an initial rate increase in excess of 12%. The phase-in period would begin in 2009, last approximately four years and then be fully market-based;
·
TEP’s current rates would remain frozen through the end of 2008; and
·
Implementation of the new DSM, REST and TOU programs and tariffs.
The Cost-of-Service (including Regulatory Asset and Energy Cost Adjustment Clause) Proposal
TEP’s cost-of-service proposal presents a framework for returning TEP to cost-of-service regulation for generation service if the ACC determines that it will abandon the concept of a competitive wholesale and retail generation market. Elements of the proposal include:
·
A new regulatory asset of $850 million to be included in rate base will be created to compensate TEP for the financial impacts and costs incurred in performing under the Settlement Agreement;
·
An energy cost adjustment clause (ECAC) to recover energy costs associated with serving the incremental retail load above that filed in its cost-of-service test year;
·
Immediate filing of a cost-of-service rate case in 2007;
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·
Implementation of the new DSM, REST and TOU programs and tariffs; and
·
Restore exclusivity of TEP’s certificate of convenience and necessity.
The proposed ECAC would differ from some other purchase power and fuel clauses in that it would not include any fuel or purchased power price risks or plant operating risks associated with serving the test year portion of TEP’s retail load. Also, the ECAC would not be a straight pass through of purchased power costs to serve the incremental load. In the event that TEP’s actual fuel and purchased power costs related to the incremental load exceeds the ECAC rate, TEP would not be able to pass the “excess” costs through to customers. However, in the event that those costs are less than the ECAC rate, TEP would be entitled to retain those earnings.
If the ACC adopts TEP’s cost-of-service proposal and approves a new regulatory asset of $850 million and implementation of the ECAC mechanism, TEP expects that its average retail rate in 2009 would increase by approximately 26% over current rates.
Renewable Energy Standard and Tariff
In October 2006, the ACC approved new Renewable Energy Standard and Tariff rules (REST rules) designed to require TEP, UNS Electric and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years starting when the REST tariff submitted by an affected utility is approved by the ACC. To provide an opportunity for full recovery of the increased costs of meeting the more aggressive standard, the adopted REST rules allow for a new tariff to be implemented separate and apart from the existing Environmental Portfolio Surcharge. The rules require affected utilities to annually file with the ACC a REST tariff request with a REST implementation plan to recover the cost of purchasing or installing and operating the renewable resources. The tariff amount is annually subject to ACC approval.
The REST rules require utilities to file annual compliance reports outlining the results of the renewable programs implemented the prior year, highlighting steps they are taking to meet the REST annual renewable energy requirements. The REST rules adopted by the ACC must be certified by the Arizona Attorney General before taking effect. As of February 23, 2007, the Attorney General had not issued an opinion certifying the REST rules.
Western Energy Markets
As a participant in the Western U.S. wholesale power markets, TEP is directly and indirectly affected by changes in market conditions and market participants. TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy at market-based rates in the wholesale market.
At the end of 2006, electric generating capacity in Arizona was approximately 25,600 MW, an increase of 61% since 2001. A majority of the growth is the result of 17 new or upgraded gas-fired generating units with a combined capacity of approximately 9,700 MW. The completion of Springerville Unit 3 in 2006 provided 400 MW of new coal-fired generation located in Arizona.
Market Prices
The average market price for around-the-clock energy based on the Dow Jones Palo Verde Index decreased in 2006, as did the average price for natural gas based on the Permian Index. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2007.
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In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers. 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 and gas-indexed purchased power with fixed price contracts for a maximum of three years. TEP currently has approximately 35% of this exposure hedged for the summer peak period of 2007 (June - September) at a weighted average price of $7.18 per MMBtu. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.
Market prices may also affect TEP’s wholesale revenues. TEP commits to future sales of energy as part of its ongoing efforts to hedge its excess generation based on projected generation capability, forward prices and generation costs. For the first quarter of 2007, TEP has sold forward approximately 255,000 MWh at an average price of $70 per MWh, which excludes on-peak hours in April through September.
We expect the market price and demand for capacity and energy to continue to be influenced by factors including:
·
availability and price of natural gas;
·
weather;
·
continued population growth in the Western U.S.;
·
economic conditions in the Western U.S.;
·
availability of generating capacity throughout the Western U.S.;
·
the extent of electric utility industry restructuring in Arizona, California and other Western states;
·
FERC regulation of wholesale energy markets;
·
availability of hydropower;
·
transmission constraints; and
·
environmental regulations and the cost of compliance.
Coal Supply
On December 28, 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through 2008. The cost of coal and transportation under the agreements will increase approximately 60%, primarily due to significantly higher rail costs. Based on these agreements, and increases at other coal-fired plants, we expect TEP’s total coal-related fuel expense across all of its plants to increase by approximately $17 million, or 9% in 2007.
Emission Allowances
TEP has SO2 Emission Allowances in excess of what is required to operate its generating units. The excess results primarily from a higher removal rate of SO2 emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations. From time to time, TEP will sell a portion of its excess SO2 Emission Allowances. The table below summarizes sales made in 2005 and 2006, and forward sales of SO2 Emission Allowances, as of December 31, 2006.
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In addition to the allowances contracted to be sold in 2007, TEP expects to have approximately 20,000 excess SO2 Emission Allowances through 2009.
Springerville Units 3 and 4
Springerville Unit 3, which commenced commercial operation in July 2006, is a 400 MW coal-fired generating facility located at the same site as Springerville Units 1 and 2. Tri-State is leasing 100% of Unit 3 from a financial owner. TEP allocates a portion of the fixed costs of the existing common facilities to the additional generating unit. TEP operates Unit 3 and will receive annual pre-tax benefits of approximately $15 million in the form of transmission revenues, rental payments and other fees and cost savings. As part of the project, Tri-State provided funding to improve sulfur dioxide scrubbers, low-nitrogen oxide burners and other emission control upgrades for Units 1 and 2, which were completed in 2005.
SRP is purchasing 100 MW of capacity from Tri-State under a 30-year power purchase agreement. In May 2006, SRP announced its intention to build Unit 4, a 400 MW coal-fired generating facility at the same Springerville site. Construction of Unit 4 has begun and, under the terms of existing regulatory permits, is required to be completed by December 31, 2009. Prior to Unit 4’s completion, TEP may be required, along with Tri-State, to exercise best efforts to find a replacement purchaser for SRP to purchase 100 MW of capacity from Unit 3. If TEP and Tri-State are unable to find such a replacement purchaser, TEP would then purchase 100 MW of output from Unit 4, beginning with the commercial operation of Unit 4. Given the current level of wholesale power market prices, we believe it is unlikely that TEP would be required to find a replacement purchaser or to purchase SRP’s 100 MW.
LIQUIDITY AND CAPITAL RESOURCES
TEP Cash Flows
During 2007, TEP expects to generate sufficient internal cash flows to fund most of its construction expenditures as well as its operating activities, required debt maturities and dividends to UniSource Energy. 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.
The table below shows the cash available to TEP after capital expenditures, scheduled debt payments and payments on capital lease obligations:
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* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments, 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 as a measure of liquidity. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments provide useful information to investors as measures of liquidity and our ability to fund our capital requirements, make required payments on debt and capital lease obligations, and pay dividends to UniSource Energy.
Liquidity Outlook
As a result of growing capital expenditures, TEP may use its revolving credit facility on a more frequent basis. Other funding sources to meet the capital requirements from TEP’s strong customer growth could include the issuance of long-term debt as well as capital contributions from UniSource Energy. The need for external funding sources is partially dependent on the outcome of TEP’s rate-related proceedings.
Operating Activities
In 2006, net cash flows from operating activities decreased by $16 million compared with the same period in 2005. Net cash flows were impacted by:
included:
·
a $28 million increase in cash receipts from electric retail and wholesale sales, net of fuel and purchased energy costs, due primarily to retail customer growth, higher availability of excess power to sell into the wholesale market; and the availability of Luna to offset some of TEP’s purchased power requirements; and
·
a $16 million decrease in total interest paid due to lower capital lease obligation balances, lower long-term debt balances and lower annual fees under the TEP credit agreement that was entered into in May 2005 and amended in August 2006;
·
a $20 million increase in other cash receipts due primarily to payments from Tri-State for fees and the reimbursement of operating costs related to Springerville Unit 3; offset by
·
a $42 million increase in income taxes paid due to a $31 million payment made to the IRS and state authorities related to a notice of a proposed adjustment to previously filed tax returns and an increase in federal and state extension and estimated tax payments;
·
an $11 million increase in O&M costs due primarily to operating costs at Luna and higher generating plant maintenance costs;
·
an $8 million decline in proceeds from the sale of excess emission allowances;
·
a $4 million increase in taxes other than income taxes; and
·
a $3 million increase in wages paid.
included:
·
$11 million of interest received from UniSource Energy related to an inter-company note repaid in the first quarter of 2005.
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Investing Activities
Net cash used for investing activities was $53 million higher in 2006 compared with 2005 primarily due to:
·
a $9 million increase in proceeds from investments in Springerville Lease Debt; offset by
·
a $6 million increase in capital expenditures related to TEP’s share of the construction costs of Luna and growth and maintenance of TEP’s electric system; and
·
TEP’s purchase of a 14% equity interest in Springerville Unit 1 Lease, which represents approximately 53 MW of capacity.
Capital Expenditures
TEP’s forecasted capital expenditures are summarized below:
Capital expenditures for TEP of $855 million for 2007 through 2010 are expected to be $216 million, or 34% higher than our 2005 forecast. This increase is the result of several factors including: strong customer growth; higher material and construction costs; the need to increase high-voltage transmission capacity into TEP’s service territory; the reinforcement and expansion of distribution lines; and environmental upgrades to generating facilities.
These estimated expenditures include costs for TEP to comply with current federal and state environmental regulations. These estimates do not include the costs to construct the proposed Tucson to Nogales, Arizona transmission line. All of these estimates are subject to continuing review and adjustment. Actual construction expenditures may be different from these estimates due to changes in business conditions, construction schedules, environmental requirements, and changes to TEP’s business arising from retail competition. TEP plans to fund these expenditures through internally generated cash flow.
Tucson to Nogales Transmission Line
If all regulatory approvals are received, the future costs to construct the transmission line from Tucson to Nogales, Arizona is expected to be approximately $95 million. Through December 31, 2006, approximately $11 million in land acquisition, engineering and environmental expenses have been incurred on this project. If the required approvals are not received, TEP may be required to expense a portion of the costs that have been capitalized related to the project, propose alternative methods to the ACC for improving reliability and spend additional amounts to implement such alternatives. See Item 1. Business, Tucson Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.
In addition to TEP’s forecasted capital expenditures for construction, TEP’s other capital requirements include its required debt maturities and capital lease obligations. See Note 8 of Notes to Consolidated Financial Statements - Debt, Credit Facilities, and Capital Lease Obligations.
Investments in Springerville Lease Debt and Equity
At December 31, 2006, TEP had $181 million of investments in lease debt and equity on its balance sheet. The yields on TEP’s investments in Springerville Lease Debt, at the date of purchase, range from 8.9% to 12.7%. The table below provides a summary of the investment balances in lease debt.
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See Note of Notes to Consolidated Financial Statements - Debt, Credit Facilities and Capital Lease Obligations
Financing Activities
Net cash used for financing activities was $95 million lower in 2006 compared with 2005. The following factors contributed to the decrease:
included:
·
a $30 million increase in net proceeds from borrowings under the TEP Revolving Credit Facility; offset by
·
a $16 million increase in dividends paid to UniSource Energy; and
·
an $8 million increase in scheduled payments made on capital lease obligations.
included:
·
a $110 million equity investment by UniSource Energy; and
·
$95 million from UniSource Energy as a repayment for an inter-company loan; offset by
·
$282 million to repay long-term debt;
·
$5 million for debt issuance and retirement costs.
At December 31, 2006, there were $30 million in outstanding borrowings under the TEP Revolving Credit Facility.
TEP Credit Agreement
In August 2006, TEP amended and restated its existing credit agreement (TEP Credit Agreement). The amendment reduced the interest rate and fees payable on TEP’s borrowings and letters of credit, increased the amount of its revolving credit facility to $150 million from $60 million, and extended the maturity to August 2011 from May 2010. In addition to the revolving credit facility, the TEP Credit Agreement includes a $341 million letter of credit facility which supports $329 million of tax-exempt variable rate bonds. The TEP Credit Agreement is secured by $491 million of 1992 Mortgage Bonds.
Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. Letter of credit fees are 0.55% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.55% per annum. TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.55% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.
The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leaseback agreements. The TEP Credit Agreement also requires TEP to meet a minimum cash coverage ratio and a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, it may pay dividends to UniSource Energy. As of December 31, 2006, TEP was in compliance with the terms of the TEP Credit Agreement.
If an event of default occurs, the TEP Credit Agreement may become immediately due and payable. An event of default includes failure to make required payments under the TEP Credit Agreement; change in control, as defined; failure of TEP or certain subsidiaries to make payments or default on debt greater than $20 million; or certain bankruptcy events at TEP or certain subsidiaries.
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Springerville Common Facilities Leases
In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station. TEP refinanced the lease debt totaling $68 million in June 2006. Interest is payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. The refinancing had no impact on the Springerville Common Facilities capital lease obligation or asset.
A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the floating rate lease debt. On June 8, 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest rate portion of rent at 7.27% on $37 million of the lease debt.
The LIBOR rate in effect on December 31, 2006 was 5.63%, and 3.68% on December 31, 2005, which resulted in a total interest rate on the lease debt of 7.13% at December 31, 2006, and 7.68% at December 31, 2005.
Inter-Company Note from UniSource Energy
In March 2005, UniSource Energy repaid to TEP a debt obligation in the principal amount of $95 million plus accrued interest of $11 million. TEP used the proceeds during May 2005 to redeem or repurchase certain of its existing debt through tender offers and redemptions. See Bond Repurchases and Redemptions, below.
Capital Contribution from UniSource Energy
In May 2005, UniSource Energy made a $110 million capital contribution to TEP. TEP used the proceeds during May 2005 to redeem or repurchase certain of its existing debt through tender offers and redemptions. See Bond Repurchases and Redemptions, below.
Bond Repurchases and Redemptions
TEP made a sinking fund payment of $1 million on its 6.1% 1941 Mortgage IDBs in January 2005. In March 2005, TEP redeemed at par the remaining $31 million of its 6.1% 1941 Mortgage IDBs due in 2008, as well as the remaining $21 million of its 7.5% Mortgage IDBs due in 2006.
In May 2005, TEP used the proceeds from the repayment of the note from UniSource Energy and the capital contribution from UniSource Energy to purchase $147 million of its 1997 Pima Series B and $74 million of its 1997 Pima Series C fixed-rate tax-exempt bonds (Repurchased Bonds) at a price of $101.50 per $100 principal amount. In May 2005, TEP redeemed at par the remaining $4 million of bonds outstanding under those series. TEP does not currently plan on canceling the Repurchased Bonds, which will remain outstanding under their respective indentures; however, the Repurchased Bonds will not be presented in our financial statements. TEP may choose to resell the Repurchased Bonds to third parties or cancel them in the future.
Mortgage Indentures
In June 2005, TEP terminated its 1941 Mortgage (formerly known as its First Mortgage). TEP’s remaining mortgage is its 1992 Mortgage (formerly known as its Second Mortgage).
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. TEP’s mortgage indenture allows TEP to issue additional mortgage bonds on the basis of (1) a percentage of net utility property additions and/or (2) 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 indenture.
TEP’s Credit Agreement, which totals $491 million and is secured by 1992 Mortgage Bonds, limits the amount of mortgage bonds that may be outstanding to no more than $840 million. At December 31, 2006, TEP had a total of $629 million in outstanding mortgage bonds, consisting of $491 million in bonds securing the TEP Credit Agreement, and $138 million in bonds securing the 7.50% Collateral Trust Bonds due in 2008. Although the 1992 Mortgage would allow TEP to issue additional bonds, the limit imposed by the TEP Credit Agreement is more restrictive and is currently the governing limitation.
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Tax-Exempt Local Furnishing Bonds
TEP has financed a substantial portion of utility plant assets with industrial development revenue bonds issued by the Industrial Development Authorities of Pima County and Apache County. The interest on these bonds is excluded from gross income of the bondholder for federal tax purposes. This exclusion is allowed because the facilities qualify as “facilities for the local furnishing of electric energy” as defined by the Internal Revenue Code. These bonds are sometimes referred to as “tax-exempt local furnishing bonds.” To qualify for this exclusion, the facilities must be part of a system providing electric service to customers within not more than two contiguous counties. TEP provides electric service to retail customers in the City of Tucson and certain other portions of Pima County, Arizona and to Fort Huachuca in contiguous Cochise County, Arizona.
TEP has financed the following facilities, in whole or in part, with the proceeds of tax-exempt local furnishing bonds: Springerville Unit 2, Sundt Unit 4, a dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service area (the Express Line), and a portion of TEP’s local transmission and distribution system in the Tucson metropolitan area. As of December 31, 2006, TEP had approximately $359 million of tax-exempt local furnishing bonds outstanding. Approximately $257 million in principal amount of such bonds financed Springerville Unit 2 and the Express Line. In addition, approximately $38 million of remaining lease debt related to the Sundt Unit 4 lease obligation was issued as tax-exempt local furnishing bonds.
Various events might cause TEP to have to redeem or defease some or all of these bonds:
·
formation of an RTO or ISO;
·
asset divestiture;
·
changes in tax laws; or
·
changes in system operations.
TEP believes that its qualification as a local furnishing system should not be lost so long as (1) the RTO or ISO would not change the operation of the Express Line or the transmission facilities within TEP’s local service area, (2) the RTO or ISO allows pricing of transmission service such that the benefits of tax-exempt financing continue to accrue to retail customers, and (3) energy produced by Springerville Unit 2 and TEP’s local generating units continues to be consumed in TEP’s local service area. However, there is no assurance that such qualification can be maintained. Any redemption or defeasance of these bonds would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater amount.
Capital Lease Obligations
At December 31, 2006, TEP had $647 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.
Except for TEP’s 14% equity ownership in the Springerville Unit 1 Leases and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases. TEP may renew the leases or purchase the leased assets at such time. The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, while the purchase price option is fixed for the Springerville Coal Handling Facilities and Common Facilities. See UniSource Energy, Contractual Obligations, footnote (3), for more information about the fixed purchase price amounts.
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Contractual Obligations
The following charts display TEP’s contractual obligations as of December 31, 2006 by maturity and by type of obligation.
See UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations.
We have no other commercial commitments to report.
We have reviewed our contractual obligations and provide the following additional information:
·
TEP’s Credit Agreement contains pricing for its Revolving Credit Facility 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.
·
TEP’s Credit Agreement contains certain financial and other restrictive covenants, including interest coverage and leverage tests. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2006, 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 margin due to 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, 2006, TEP has not been required to post such credit enhancement.
Dividends on Common Stock
TEP declared and paid dividends to UniSource Energy of $62 million in 2006, $46 million in 2005 and $32 million in 2004.
TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2006, TEP was in compliance with the terms of the TEP Credit Agreement.
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The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis to pay dividends from current year earnings.
UNS GAS
RESULTS OF OPERATIONS
UniSource Energy formed two operating companies, UNS Gas and UNS Electric, to acquire the Arizona electric and gas assets from Citizens in 2003, as well as an intermediate holding company, UES, to hold the common stock of UNS Gas and UNS Electric.
UNS Gas reported net income of $4 million in 2006, $5 million in 2005 and $6 million in 2004. We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months.
As of December 31, 2006, UNS Gas had approximately 145,000 retail customers, a 5% increase from last year. The table below shows UNS Gas’ therm sales and revenues for 2006, 2005 and 2004.
Through a Negotiated Sales Program (NSP) approved by the ACC, 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 Purchased Gas Adjustor (PGA) mechanism which reduces the gas commodity price. See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.
The table below provides summary financial information for UNS Gas.
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Retail therm sales were 2% higher in 2006 due primarily to customer growth. In 2006, retail revenues increased $24 million and purchased energy expense increased $23 million, due primarily to the PGA surcharge increase, which became effective in November 2005. See Factors Affecting Results of Operations, Rates and Regulation Energy, Energy Cost Adjustment Mechanism, below.
FACTORS AFFECTING RESULTS OF OPERATIONS
Rates
Energy Cost Adjustment Mechanism
UNS Gas’ retail rates include a PGA mechanism 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 gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or repaid 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 compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve-month period. The actual gas and transportation costs that are either under or over collected through the base rate of $0.40 per therm or $4.00 per MMBtu and the PGA factor are charged or credited to a balancing account (PGA bank). In the twelve months ended December 31, 2006, the average PGA factor was approximately $0.33 per therm or $3.33 per MMBtu.
The current annual cap on the maximum increase in the PGA factor is $0.10 per therm in a twelve-month period. As part of its general rate case proceeding with the ACC, UNS Gas requested to remove the cap to allow for more timely recovery of actual gas costs. See General Rate Case Filing, below.
When the ACC-designated under or over recovery trigger points of $6.2 million and $4.5 million, respectively, are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a period deemed appropriate by the ACC.
On December 31, 2006, the PGA bank balance was over-collected by $2 million on the basis as billed to customers. In December 2006, the ACC approved a proposal by UNS Gas that lowered the PGA surcharge to $0.05 per therm. The $0.05 per therm PGA surcharge will remain in effect through April 2007. Based on current projections of gas prices, UNS Gas believes that the lower surcharge amount will allow it to timely recover its gas costs and still provide rate relief to its customers.
Changes in the market price for gas, sales volumes and surcharge amount could significantly change the PGA bank balance in the future.
General Rate Case Filing
UNS Gas’ current rates have been in place since August 2003 and were designed to provide a 9.05% return on original cost rate base of $118 million. As a result of increased growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Gas to recover its costs and earn a reasonable rate of return on its investment. In July 2006, UNS Gas filed a general rate case. Below is a table that summarizes UNS Gas’ request:
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UNS Gas also requested modifications to its PGA mechanism to help address problems posed by volatile gas prices, inappropriate price signals to customers and the potential for over or under collections to result in the accumulation of large bank balances.
In February 2007, ACC staff filed testimony that indicated a revenue deficiency for UNS Gas of approximately $5 million; RUCO’s testimony indicated a revenue deficiency of approximately $2 million.
The procedural schedule for the UNS Gas rate case is as follows:
UNS Gas expects the ACC to rule on its rate case in the second half of 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Gas’ capital requirements consist primarily of capital expenditures. In 2006, capital expenditures were $23 million. UNS Gas expects internal 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 contribution from UniSource Energy. The need for external funding sources is partially dependent on the outcome of UNS Gas’ general rate case that was filed in July 2006.
Operating Cash Flow and Capital Expenditures
The table below provides summary information for operating cash flow and capital expenditures:
Forecasted capital expenditures for UNS Gas are as follows:
UNS Gas/UNS Electric Revolver
In August 2006, UNS Gas and UNS Electric amended and restated their existing unsecured revolving credit agreement (UNS Gas/UNS Electric Revolver). The amendment reduced the interest rate payable on borrowings and, upon ACC approval, will increase the amount of the revolving credit facility to $60 million from $40 million, and extend the maturity from April 2008 to August 2011. Currently, either borrower may borrow up to a maximum of $30 million, but the total combined amount borrowed cannot exceed $40 million. Upon ACC approval of the increase in the UNS Gas/UNS Electric Revolver, either borrower may borrow up to a maximum of $45 million so long as the combined amount borrowed does not exceed $60 million. The matter is pending before the ACC.
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. UES guarantees the obligations of both UNS Gas and UNS Electric.
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UNS Gas and UNS Electric have the option of paying interest at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.
The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, mergers and sales of assets; it also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower. As of December 31, 2006, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.
If an event of default occurs, the UNS Gas/UNS Electric Revolver may become immediately due and payable. An event of default includes failure to make required payments under the UNS Gas/UNS Electric Revolver, certain change in control transactions, certain bankruptcy events of UNS Gas or UNS Electric, or failure of UES, UNS Gas or UNS Electric to make payments or default on debt greater than $4 million.
UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of its capital expenditures. As of February 23, 2007, UNS Gas had no outstanding borrowings under the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Gas has $100 million of senior unsecured notes outstanding consisting of $50 million of 6.23% Notes due in 2011 and $50 million of 6.23% Notes due in 2015 that are guaranteed by UES. The note purchase agreement for UNS Gas restricts transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness, and also contains a minimum net worth test. As of December 31, 2006, UNS Gas was in compliance with the terms of its note purchase agreement.
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 $7 million in short-term debt.
Contractual Obligations
UNS Gas Supply Contracts
UNS Gas has a natural gas supply and management agreement with BP Energy Company (BP). Under the contract, BP manages UNS Gas’ existing supply and transportation contracts and its incremental requirements. The initial term of the agreement expired in August 2005. The agreement was automatically extended one year and will continue to extend on an annual basis unless either party provides 180 days notice of its intent to terminate. No termination notice has been tendered by either party. Prices for incremental gas supplied by BP will vary based upon the market prices for the period during which the gas is delivered.
UNS Gas hedges its gas supply prices by entering into fixed price forward contracts at various times during the year to provide more stable prices to its customers. These purchases 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 48% of its expected monthly consumption for the 2006/2007 winter season (November through March). Additionally, UNS Gas has approximately 36% of its expected gas consumption hedged for April through October 2007, and 29% hedged for the period November 2007 through March 2008.
UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its load requirements.
UNS Gas currently has a transportation agreement with EPNG to serve its Northern and Southern Arizona service territories. This agreement has specific contract volumes in each month and specific receipt point rights from the available supply basins (San Juan and Permian). The average daily capacity rights 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).
EPNG filed a rate case in 2005 with new, higher rates effective in January 2006, subject to refund. The rate case participants reached a negotiated settlement and filed an agreement with FERC on December 6, 2006. FERC is expected to take action on the settlement agreement in the first half of 2007. UNS Gas’ contract with EPNG expires in August 2011, with rights of first refusal for continuation thereafter.
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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, Arizona, and also delivers gas to UNS Gas’ facilities serving the Griffith Power Plant in Mohave County. The current contract with Transwestern expires in February 2007. UNS Gas entered into a new firm transportation contract with Transwestern through February 2012 with rights of first refusal for continuation thereafter. The new capacity rights under this agreement are: 250,000 therms per day October through April; 15,000 therms per day in May; and 10,000 therms per day June through September.
Transwestern filed a rate case in October 2006 with new, higher rates to be effective in April 2007. The rate case participants are attempting to negotiate a settlement prior to the new rates becoming effective.
The aggregate annual minimum transportation charges are expected to be approximately $9 million and $2 million for the EPNG and Transwestern contracts, respectively. These costs are passed through to our customers via the PGA.
Dividends on Common Stock
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. See Senior Unsecured Notes, above. It is unlikely, however, that UNS Gas will pay dividends in the next few years due to expected cash requirements for capital expenditures.
UNS ELECTRIC
RESULTS OF OPERATIONS
UNS Electric reported net income of $5 million in 2006 and 2005, and $4 million in 2004. Similar to TEP’s operations, we expect UNS Electric’s operations to be seasonal in nature, with peak energy demand occurring in the summer months.
As of December 31, 2006, UNS Electric had approximately 93,000 retail customers, a 4% increase from last year. Retail kWh sales were 6% higher in 2006 due primarily to customer growth. The table below shows UNS Electric’s kWh sales and revenues for 2006, 2005 and 2004.
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The table below provides summary financial information for UNS Electric.
FACTORS AFFECTING RESULTS OF OPERATIONS
Competition
As required by the ACC order approving UniSource Energy’s acquisition of the Citizens’ Arizona gas and electric assets, in 2003 UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003. The plan addressed all aspects of implementation. It included UNS Electric’s unbundled distribution tariffs for both standard offer customers and customers that choose competitive retail access, as well as Direct Access and Settlement Fee schedules. UNS Electric’s direct access rates for both transmission and ancillary services would be based upon its FERC Open Access Transmission Tariff. The plan is subject to review and approval by the ACC, which has not yet considered the plan. As a result of the court decisions concerning the ACC’s Rules, we are unable to predict when and how the ACC will address this plan. See Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, above for information regarding the Arizona Court of Appeals decision.
Rates
Energy Cost Adjustment Mechanism
UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under or over recovery of costs. The ACC has approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.
General Rate Case Filing
UNS Electric’s retail rates were last adjusted in August 2003. As a result of increased growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Electric to recover its costs and earn a reasonable rate of return on its investment. In December 2006, UNS Electric filed a general rate case. Below is a table that summarizes UNS Electric’s request:
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The procedural schedule for the UNS Electric rate case is as follows:
UNS Electric also requested the ACC to approve the acquisition of the 90 MW BMGS combustion turbine project under development by UED with a post test year rate base adjustment effective June 1, 2008. The cost of the BMGS is expected to cost $60 million.
UNS Electric expects the ACC to rule on its rate case in late 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
UNS Electric also requested that a new PPFAC surcharge take effect when the current power supply agreement with PWMT expires in May 2008.
Renewable Energy Standard and Tariff
See, Tucson Electric Power Company, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff, above.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Electric’s capital requirements consist primarily of capital expenditures. In 2006, capital expenditures were $39 million. UNS Electric expects internal cash flows to fund its future operating activities and a portion of its construction expenditures. 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 UniSource Energy. The need for external funding sources is partially dependent on the outcome of UNS Electric’s general rate case that was filed in December 2006.
In June 2006, UniSource Energy contributed $10 million of capital to UNS Electric.
Operating Cash Flow and Capital Expenditures
The table below provides summary information for operating cash flow and capital expenditures.
To improve the reliability of service in Santa Cruz County, UNS Electric completed a 20 MW gas-fired combustion turbine at the Valencia site in 2006, and plans to upgrade its existing 115 kV transmission line over time. The turbine improves reliability while the approval and permitting process for the 345 kV Tucson to Nogales transmission line continues. In 2006, UNS Electric’s capital expenditures included $7 million related to the turbine. See Item 1. Business, TEP Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.
Forecasted capital expenditures for UNS Electric are as follows:
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UNS Gas/UNS Electric Revolver
See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for 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 and to fund a portion of its capital expenditures. At February 23, 2007, UNS Electric had $25 million outstanding under the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Electric has $60 million of 7.61% senior unsecured notes outstanding due in 2008 that are guaranteed by UES. The note purchase agreements for UNS Electric contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, incurrence of indebtedness, and minimum net worth. As of December 31, 2006, UNS Electric was in compliance with the terms of its 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.
Contractual Obligations
UNS Electric Power Supply and Transmission Contracts
UNS Electric has a full requirements power supply agreement with Pinnacle West Marketing and Trading (PWMT), which expires in May 2008. The agreement obligates PWMT to supply all of UNS Electric’s power requirements at a fixed price per MWh. Payments under the contract are usage based, with no fixed customer or demand charges. UNS Electric is in the process of securing replacement energy resources when its supply contract ends with PWMT in 2008.
During 2006, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. As of December 31, 2006, UNS Electric estimates its future minimum annual payments under these contracts to be $27 million.
The new UNS Electric power purchase contracts are subject to master agreements whereby UNS Electric may be required to post margin due to changes in contract values or if there has been a material change in creditworthiness. As of December 31, 2006, UNS Electric had not been required to post such credit enhancement.
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 February 2008 and June 2011. The contract that expires in 2008 also contains a capacity adjustment clause. Under the terms of the agreements, UNS Electric’s aggregated minimum fixed transmission charges are expected to be $12 million in 2007 through 2011. UNS Electric made payments under these contracts of $8 million in 2006 and $7 million in 2005.
Dividends on Common Stock
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. See Senior Unsecured Notes, above. It is unlikely, however, that UNS Electric will pay dividends in the next few years due to expected cash requirements for capital expenditures.
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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.
UniSource Energy Parent Company
UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes, the UniSource Credit Agreement, and in 2004 and 2005, a note payable from UniSource Energy to TEP, which was repaid in March 2005.
UED
In 2006, UED purchased two electric generating turbines for $17 million. The turbines will be part of the 90 MW BMGS, to be constructed in Kingman, Arizona, and, pending ACC approval is expected to provide energy to UNS Electric. Construction is planned to begin during the third quarter of 2007 with an estimated completion date of May 2008. Including the purchase of the turbines, the total cost of the project is expected to be approximately $60 million. UED is financing the BMGS project with borrowings from UniSource Energy under an inter-company note payable. At December 31, 2006, there was $22 million outstanding and interest is payable quarterly at LIBOR plus 1.25%.
In 2005, UED had no significant operations.
In 2004, UED recognized an impairment loss on its note receivable from an independent power producer. As UED’s recovery of the note receivable from the entity is subordinated to the rights of others, UED wrote off the entire $2 million balance due on the note at the time that Haddington, an investor in the independent power producer, determined that its investment was impaired. In 2004, UED’s net loss was $1 million.
Discontinued Operations - Global Solar
Global Solar recorded losses of $2 million in 2006, $5 million in 2005 and $5 million in 2004. On March 31, 2006, Millennium completed the sale of its interest in Global Solar. In these financial statements, UniSource Energy accounts for Global Solar as a discontinued operation and recognizes 100% of Global Solar’s losses.
FACTORS AFFECTING RESULTS OF OPERATIONS
Millennium Investments
MEG is in the process of winding down its activities and does not expect to engage in any significant new activities. As of December 31, 2006, the fair value of MEG’s trading assets was $11 million and the fair value of MEG’s trading liabilities was $5 million.
Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary of Millennium, has been inactive since 2001. As of December 31, 2006, and December 31, 2005, Nations Energy had a deferred tax asset of $3 million related to investment losses that has not been reflected on UniSource Energy’s consolidated income tax return.
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Millennium is in the process of exiting its remaining investments. At December 31, 2006, the book value of Millennium’s investments was $28 million.
LIQUIDITY AND CAPITAL RESOURCES
Millennium made a $5 million dividend payment to UniSource Energy in February 2007 and is expected to make additional dividend payments totaling $10 million to UniSource Energy during the first half of 2007.
In 2006, Millennium funded $2 million to Haddington under an existing commitment. In 2005, Haddington sold one of its investments and Millennium received a $6 million distribution related to the sale. In 2004, Millennium received a $7 million distribution from Haddington related to the gain on a sale of one of its investments. Millennium’s remaining commitment is $1 million to Valley Ventures.
In 2006, Millennium received the remaining payment of $5 million on a note receivable from a subsidiary of Mirant Corporation and, in 2005, received a payment of $4 million.
Millennium funded the remainder of its commitment to IPS in 2006. Millennium owns less than 10% of the equity of IPS.
In 2005, Millennium received a $4 million payment from its investment in Carboelectrica Sabinas, S. de R.L. de C.V., (Sabinas) a Mexican limited liability company. The $4 million payment was treated as the return of capital and the book value of the investment in Sabinas was reduced to approximately $14 million. Millennium owns 50% of Sabinas. A $2 million payment due to Millennium in June 2006 was cancelled in exchange for payment by Mimosa, an affiliate of Sabinas, for up to $2 million to obtain a valuation of the interest in coal reserves and associated gas held by Mimosa. This evaluation is being performed under Millennium's direction, primarliy to determine the impact of current regulatory changes in Mexico on the value of the Sabinas investment. We expect the evaluation to be completed in 2007.
UniSource Energy has ceased making loans or equity contributions to Millennium. We anticipate that the funding required to fund Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments. We believe such cash and returns will be adequate to fund Millennium’s remaining commitments.
CRITICAL ACCOUNTING ESTIMATES
In preparing financial statements under Generally Accepted Accounting Principles (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions. UniSource Energy and TEP consider Critical Accounting Estimates to be those that could result in materially different financial statement results if our assumptions regarding application of accounting principles were different. UniSource Energy and TEP describe their Critical Accounting Estimates below. Other significant accounting policies and recently issued accounting standards are discussed in Note 1 of Notes to Consolidated Financial Statements - Nature of Operations and Summary of Significant Accounting Estimates.
Accounting for Rate Regulation
TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. However, sometimes these principles, such as the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation. For example, in setting TEP, UNS Gas and UNS Electric’s retail rates, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that these expenses be charged to customers in the future. In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until TEP, UNS Gas and UNS Electric are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expense to the income statement as these charges are recovered from customers. Similarly, certain revenue items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:
·
an independent regulator sets rates;
·
the regulator sets the rates to recover specific costs of delivering service; and
·
the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.
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TEP
Upon approval by the ACC of a settlement agreement (Settlement Agreement) in November 1999, TEP discontinued application of FAS 71 for its generation operations. TEP continues to apply FAS 71 to its cost-based rate regulated operations, which include the transmission and distribution portions of its business.
TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $118 million at December 31, 2006. Regulatory assets of $61 million are not presently included in the rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through the cost of service or are authorized to be collected in future base rates. TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $163 million at December 31, 2005.
TEP regularly assesses whether it can continue to apply FAS 71 to its cost-based rate regulated operations. If TEP stopped applying FAS 71 to its remaining regulated operations, it would write off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at December 31, 2006, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $71 million. While regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if it stopped applying FAS 71 unless a regulatory order limited its ability to recover the cost of its regulatory assets.
UNS Gas and UNS Electric
UNS Gas regulatory liabilities, net of regulatory assets, totaled $13 million at December 31, compared with regulatory assets, net of regulatory liabilities of $3 million at December 31, 2005. UNS Electric’s regulatory liabilities, net of regulatory assets, totaled $12 million at December 31, 2006 and $7 million at December 31, 2005. UNS Electric has $11 million of regulatory liabilities and $1 million of regulatory assets that are not included in rate base. UNS Gas and UNS Electric regularly assess whether they can continue to apply FAS 71 to their cost-based rate regulated operations. If UNS Gas and UNS Electric stopped applying FAS 71 to their regulated operations, they would write off the related balances of regulatory assets as an expense and regulatory liabilities as income on their income statements. Based on the balances of regulatory liabilities and assets at December 31, 2006, if UNS Gas and UNS Electric had stopped applying FAS 71 to their regulated operations, UNS Gas would record an extraordinary after-tax gain of $8 million and UNS Electric would record an extraordinary after-tax gain of $7 million. UNS Gas and UNS Electric’s cash flows would not be affected if they stopped applying FAS 71 unless a regulatory order limited their ability to recover the cost of their regulatory assets.
Accounting for Asset Retirement Obligations
FAS 143, issued by the FASB, requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. A legal obligation can also be associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event. We are required to record a conditional asset retirement obligation at its estimated fair value if that fair value can be reasonably estimated. When the liability is initially recorded, the entity should capitalize a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense as an operating expense in the income statement each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount.
TEP
In 2005, TEP implemented FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). The implementation of FIN 47 required TEP to update an existing inventory, originally created for the implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated. The ability to reasonably estimate conditional asset retirement obligations was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of TEP’s conditional asset retirement obligations. In determining whether its conditional asset retirement obligations could be reasonably estimated, management considered TEP’s past practices, industry practices, management’s intent and the estimated economic life of the assets. The fair value of the
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conditional asset retirement obligations were then estimated using an expected present value technique. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have a material effect on the liability recorded by TEP at December 31, 2006 as well as the associated cumulative effect of the change in accounting principle recorded. The liabilities associated with conditional asset retirement obligations will be adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Income. For more information regarding the implementation and ongoing application of FIN 47, see Notes 1 and 3 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies and Accounting Change: Accounting for Asset Retirement Obligations.
Prior to implementing FAS 143, costs for final removal of all owned generation facilities were accrued as an additional component of depreciation expense. Under FAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost. As of December 31, 2006, TEP had a liability of $4 million associated with its final asset retirement obligations.
TEP has 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. TEP also has certain environmental obligations at the San Juan Generating Station. TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the San Juan environmental obligations will be approximately $40 million at the date of retirement. No other legal obligations to retire generation plant assets were identified.
In 2004, TEP, Phelps Dodge Energy Services, LLC and PNM Resources, Inc. each purchased from Duke Energy North America, LLC a one-third interest in a limited liability company which owns the natural gas-fired Luna Energy Facility (Luna) in Southern New Mexico. Luna is a 570-MW combined cycle plant and was placed into commercial operation in April 2006. See Item 1. - Business, Future Generating Resources - TEP. The new owners assumed asset retirement obligations to remove certain piping and evaporation ponds and to restore the ground to its original condition. TEP has estimated its share to settle the obligations will be approximately $2 million at the date of retirement.
TEP has various transmission and distribution lines that operate under land 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 a result, TEP is not recognizing the costs of final removal of the transmission and distribution lines in the financial statements. As of December 31, 2006, TEP had accrued $80 million for the net cost of removal for the interim retirements from its transmission, distribution and general plant. As of December 31, 2005, TEP had accrued $75 million for these removal costs. The amount is recorded as a regulatory liability.
Amounts recorded under FAS 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and the credit-adjusted risk-free interest rates to be used to discount 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.
If TEP retires any asset at the end of its useful life, without a legal obligation to do so, it will record retirement costs at that time as incurred or accrued. TEP does not believe that the implementation of FAS 143 will result in any change in retail rates since all matters relating to the rate-making treatment of TEP’s generating assets have been determined pursuant to the Settlement Agreement.
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.
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For the net cost of removal for interim retirements from transmission, distribution and general plant, UNS Gas accrued $4 million as of December 31, 2006 and $3 million as of December 31, 2005. UNS Electric accrued $2 million as of December 31, 2006 and $1 million as of December 31, 2005. The amounts are recorded as regulatory liabilities.
Pension and Other Postretirement Benefit Plan Assumptions
We record plan assets, obligations, and expenses related to pension and other postretirement 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 under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries.
TEP
As a result of adopting FAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, in December 2006, TEP recognized the underfunded status of our defined benefit pension and other postretirement plans as a liability. The underfunded status was measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated postretirement benefit obligation for other postretirement benefit plans. We expect volatility in the liability recognized in the balance sheet in future years as the funded status of our plans can change significantly due to discount rate changes and investment and actuarial experience. The adjustment required to recognize the pension liability on adoption of this statement resulted in (i) recognition of a regulatory asset of $32 million representing a reasonable appropriation of the actuarial losses and prior service costs of TEP’s pension plans that are probable of recovery in rates by its regulated operations in future periods and (ii) an adjustment to accumulated other comprehensive loss of $17 million for our unregulated operations. We recorded the required increase in our other postretirement benefit obligation as an adjustment to accumulated other comprehensive loss of $8 million as the ACC allows TEP, UNS Gas and UNS Electric to recover other postretirement costs through rates only as benefit payments are made. Any change in the funded status of our plans due to discount rate changes and investment and actuarial experience will be recognized as an adjustment to regulatory assets and other comprehensive income.
TEP discounted its future pension plan obligations at 5.9% at December 31, 2006 and 5.8% at December 31, 2005. TEP discounted its other postretirement plan obligations at a rate of 5.6% at December 31, 2006, and 5.8% at December 31, 2005. TEP determines the discount rate annually based on the rates currently available on high-quality, non-callable, long-term bonds. TEP looks to bonds that receive one of the two highest ratings given by a recognized rating agency whose future cash flows match the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point decrease in the discount rate would increase the projected benefit obligation (PBO) by approximately $7 million and the 2007 plan expense by approximately $1 million. A similar increase in the discount rate would decrease the PBO by approximately $8 million and the 2007 plan expense by approximately $1 million. For TEP’s other postretirement 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 approximately $0.1 million.
TEP calculates the market-related value of plan assets using the fair value of plan assets on the measurement date. TEP assumed that its plans’ assets would generate a long-term rate of return of 8.3% at December 31, 2006 and 8.5% at December 31, 2005. In establishing its assumption as to the expected return on plan assets, TEP reviews the plans’ asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the plans’ 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 plan assets increases. A 25-basis point change in the expected return on plan assets would impact pension expense in 2007 by less than $0.5 million.
TEP used an initial health care cost trend rate of 9.0% in valuing its postretirement benefit obligation at December 31, 2006. This rate reflects both market conditions and the plan’s experience. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A 1% increase in assumed health care cost trend rates would increase the postretirement benefit obligation by approximately $5 million and the related plan expense in 2007 by less than $1 million. A similar decrease in assumed health care cost trend rates would decrease the postretirement benefit obligation by approximately $4 million and the related plan expense in 2007 by less than $1 million.
TEP will record pension expense of approximately $9 million and other postretirement benefit expense of $5 million ratably through 2007. TEP will make required pension plan
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contributions of $10 million in 2007. TEP’s other postretirement benefit plan is not funded. TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $3 million in 2007.
UNS Gas and UNS Electric
UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 5.9% at December 31, 2006 and December 31, 2005. For UNS Gas and UNS Electric's pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and pension expense by less than $0.5 million. UNS Gas and UNS Electric will record pension expense of $1 million in 2007. UNS Gas and UNS Electric will make a pension plan contribution of $1 million in 2007.
UNS Gas and UNS Electric discounted its other postretirement plan obligations using a rate of 5.6% at December 31, 2006, compared with 5.8% at December 31, 2005. UNS Gas and UNS Electric will record postretirement medical benefit expense and make benefit payments to retirees under the postretirement benefit plan of approximately $0.1 million in 2007.
Accounting for Derivative Instruments, Trading Activities and Hedging Activities
A derivative financial instrument or other contract derives its value from another investment or designated benchmark. TEP enters into forward contracts to purchase or sell a specified amount of capacity or energy at a specified price 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. A portion of TEP’s forward contracts are considered to be normal purchases and sales and, therefore, are not required to be marked-to-market. However, some of these forward contracts are considered to be derivatives, which TEP marks-to-market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month. However, some of these forward contracts which are derivatives satisfy the requirements for cash flow hedge accounting and the unrealized gains and losses are recorded in Other Comprehensive Income, a component of Common Stock Equity, rather than being reflected in the income statement. Derivative financial instruments can be accounted for under multiple methods depending upon facts and circumstances, which can lead to variability in earnings.
TEP has a natural gas supply agreement, that expires in February 2007, under which it purchases its gas requirements for its generating units located in Tucson, Arizona at spot market prices. TEP also has agreements to purchase power that are priced using spot market gas prices. These contracts meet the definition of normal purchases and are not required to be marked-to-market. In an effort to minimize price risk on these purchases, TEP enters into commodity price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices. The spot market price in the swap agreements is tied to the same index as the purchases under the natural gas supply and purchased power contracts. These swap agreements, which expire during the summer months through 2009, were entered into with the goal of locking in fixed prices on at least 45% and not more than 80% of TEP’s expected summer monthly gas risk prior to entering into the month. The swap agreements are marked-to-market on a monthly basis; however, since the agreements satisfy the requirements for cash flow hedge accounting, the unrealized gains and losses are recorded in Other Comprehensive Income rather than being reflected in the income statement.
In June 2006, TEP entered into an interest rate swap in order to reduce the risk associated with unfavorable changes in variable interest rate payments related to changes in LIBOR. The swap has the effect of converting approximately $37 million of variable rate lease payments for the Springerville Common Lease to a fixed rate. The swap is designated as a cash flow hedge. The fair value of the interest rate swap is derived from models based on well recognized financial principles, which provide a reasonable approximation of the fair value of the swap as of the valuation date. Other models can be used to estimate the fair value of the swap and these models, which may use different assumptions or methods, may yield different results. At December 31, 2006, the fair value of the swap is a liability of $2 million.
TEP manages 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.
UNS Gas does not currently have any contracts that are required to be marked-to-market. UNS Gas does have a natural gas supply and management agreement under which it purchases substantially all of its gas requirements
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at market prices from BP Energy Company (BP). However, the contract terms allow UNS Gas to lock in fixed prices on a portion of its gas purchases by entering into fixed price forward contracts with BP at various times during the year. This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% and not more than 80% of the expected monthly gas consumption prior to entering into the month. These forward contracts, as well as the main gas supply contract, meet the definition of normal purchases and therefore are not required to be marked-to-market.
UNS Electric presently has a full requirements power supply agreement that enables it to meet its load. The agreement expires May 31, 2008 and UNS Electric is in the process of replacing this energy resource. In order to reduce exposure to energy price risk resulting from the procurement of power, UNS Electric has entered into forward power purchase contracts for specified amounts of energy at specified prices over a given period of time, within established limits. UNS Electric’s forward power purchase contracts meet the definition of a derivative and are marked-to-market by recording unrealized gains or losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month. In December 2006, the ACC issued an order allowing UNS Electric to record the unrealized net gains or losses as a regulatory asset or regulatory liability.
MEG, a wholly-owned subsidiary of Millennium, enters into swap agreements, options and forward contracts relating to Emission Allowances. MEG marks its trading contracts to market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month. In accordance with UniSource Energy’s intention to cease making capital contributions to Millennium, Millennium has significantly reduced the holdings and activity of MEG. MEG’s activities consist of managing a small number of remaining positions which are expected to close by early 2008.
The market prices used to determine fair values for TEP, UNS Electric and MEG’s derivative instruments at December 31, 2006, are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value. For TEP’s forward power sales contracts, a 10% decrease in market prices would result in an increase in unrealized net gains of $3 million, while a 10% increase in market prices would result in a decrease in unrealized net gains of $3 million. For TEP’s forward power purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses of $3 million, while a 10% increase in market prices would result in a decrease in unrealized net losses of $3 million. For TEP’s forward power contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $1 million increase in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $1 million decrease in unrealized gains reported in Other Comprehensive Income. For TEP’s gas swap agreements, a 10% decrease in market prices would result in a $3 million increase in unrealized net losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $3 million decrease in unrealized net losses reported in Other Comprehensive Income. For UNS Electric’s forward power purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $10 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $10 million. For MEG’s remaining trading contracts, a 10% decrease in market prices or a 10% increase in market prices would be less than $0.1 million. The unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded.
Because of the complexity of derivatives, the FASB established a Derivatives Implementation Group (DIG). To date, the DIG has issued more than 100 interpretations to provide guidance in applying Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). As the DIG or the FASB continues to issue interpretations, TEP, UNS Gas and UNS Electric may change the conclusions they have reached and, as a result, the accounting treatment and financial statement impact could change in the future.
See Market Risks - Commodity Price Risk in Item 7A.
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.
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For additional information concerning risk factors, including market risks, see Safe Harbor for Forward-Looking Statements, above.
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, the emissions and trading activities of MEG, 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 the generation operations departments of UniSource Energy. To limit TEP, UNS Gas, UNS Electric and MEG’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, UNS Electric and MEG’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.
Interest Rate Risk
TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. At December 31, 2006 and 2005, TEP’s debt included $329 million of tax-exempt variable rate debt. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 3.47% in 2006 and 2.48% in 2005. In June 2006, TEP refinanced variable rate lease debt totaling $68 million related to its Springerville Common Facilities Leases. The notes underlying the leases mature in June 2017 and January 2020. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. The interest rate in effect on the lease debt was 7.13% at December 31, 2006, and 7.68% at December 31, 2005. A 1% increase (decrease) in average interest rates would result in a decrease (increase) in TEP’s pre-tax income by approximately $4 million.
A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the floating rate lease debt. On June 8, 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest rate portion of rent at 7.27% on $37 million of the lease debt.
Marketable Securities Risk
TEP is exposed to fluctuations in the return on its marketable securities, which is comprised of investments in debt securities. At December 31, 2006 and 2005, TEP had marketable debt securities with an estimated fair value of $139 million and $165 million, respectively. At December 31, 2006 and 2005, the fair value exceeded the carrying value by $6 million and $9 million, respectively. These debt securities represent TEP’s investments in lease debt 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
We are exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances.
TEP
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 locational 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
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Management Committee. For example, the risk management policies provide that TEP should not take a short position in the third quarter and must have owned generation backing up all 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.
The majority of TEP’s forward contracts are considered to be “normal purchases and sales” of electric energy and are not considered to be derivatives under FAS 133. TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered. From time to time, however, TEP enters into forward contracts that meet the definition of a derivative under FAS 133. 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.
To adjust the value of its derivative forward power sales and purchases, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:
TEP also reported the following net unrealized gains and losses on forward power sales and purchases in Wholesale Sales and Purchased Power.
TEP uses sensitivity analysis to measure the impact of an unfavorable change in market prices on the fair value of its derivative forward contracts. As of December 31, 2006, for TEP’s forward power sales contracts, a 10% decrease in market prices would result in an increase in unrealized net gains of $3 million, while a 10% increase in market prices would result in a decrease in unrealized net gains of $3 million. For TEP’s forward power purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses of $3 million, while a 10% increase in market prices would result in a decrease in unrealized net losses of $3 million.
For TEP’s forward power contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $1 million increase in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $1 million decrease in unrealized gains reported in Other Comprehensive Income. The unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded.
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 purchased power, 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 purchase power 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.
In 2006, the average market price of natural gas was $6.05 per MMBtu, or 16% lower than 2005. The table below summarizes TEP’s gas generation output and purchased power for 2006, 2005 and 2004.
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To adjust the value of its derivative gas swap contracts, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:
As of December 31, 2006, for TEP’s gas swap agreements, a 10% decrease in market prices would result in a $3 million increase in unrealized losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $3 million decrease in unrealized losses reported in Other Comprehensive Income.
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 will be determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling. Based on current coal market conditions, this range would be from $24 to $30 per ton. TEP estimates its future minimum annual payments under this contract to be $45 million through 2010, the initial contract expiration date, and $14 million from 2011 through 2020. TEP’s coal transportation contract at Springerville runs through June of 2011. TEP estimates minimum annual payments under this contract to be $13 million through 2010 and $7 million in 2011.
In December 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through December 2008. Although TEP expects to pay $20 million annually, the total amount paid under these agreements depends on the number of tons of coal purchased and transported. In 2007, the impact on TEP’s total coal-related fuel expense across all of its plants is expected to increase by $17 million, or 9%.
The long-term rail contract for Sundt Unit 4 is in effect until the earliest of 2015, the remaining life of Sundt Unit 4 or the life of the coal mine. This rail contract requires TEP to transport at least 75,000 tons of coal per year through 2015 at an estimated annual cost of $2 million or to make a minimum payment of $1 million.
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. In 2003, the Four Corners coal contract was extended through July 2016. This contract requires TEP to purchase minimum amounts of coal at an estimated annual cost of $6 million. 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, UniSource Energy Consolidated, Contractual Obligations and Note 6 of Notes to Consolidated Financial Statements - Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.
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 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.
UNS Electric
UNS Electric is currently not exposed to commodity price risk for its purchase of electricity as it has a fixed price full-requirements supply agreement with PWMT and a PPFAC mechanism which fully recovers the costs incurred
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under such contract on a timely basis. This supply agreement with PWMT expires in May 2008 and UNS Electric is in the process of replacing this energy resource.
During 2006, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. As of December 31, 2006, UNS Electric estimates its future minimum annual payments under these contracts to be $23 million.
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 purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $10 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $10 million.
MEG
MEG trades Emission Allowances and related instruments; however, its current activities consist of managing a small number of remaining positions which are expected to close by early 2008. We manage the market risk of this line of business by setting notional limits by product, as well as limits to the potential change in fair market value under a 33% change in price or volatility. We closely monitor MEG’s trading activities, which include swap agreements, options and forward contracts, using risk management policies and procedures overseen by the Risk Management Committee.
MEG marks its trading positions to market on a daily basis using actively quoted prices obtained from brokers and options pricing models for positions that extend through 2007. As of December 31, 2006 and December 31, 2005, the fair value of MEG’s trading assets combined with Emission Allowances it holds in escrow was $11 million and $38 million, respectively. The fair value of MEG’s trading liabilities was $5 million at December 31, 2006 and $24 million at December 31, 2005. For 2006, MEG reflected a $10 million unrealized loss and a $10 million realized gain on its income statement, compared with an unrealized gain of $11 million and a realized loss of $11 million in the same period last year. For MEG’s remaining trading contracts at December 31, 2006, a 10% decrease in market prices or a 10% increase in market prices would be less than $1 million.
Credit Risk
UniSource Energy is exposed to credit risk in its energy-related marketing and trading activities related to potential nonperformance by counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standard agreement which allows 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. As of December 31, 2006, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $34 million. Approximately $2 million of TEP’s exposure is to non-investment grade companies. TEP had five counterparties with exposures of greater than 10% of its total credit exposure, totaling approximately $23 million. MEG’s total credit exposure related to its trading activities was $5 million and was concentrated primarily with two counterparties. MEG has no credit exposure to non-investment grade counterparties.
UNS Gas is subject to credit risk from non-performance by its supply counterparty, BP Energy (BP), to the extent that this contract has a mark-to-market value in favor of UNS Gas. As of December 31, 2006, UNS Gas
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has purchased under fixed price contracts approximately 48% of the expected monthly consumption for the 2006/2007 winter season (November through March) and approximately 29% of its expected consumption for the 2007/2008 winter season. At December 31, 2006, UNS Gas had no credit exposure under its supply contract with BP.
UNS Electric has begun to enter into energy purchase agreements to replace the full requirements contract it has with PWMT that expires in May 2008. To the extent that such contracts have a positive mark-to-market value, UNS Electric would be exposed to credit risk under those contracts. At December 31, 2006, UNS Electric had less than $1 million in credit exposure under such contracts.
ITEM 8.
ITEM 8. - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Controls Over Financial Reporting
UniSource Energy Corporation’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 the UniSource Energy Corporation’s internal control over financial reporting as of December 31, 2006. 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, 2006, UniSource Energy Corporation’s internal control over financial reporting was effective.
Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
UniSource Energy Corporation:
We have completed integrated audits of UniSource Energy Corporation's 2006 and consolidated financial statements and of its internal control over financial reporting for each of the three years in the period ended December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) and the financial statement schedule listed in the index appearing under Item 15(a)(2), respectively present fairly, in all material respects, the financial position of UniSource Energy Corporation and its subsidiaries at December 31, 2006 and December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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) present 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 of financial statements 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.
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As described in Note 12 to the consolidated financial statements, the company changed the manner in which it accounts for pension and post-retirement obligations as a result of implementing Financial Accounting Standards Board Standard No. 158 as of December 31, 2006.
As described in Note 3 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No. 47 as of December 31, 2005.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management's Report on Internal Controls Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides 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
Chicago, Illinois
February 26,
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Tucson Electric Power Company:
In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) and financial statement schedule listed in index appearing under Item 15(a)(2), respectively present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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) present 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.
As described in Note 12 to the consolidated financial statements, the company changed the manner in which it accounts for pension and post-retirement obligations as a result of implementing Financial Accounting Standards Board Standard No. 158 as of December 31, 2006.
As described in Note 3 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No. 47 as of December 31, 2005.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 26,
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* TEP’s Variable Rate industrial development bonds (IDBs) are backed by letters of credit (LOCs) issued pursuant to TEP’s Credit Agreement which expires in August 2011. Although the Variable Rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. Weighted average interest rates on variable rate tax-exempt debt ranged from 2.95 % to 3.96% during 2006 and 1.52% to 3.55% during 2005, and the average interest rate on such debt was 3.47% in 2006 and 2.48% in 2005.
UniSource Energy also has stock options outstanding. See Note 13.
See Notes to Consolidated Financial Statements.
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(Consolidated Balance Sheets Continued)
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(Consolidated Balance Sheets Concluded)
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* TEP’s Variable Rate industrial development bonds (IDBs) are backed by letters of credit (LOCs) issued pursuant to TEP’s Credit Agreement which expires in August 2011. Although the Variable Rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. Weighted average interest rates on this variable rate tax-exempt debt ranged from 2.95% to 3.96% during 2006 and 1.52% to 3.55% during 2005, and the average interest rate on such debt was 3.47% in 2006 and 2.48% in 2005.
See Notes to Consolidated Financial Statements.
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We describe limitations on TEP's ability to pay dividends in Note 10.
See Notes to Consolidated Financial Statements.
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
UniSource Energy Corporation (UniSource Energy) is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the common stock of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development Company (UED).
TEP, a regulated public utility, is UniSource Energy’s largest operating subsidiary and represented approximately 82% of UniSource Energy’s assets as of December 31, 2006. TEP generates, transmits and distributes electricity to approximately 392,000 retail electric customers in a 1,155 square mile area in Southern Arizona. TEP also sells electricity to other utilities and power marketing entities primarily located in the Western U.S. In addition, TEP operates Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State).
UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a gas distribution company with 145,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in Southeast Arizona. UNS Electric is an electric transmission and distribution company with approximately 93,000 retail customers in Mohave and Santa Cruz counties.
Millennium invests in unregulated energy related businesses. On March 31, 2006, UniSource Energy completed the sale of all of the capital stock of Global Solar, Inc. (Global Solar), Millennium’s largest subsidiary, to a third party. We present Global Solar’s assets, liabilities and related operations throughout this report as a discontinued operation. See Note 16.
UED is facilitating the expansion of the Springerville Generating Station and other generation resources.
We conduct our business in three primary business segments - TEP, UNS Gas and UNS Electric.
References to “we” and “our” are to UniSource Energy and its subsidiaries, collectively.
BASIS OF PRESENTATION
We account for our investments in subsidiaries using the consolidation method when we hold a majority of a subsidiary’s voting stock and we can exercise control over the subsidiary. The accounts of the subsidiary and parent are combined, and intercompany balances and transactions are eliminated.
We use the equity method to report corporate joint ventures, partnerships, and affiliated company investments when we can demonstrate the ability to exercise significant influence over the operating and financial policies of an investee company. Equity method investments appear on a single line item on the balance sheet and net income (loss) from the entity is reflected in Other Income on the income statements.
UniSource Energy held the following equity investments at December 31, 2006:
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
USE OF ACCOUNTING ESTIMATES
We make estimates and assumptions to prepare financial statements under accounting principles generally accepted in the U.S. (GAAP). These estimates and assumptions affect:
·
A portion of the reported amounts of assets and liabilities at the dates of the financial statements;
·
Our disclosures about contingent assets and liabilities at the dates of the financial statements; and
·
A portion of revenues and expenses reported during the periods.
Because these estimates involve judgments, the actual amounts may differ from the estimates.
ACCOUNTING FOR RATE REGULATION
The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) regulate portions of TEP’s, UNS Gas’ and UNS Electric’s utility accounting practices and rates. The ACC authorizes certain rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. The FERC regulates TEP’s and UNS Electric’s rates for wholesale power sales and transmission services.
TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies. Sometimes these principles, such as Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation. For example, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that they charge these expenses to customers in the future. In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until they are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expense as they recover these charges from customers. Similarly, certain revenue items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:
·
an independent regulator sets rates;
·
the regulator sets the rates to recover specific costs of providing service; and
·
the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.
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.
RESTRICTED CASH
Restricted cash represents cash deposits that have withdrawal restrictions, or are set aside for a specific use and not available for general current operations. Cash deposits that are restricted for a period of less than one year, or that are restricted as to use but are available to meet specific current operational requirements, are classified on the balance sheet as Other Current Assets. Balances that are restricted as to withdrawal for more than one year or are designated for a purpose other than current operations are classified on the balance sheet as Investments and Other Property, Other. At December 31, 2006, restricted cash includes cash on deposit in support of our self-insured medical and workman’s compensation plans, amounts on deposit for credit enhancement with counterparties and deposits to meet contractual and regulatory requirements.
UTILITY PLANT
TEP, UNS Gas and UNS Electric report utility plant at cost. Costs included in Utility Plant are:
·
Material and labor,
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
·
Contractor services,
·
Construction overhead (where applicable), and
·
An Allowance for Funds Used During Construction (AFUDC) or capitalized interest during construction.
AFUDC reflects the cost of financing construction for transmission and distribution projects with borrowed and equity funds.
The component of AFUDC attributable to borrowed funds is included as a reduction of Other Interest Expense on the income statement. The equity component is included in Other Income. The interest capitalized during construction of TEP’s generation-related construction projects is included as a reduction of Other Interest Expense.
The table below summarizes TEP’s cost of capital, average capitalized interest rates, AFUDC and capitalized interest for the last three years. The imputed cost of capital on transmission and distribution construction expenditures reflects the cost of using borrowed and equity funds to finance construction, and the average capitalized interest rate applies to generation-related construction expenditures. AFUDC and capitalized interest are presented in millions of dollars.
The tables below summarize UNS Gas and UNS Electric’s cost of capital and AFUDC for the last three years. The imputed cost of capital reflects the cost of using borrowed and equity funds to finance construction.
Depreciation
TEP, UNS Gas and UNS Electric compute depreciation for owned utility plant on a straight-line basis at rates based on the economic lives of the assets. See Note 7. The ACC approves depreciation rates for all plant except TEP’s deregulated generation assets. The depreciable lives for TEP’s generation plant are based on remaining useful lives. Note 7 discusses changes made to the depreciable lives of TEP’s generation plant. The depreciation rates for generation plant reflect interim retirements. Interim retirements of generation plant, together with removal costs less salvage, are charged to accumulated depreciation. The costs of planned major maintenance activities
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
are recorded as the costs are actually incurred. Planned major maintenance activities include the scheduled overhauls at TEP’s generation plants. We expense minor replacements and repairs as incurred.
The depreciable lives for transmission, distribution, general and intangible plant are based on average lives. The rates reflect estimated removal costs, net of estimated salvage value for interim retirements. Retirements of transmission plant, distribution plant, general plant and intangible plant, together with the cost of removal less salvage, are charged to accumulated depreciation. Amounts collected through revenues for the net cost of removal of interim retirements for transmission, distribution, general and intangible plant which are not yet expended, are reflected as a regulatory liability.
We have summarized the average annual depreciation rates for all utility plants below.
Computer Software Costs
TEP, UNS Gas and UNS Electric capitalize all costs incurred to purchase 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 amortized capitalized computer software costs of $7 million in 2006 and $8 million in both 2005 and 2004.
TEP Utility Plant under Capital Leases
TEP financed the following generation assets with capital leases:
·
Springerville Common Facilities,
·
Springerville Unit 1,
·
Springerville Coal Handling Facilities, and
·
Sundt Unit 4.
The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases. We describe the lease terms in TEP Capital Lease Obligations in Note 8.
ASSET RETIREMENT OBLIGATIONS
FASB Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), requires entities to record the fair value of a liability for a legal obligation to perform asset retirement activity in which the timing and (or) method of settlement depends on a future event that may or may not be within the control of the entity.
We record a liability for the fair value of a conditional asset retirement obligation as follows:
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
·
when we are 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 we can reasonably estimate the fair value.
When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, we adjust the liability to its present value by recognizing accretion expense as an operating expense in the income statement each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss if the actual costs differ from the recorded amount.
EVALUATION OF ASSETS FOR IMPAIRMENT
TEP, UNS Gas, and UNS Electric evaluate their Utility Plant and other long-lived assets for impairment whenever events or circumstances indicate that the value of the assets may be impaired. If the fair value of the asset determined based on the undiscounted expected future cash flows is less than the carrying value of the asset, an impairment charge would be recorded.
Millennium evaluates its investments for impairment at the end of each quarter. Investments are considered to be impaired when a decline in fair value is judged to be other-than-temporary. If the fair value is determined to be other-than-temporary, an impairment loss would be recorded.
INVESTMENTS IN LEASE DEBT
TEP’s investments in lease debt are considered to be held-to-maturity investments because TEP has the ability and intent to hold until maturity. TEP records these investments at amortized costs and recognizes interest income. TEP presents these investments in Investments in Lease Debt on the balance sheet and classifies them as investing activities on its cash flow statements.
DEBT
We defer costs related to the issuance of debt. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting and regulatory fees and printing costs. We amortize these costs over the life of the debt using the straight-line method, which approximates the effective interest method.
TEP recognizes gains and losses on reacquired debt associated with the generation portion of its operations as incurred. TEP defers and amortizes the gains and losses on reacquired debt associated with its regulated operations to interest expense over the remaining life of the original debt.
UTILITY OPERATING REVENUES
TEP and UES record utility operating revenues when services are provided or commodities are delivered to customers. Operating revenues include unbilled revenues which are earned (service has been provided) but not billed by the end of an accounting period.
We estimate unbilled sales for the month by estimating the number of billed and unbilled kWhs or therms, as applicable, for each billing cycle. We then allocate current month estimated unbilled kWhs or therms by customer class. Finally, we record new unbilled revenue estimates and reverse unbilled revenue estimates from the prior month.
We record an Allowance for Doubtful Accounts to reduce accounts receivable for revenue amounts that are estimated to become uncollectible. TEP, UNS Gas and UNS Electric establish an allowance for doubtful accounts receivable based on historical experience and any specific customer collection issues identified. TEP’s Allowance for Doubtful Accounts was $16 million at December 31, 2006 and $15 million at December 31, 2005. UNS Gas and UNS Electric’s combined Allowance for Doubtful Accounts was less than $1 million at December 31, 2006 and 2005.
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
FUEL AND PURCHASED ENERGY COSTS
TEP
TEP records fuel inventory, primarily coal, at weighted average cost. TEP uses full absorption costing, under which, all handling and procurement costs are included in the cost of the inventory. Examples of these costs include direct material, direct labor, overhead costs and mine reclamation expenses. TEP has long-term contracts for the purchase and transportation of coal with various expiration dates from 2008 through 2020. If certain minimum quantities of coal are not purchased, the contracts require TEP to pay a take-or-pay fee. TEP expenses such fees as they are incurred. TEP recorded take-or-pay fees of less than $0.1 million in 2006, 2005 and 2004. See Purchase and Transportation Commitments in Note 6, below.
UNS Gas
UNS Gas defers differences between actual gas purchase costs and the revenues received to recover such costs under a Purchased Gas Adjustor (PGA) mechanism. The PGA mechanism addresses the volatility of natural gas prices and allows UNS Gas to recover its commodity costs through a price adjustor. We may change the PGA charge monthly based on an ACC approved mechanism that compares the twelve-month rolling average gas cost to the base cost of gas, subject to limitations on how much the price per therm may change in a twelve-month period. The difference between the actual cost of UNS Gas’ gas supplies and transportation contracts and that currently allowed by the ACC is deferred and recovered or repaid through the PGA mechanism. When under or over recovery trigger points are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a twelve-month period. UNS Gas had a liability for over recovered purchased gas costs of $11 million at December 31, 2006 which is included in Current Liabilities - Current Regulatory Liabilities on our consolidated balance sheet and an asset for under recovered purchased gas costs of $6 million at December 31, 2005 which is included in Regulatory and Other Assets - Other Regulatory Assets. See Note 2 Regulatory Matters.
UNS Electric
UNS Electric defers differences between purchased energy costs and the recovery of such costs in revenues. Future billings are adjusted for such deferrals through use of a Purchased Power and Fuel Adjustment Clause (PPFAC) approved by the ACC. The PPFAC allows for a revenue surcharge or credit (that adjusts the customer’s base rate for delivered purchased power) to collect or return under or over recovery of costs. UNS Electric had a liability for over recovered purchased power costs of $6 million at December 31, 2006 and $4 million at December 31, 2005 that is included in Deferred Credits and Other Liabilities - Regulatory Liabilities on our consolidated balance sheet. See Note 2 Regulatory Matters.
INCOME TAXES
GAAP requires us to report some of our assets and liabilities differently for our financial statements than we do for income tax purposes. We report the tax effects of differences in these items as deferred income tax assets or liabilities in our balance sheets. We measure these tax assets and liabilities using current income tax rates. Federal Investment Tax Credits (ITC) as well as applicable state income tax credits are accounted for as a reduction of income tax expense in the year in which the credit arises.
We allocate income taxes to the subsidiaries based on their taxable income and deductions as reported in the consolidated tax return filings.
EMISSIONS ALLOWANCES
The Environmental Protection Agency (EPA) issues emissions allowances to qualifying utilities based on past operational history. Each allowance permits emission of one ton of sulfur dioxide (SO2) in its vintage year or a subsequent year. TEP receives an allotment of these allowances annually, but UNS Electric does not receive any since it has no coal-fired generation. When issued from the EPA, these allowances have no book value for accounting purposes but may be sold if TEP does not need them for operations. TEP also may purchase additional allowances if needed. The gains from sales of excess allowances are reflected as a reduction of Other Operations and Maintenance expense on TEP’s income statement and are recognized when title passes.
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
DERIVATIVE FINANCIAL INSTRUMENTS
TEP uses derivative financial instruments including forward power sales and purchases and gas swaps to manage exposure to energy price risk. TEP entered into an interest rate swap to reduce the risk associated with unfavorable changes in the variable interest rate on the Springerville Common Lease. UNS Electric enters into forward power purchase agreements that meet the definition of derivatives. MEG enters into swap agreements, options and forward contracts relating to Emission Allowances. TEP, UNS Electric and MEG record derivative instruments at fair value. To reflect the market prices at the end of the month, TEP, UNS Electric and MEG record unrealized gains and losses and adjust the related assets and liabilities on a monthly basis. In December 2006, the ACC granted UNS Electric an accounting order to record the unrealized gains and losses as a regulatory asset or a regulatory liability. As these contracts settle, the actual costs of the power purchased are charged to the PPFAC. Certain of TEP’s derivatives meet the criteria for cash flow hedge accounting. See Note 5, Accounting for Derivative Instruments, Trading Activities and Hedging Activities.
We report TEP, UNS Electric and MEG’s derivative activities as follows:
Although we report MEG’s realized gains and losses on trading activities on a net basis in our income statement, we report the related cash receipts and cash payments separately in our statement of cash flows.
We report TEP, UNS Electric and MEG’s derivative assets and liabilities as follows:
SHARE-BASED COMPENSATION
Effective January 1, 2005, we prospectively adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment (FAS 123(R)). Before January 1, 2005, we accounted for our share-based compensation under the principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), and related interpretations and applied the disclosure only guidance in Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation. Our share-based compensation plans are described more fully in Note 13. All our stock options were granted with an exercise price equal to the market value of the stock at the date of the grant. Accordingly, before January 1, 2005, under the provisions of APB 25, no compensation expense was recorded for these awards. However, compensation expense was recognized for restricted stock, stock unit and performance share awards over the performance/vesting period. Beginning January 1, 2005, under the provisions
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
of FAS 123(R), we began recognizing compensation expense over the vesting period for the fair value of new stock options granted.
The following table illustrates the effect on UniSource Energy’s Net Income and earnings per share and TEP’s Net Income as if we had applied the fair value recognition provisions of FAS 123 to all share-based employee compensation awards that vested during the year ended December 31, 2004:
NEW ACCOUNTING STANDARDS
The FASB recently issued the following Statements of Financial Accounting Standards (FAS), FASB Interpretations (FIN), FASB Staff Positions (FSP), and Emerging Issues Task Force Issues (EITF):
·
EITF 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (that is, Gross versus Net Presentation), approved June 2006, requires that we disclose our accounting policy regarding presentation of taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. Additionally, we must disclose the amounts of any taxes reported on a gross basis in interim and annual financial statements. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. See Note 11 for our disclosures.
·
FIN 48, Accounting for Uncertainty in Income Taxes - an interpretation of FAS 109, issued July 2006, requires us to determine whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a tax position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. Additionally, FIN 48 requires disclosure of a rollforward of total unrecognized tax benefits. FIN 48 is effective for fiscal years beginning after December 15, 2006. TEP recognized between $1 million and $2 million of income as an increase to Common Stock Equity on January 1, 2007 on the adoption of FIN 48.
·
FAS 157, Fair Value Measurement, issued September 2006, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FAS 157 clarifies that the exchange price is the price in the principal market in which the reporting entity would transact for the asset or liability. We are required to disclose inputs used to develop fair value measurements and the effect of any of our assumptions on earnings or changes in net assets for the period. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are evaluating the impact of FAS 157 on our financial statements, and will
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incorporate these additional disclosure requirements in our financial statements for the quarter ended March 31, 2008.
·
FSP AUG-AIR-1, Accounting for Planned Major Maintenance Activities, issued September 2006, prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities effective in fiscal years beginning after December 15, 2006. As we do not accrue planned major maintenance activities in advance, we anticipate no impact on our financial statements from the adoption of this FSP.
·
FAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, issued September 2006, requires recognition of the overfunded or underfunded status of a defined benefit postretirement plan measured as the difference between the fair value of the plans assets and benefit obligation. FAS 158 is effective for fiscal years ending after December 15, 2006. See Note 12 for the incremental effect of adopting FAS 158.
·
In the third quarter of 2006, the Pension Protection Act of 2006 was signed into law, which will be effective January 1, 2008. The new law will affect the manner in which many companies, including UniSource Energy and TEP, administer their pension plans. The legislation will require companies to increase the amount by which they fund their pension plans, increase premiums to the Pension Benefit Guaranty Corporation for defined benefit plans, amend plan documents and provide additional disclosures in regulatory filings and to plan participants. We are currently assessing the impact it may have on our financial statements.
RECLASSIFICATIONS
We reclassified prior year financial statements and footnotes for comparative purposes. These reclassifications had no effect on Net Income.
NOTE 2. REGULATORY MATTERS
TEP RATES AND REGULATION
Upon approval of the TEP Settlement Agreement in 1999, TEP discontinued regulatory accounting under FAS 71 for its generation operations. TEP continues to report its transmission and distribution operations under FAS 71.
TEP Settlement Agreement
In 1999, the ACC approved the Rules for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.
The Rules and the Settlement Agreement established:
·
a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;
·
the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (Fixed CTC);
·
capped rates for TEP retail customers through 2008;
·
an ACC interim review of TEP retail rates in 2004;
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unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;
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a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers;
·
access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs);
·
transmission and distribution services would remain subject to regulation on a cost of service basis; and
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·
beginning in 2009, TEP’s generation would be market-based and its retail customers would pay the market rate for generation services.
General Rate Case Information
In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC. While TEP’s filing did not propose any change in retail rates, the filing, with a test year ended December 31, 2003, showed that TEP was experiencing a revenue deficiency of $111 million, reflecting the need for an increase in retail rates of 16%.
Beginning in May 2005, TEP filed a series of pleadings with the ACC to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008.
Proceedings
In April 2006, the ACC ordered that a procedure be established to allow for a review of:
·
the Settlement Agreement and its effect on how TEP’s rates for generation services will be determined after December 31, 2008;
·
TEP’s proposed amendments to the Settlement Agreement; and
·
demand-side management (DSM), renewable energy standards (RES), and time of use tariffs (TOU).
In August 2006, TEP filed testimony in the ACC proceedings stating that TEP believes it is entitled to charge market-based generation service rates in 2009 and is in compliance with the Settlement Agreement. In addition, TEP offered a Market Phase-in proposal and a Cost-of-Service Proposal as alternatives to charging market-based generation service rates after December 31, 2008.
Transition Recovery Asset
TEP’s Transition Recovery Asset consists of generation-related regulatory assets and a portion of TEP’s generation plant asset costs. Transition costs being recovered through the Fixed CTC include: (1) the Transition Recovery Asset; (2) generation-related plant assets included in Plant in Service on the balance sheet; and (3) excess capacity deferrals related to operating and capital costs associated with Springerville Unit 2 which were amortized as an off-balance sheet regulatory asset through 2003. These transition costs were amortized as follows:
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We amortized the portion of the Transition Recovery Asset that is recorded on the balance sheet as follows:
The remaining transition costs being recovered through the Fixed CTC differ from the Transition Recovery Asset recorded on the balance sheet as follows:
We will amortize the remaining Transition Recovery Asset balance as costs are recovered through rates until TEP has recovered $450 million of transition costs or until December 31, 2008, whichever occurs first.
Other Regulatory Assets and Liabilities
In addition to the Transition Recovery Asset related to TEP’s generation assets, we recover the following regulatory assets and liabilities through TEP’s transmission and distribution businesses:
Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:
·
Property Tax, Self-Insured Medical Deferrals are recorded based on historical ratemaking treatment allowing TEP to recover property taxes and self-insured medical costs. While these assets do not earn a return, they are fully recovered in rates over an approximate one-year period.
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·
Income Taxes Recoverable Through Future Revenues are currently earning a return and are approved by the ACC.
·
Pension Assets were recorded in 2006 as based on past regulatory actions, TEP expects to recover in rates the transmission and distribution portion of the underfunded Salaried and Union pension plans. TEP does not earn a return on these costs.
·
Deregulation costs were incurred to comply with various ACC deregulation orders. TEP received ACC approval to defer these costs. The recovery period will be determined in TEP’s next rate case. TEP does not earn a return on these costs.
·
Unamortized Loss on Reacquired Debt Costs related to TEP’s regulated business are, in accordance with FERC guidelines, amortized over the remaining life of the related debt instruments. While the asset is not included in rate base, the amortization is included in the ratemaking calculation of the cost of debt. TEP does not earn a return on these costs.
Regulatory liabilities represent items that we expect to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:
·
Net cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations.
Income Statement Impact of Applying FAS 71
The amortization of TEP’s regulatory assets affected UniSource Energy’s and TEP’s income statements as follows:
If TEP had not applied FAS 71 in these years, the above amounts would have been reflected in the income statements in prior periods. The reclassification of TEP’s generation-related regulatory assets to the Transition Recovery Asset shortened the amortization period for these assets to nine years.
Future Implications of Discontinuing Application of FAS 71
TEP continues to apply FAS 71 to its regulated operations, which include the transmission and distribution portions of its business. TEP regularly assesses whether it can continue to apply FAS 71 to these operations. If TEP stopped applying FAS 71 to its remaining regulated operations, it would write-off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at December 31, 2006, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $71 million. While regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if we stopped applying FAS 71.
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UNS GAS RATES AND REGULATION
Energy Cost Adjustment Mechanism
UNS Gas’ retail rates include a PGA mechanism 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 gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or repaid through the PGA mechanism.
The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations, on how much the price per therm may change in a twelve-month period. The actual gas and transportation costs that are either under- or over-collected through the base rate of $0.40 per therm or $4.00 per MMBtu and the PGA factor are charged or credited to a balancing account (PGA bank).
The current annual cap on the maximum increase in the PGA factor is $0.10 per therm in a twelve-month period. In January 2006, UNS Gas filed a request with the ACC to increase the cap to allow for more timely recovery of actual gas costs. In July 2006, UNS Gas requested this application be consolidated with its general rate case proceeding. See General Rate Case Filing, below.
When ACC-designated under- or over-recovery trigger points of $6.2 million and $4.5 million, respectively, are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a period deemed appropriate by the ACC.
In 2005, the ACC approved the PGA surcharges from November 2005 to April 2007. In December 2006, the ACC approved a proposal by UNS Gas that lowered the PGA surcharge to $0.05 per therm in December 2006. The $0.05 per therm PGA surcharge will remain in effect through April 2007.
Based on current projections of gas prices, UNS Gas believes that the lower surcharge amount will allow it to timely recover its gas costs and still provide rate relief to its customers. However, changes in the market price for gas, sales volumes and surcharge amount could significantly change the PGA bank balance in the future.
The following table shows the balance of purchased gas costs:
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Other Regulatory Assets and Liabilities
In addition to the Under/(Over) Recovered Purchased Power Costs, UNS Gas has the following Regulatory Assets and Liabilities:
Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:
·
Pension Assets were recorded in 2006 as based on past regulatory actions, UNS Gas expects to recover in rates the UNS Gas portion of the underfunded pension plan for UNS Gas employees. UNS Gas does not earn a return on these costs.
·
Other Regulatory assets relate primarily to UNS Gas’ low income assistance program. These deferrals were authorized by the ACC and are included in rate base and consequently earn a return.
Regulatory liabilities represent items that we expect to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:
·
Net cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations.
General Rate Case Filing
In July 2006, UNS Gas filed a general rate with the ACC requesting a total rate increase of 7% to cover a revenue deficiency of $10 million. This increase is necessary because of the growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs.
UNS Gas also requested modifications to its PGA mechanism to help address problems posed by volatile gas prices, inappropriate price signals to customers and the potential for over- or under-collections to result in the accumulation of large bank balances.
UNS Gas expects the ACC to rule on its rate case in the second half of 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
Income Statement Impact of Applying FAS 71
If UNS Gas had not applied FAS 71, net income would have been $11 million higher in 2006 as UNS Gas would have been able to recognize over-recovered gas costs as a credit to the income statement rather than record a regulatory liability. In 2005, net income would have been $2 million lower had UNS Gas not been able to defer under-recovered gas costs as a regulatory asset.
Future Implications of Discontinuing Application of FAS 71
UNS Gas regulatory liabilities exceeded its regulatory assets by $13 million at December 31, 2006. Regulatory assets exceeded regulatory liabilities by $3 million at December 31, 2005. UNS Gas regularly assesses whether it can continue to apply FAS 71. If UNS Gas stopped applying FAS 71 to its regulated operations, UNS Gas would
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write-off the related balance of its regulatory assets as an expense and write-off its regulatory liabilities as income on its income statement. Based on the regulatory asset and liability balances, if UNS Gas had stopped applying FAS 71 to its regulated operations, UNS Gas would have recorded an extraordinary after-tax gain of $8 million at December 31, 2006. Discontinuing application of FAS 71 would not affect UNS Gas cash flows.
UNS ELECTRIC RATES AND REGULATION
Energy Cost Adjustment Mechanism
UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under- or over-recovery of costs. The ACC approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.
General Rate Case Filing
In December 2006, UNS Electric filed a general rate case with the ACC requesting a total rate increase of 5.5% to cover a revenue deficiency of $9 million. The increase is necessary because of the growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs.
UNS Electric expects the ACC to rule on its rate case in late 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
UNS Electric also requested that a new PPFAC surcharge take effect when the current power supply agreement with PWMT expires in May 2008.
Regulatory Assets and Liabilities
UNS Electric’s regulatory assets and liabilities were as follows:
Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:
·
Pension Assets were recorded in 2006 as based on past regulatory actions, UNS Electric expects to recover in rates the UNS Electric portion of the underfunded pension plan for UNS Electric employees. UNS Electric does not earn a return on these costs.
Regulatory liabilities represent items that we expect to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below.
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·
Deferred Environmental Friendly Portfolio Surcharge represents amounts the ACC has authorized UNS Electric to collect, through customer billings, for environmental improvement projects. The amounts are deferred until they are spent on their intended use.
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UNS Electric defers differences between purchased energy costs and the recovery of such costs in revenues. Future billings are adjusted for such deferrals through use of a Purchased Power and Fuel Adjustment Clause (PPFAC) approved by the ACC. The PPFAC allows for a revenue surcharge or surcredit (that adjusts the customer’s base rate for delivered purchased power) to collect or return under- or over-recovery of costs.
·
In December 2006, the ACC granted UNS Electric an Accounting Order authorizing regulatory deferral of unrealized gains and losses on derivative forward purchase contracts that are required to be marked-to-market under FAS 133.
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Net cost of Removal for Interim Retirements represents an estimate of future asset retirement obligations.
Income Statement Impact of Applying FAS 71
If UNS Electric had not applied FAS 71, net income would have been $3 million higher in 2006 and $1 million higher in 2005, as UNS Electric would have been able to recognize over-recovered purchased power costs as a credit to the income statement rather than record an increase to regulatory liabilities.
Future Implications of Discontinuing Application of FAS 71
UNS Electric regularly assesses whether it can continue to apply FAS 71 to its operations. If UNS Electric stopped applying FAS 71 to its regulated operations, it would write-off the related balances of their regulatory assets as an expense and would write-off its regulatory liabilities as income on their income statement. Based on the regulatory asset and liability balances, if UNS Electric had stopped applying FAS 71 to its regulated operations, it would have recorded an extraordinary after-tax gain of $7 million at December 31, 2006. Discontinuing application of FAS 71 would not affect UNS Electric’s cash flows.
NOTE 3. ACCOUNTING CHANGE: ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
In 2005, TEP implemented FIN 47. The implementation of FIN 47 required TEP to update an existing inventory, originally created for the implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated. The significant conditional asset retirement obligations identified include:
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The removal and disposal of asbestos at the Sundt Generating Station
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Remediation of the evaporative ponds upon decommissioning of our generating stations
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The disposal of equipment contaminated with polychlorinated biphenlys (PCBs) in our distribution system.
In determining whether its conditional asset retirement obligations could be reasonably estimated, management considered TEP’s past practices, industry practices, management’s intent and the estimated economic life of the assets. Management then estimated the fair value of the conditional asset retirement obligations using an expected present value technique.
Upon implementation of FIN 47, we recorded an asset retirement obligation of $16 million at its net present value of $3 million, increased depreciable assets by an immaterial amount for asset retirement costs and recognized the cumulative effect of accounting change as a loss of less than $1 million net of tax. Had FIN 47 been in effect in 2004, there would be no change in reported financial results.
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NOTE 4. 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 vertically integrated electric utility business, is our largest subsidiary.
(2)
UNS Gas is a regulated gas distribution utility business.
(3)
UNS Electric is a regulated electric distribution utility business.
The UniSource Energy, UES and Millennium holding companies, UED, and several other subsidiaries and equity investments, which are not considered reportable segments, are included in All Other. All Other also includes the discontinued operations of Global Solar. As discussed in Note 16, at March 31, 2006, Millennium sold all of the common stock of Global Solar and the results of operations of Global Solar are reported as a discontinued operation for all periods presented. Through affiliates, Millennium holds investments in several unregulated energy and emerging technology companies. UED develops generating resources and performs other project development activities.
Significant revenues and expenses included in All Other include the following:
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In 2006, Millennium recorded an after-tax loss of approximately $2 million related to the discontinued operations and disposal of Global Solar.
·
In 2005, Millennium recorded an after-tax gain of $2 million related to a gain on the sale of an investment by one of its investees. Millennium also recognized an impairment loss of $1 million in 2005 related to the sale of one of its investments in January 2006.
·
In 2004, Millennium recorded an after-tax gain of $3 million related to gains and losses on sales of investments by its investees.
·
In 2004, UED recognized an impairment loss on the entire $2 million balance of a note receivable.
Reconciling adjustments consist of the elimination of intercompany activity and balances. Millennium’s subsidiaries recorded revenue from transactions with TEP of $14 million in 2006, $12 million in 2005 and $13 million in 2004. TEP’s related expense is reported in Other Operations and Maintenance expense on its income statement. Millennium’s revenue and TEP’s related expense are eliminated in UniSource Energy consolidation. Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UniSource Energy, the intercompany note between UniSource Energy and TEP, the related interest income and expense on the note and reclassifications of deferred tax assets and liabilities. UniSource Energy repaid the intercompany note in 2005. See Note 8.
Our portion of the net income (loss) of the entities in which TEP and Millennium own a voting interest or have the ability to exercise significant influence is shown below in Net Income (Loss) from Equity Method Entities.
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We disclose selected financial data for our reportable segments in the following tables:
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NOTE 5. ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES
TEP INTEREST RATE SWAP
In June 2006, TEP entered into an interest rate swap to reduce the risk of unfavorable changes in variable interest rates related to changes in LIBOR. The swap has the effect of converting approximately $37 million of variable rate lease payments for the Springerville Common Lease to a fixed rate through January 1, 2020. The swap is designated as a cash flow hedge for accounting purposes. The changes in interest payments related to changes in LIBOR were completely offset by the interest rate swap in the last half of 2006. At December 31, 2006, the fair value of the swap of approximately $2 million is recorded in Other Liabilities and the unrealized loss is recorded in Other Comprehensive Income, a component of Common Stock Equity. Amounts accumulated in Other Comprehensive Income will be reclassified to Interest on Capital Leases over the term of the lease. At December 31, 2006, we expect less than $1 million to be reclassified into earnings over the next 12 months.
TEP FUEL AND POWER TRANSACTIONS
TEP enters into forward contracts to purchase or sell a specified amount of capacity or energy at a specified price over a given period of time, within established limits to take advantage of favorable market opportunities and reduce exposure to energy price risk resulting from generation and procurement of power. In general, TEP enters into forward power 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 power sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. In addition, TEP has natural gas supply agreements under which it purchases all of its gas requirements at spot market prices. In an effort to minimize price risk on these purchases, TEP enters into price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.
All of TEP’s forward power sale contracts and forward power purchase contracts meet the accounting definition of a derivative. Under the accounting rules, TEP has three types of derivatives related to forward purchase and sales contracts.
·
Normal Purchase and Sale - A portion of TEP’s forward power contracts are considered to be normal purchases and sales and, therefore, are not required to be marked to market.
·
Cash Flow Hedges - Some of TEP’s forward power contracts and all of the gas swap agreements are accounted for as cash flow hedges. Unrealized gains and losses resulting from the change in the fair value of derivatives that meet the criteria for cash flow hedge accounting are recorded in Other Comprehensive Income, rather than in current earnings. Unrealized gains and losses are reclassified into earnings when the related transactions settle or terminate. There were no gains or losses recognized in Net Income related to hedge ineffectiveness because all cash flow hedges are considered to be effective.
·
Mark-to-Market - The change in fair value of forward power contracts, which are not accounted for as normal purchases and sales or cash flow hedges, is recorded in Net Income.
The settlement of forward power purchase and sales contracts that do not result in physical delivery are recorded net as a component of Electric Wholesale Sales in TEP’s income statement. During 2006, approximately $78 million in sales were netted against approximately $75 million in purchases. During 2005, $15 million in sales were netted against $16 million in purchases and in 2004, $5 million in sales were netted against approximately $5 million in purchases.
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The net unrealized gains and losses from TEP’s fuel and power related derivative activities were as follows:
The fair value of TEP’s fuel and power related derivative assets and liabilities were as follows:
At December 31, 2006, the contracts accounted for as cash flow hedges will settle through the fourth quarter of 2009. Amounts presented as Cash Flow Hedges, Derivative Assets - Current and Derivative Liabilities - Current, are expected to be reclassified into earnings within the next twelve months. TEP reclassified less than $1 million of net unrealized gains and losses into earnings from Other Comprehensive Income during 2006. TEP reclassified $6 million of net unrealized gains and losses into earnings from Other Comprehensive Income during 2005.
UNS GAS SUPPLY TRANSACTIONS
UNS Gas does not currently have any contracts that are required to be marked-to-market. UNS Gas purchases substantially all of its gas requirements at market prices under a natural gas supply and management agreement with BP Energy Company (BP). However, the contract terms allow UNS Gas to lock in fixed prices on a portion of its expected forward gas purchases from BP. This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% of the expected monthly gas consumption prior to entering into the month. These forward purchases, as well as the main gas supply contract, meet the definition of normal purchases and therefore are not required to be marked-to-market.
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UNS ELECTRIC POWER SUPPLY TRANSACTIONS
UNS Electric purchases all of its electricity under a full requirements power supply agreement that will expire May 31, 2008. UNS Electric is in the process of replacing this energy resource for periods after May 2008. In order to reduce the risk of unfavorable changes in future power procurement prices, UNS Electric has entered into forward power purchase contracts for specified amounts of energy at specified prices over a given period of time. UNS Electric’s forward power purchase contracts meet the definition of a derivative and are required to be marked to market each reporting period. However, in December 2006, the ACC granted UNS Electric an accounting order to record the unrealized gains and losses as a regulatory asset or a regulatory liability.
The fair value of UNS Electric’s derivative asset is $3 million as of December 31, 2006. During 2006, UNS Electric recorded net unrealized gains of $3 million in Deferred Credits and Other Liabilities - Other Regulatory Liabilities. UNS Electric did not have any derivatives during 2005.
At December 31, 2006, the settlement dates of contracts accounted for as cash flow hedges extended through the fourth quarter of 2013. UNS Electric does not have any current Derivative Assets or Liabilities that are expected to be reclassified into earnings within the next twelve months.
MEG TRADING TRANSACTIONS
MEG, a wholly-owned subsidiary of Millennium, enters into swap agreements, options and forward contracts relating to Emissions Allowances. MEG marks its trading contracts to market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month.
MEG had a net loss from trading activities of less than $1 million in 2006 and 2005. MEG had a net gain from trading activities of $1 million in 2004.
The fair value of MEG’s derivative assets and liabilities were as follows:
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 nonperformance by counterparties pursuant to the terms of their contractual obligations. TEP, UNS Gas and UNS Electric 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 mark-to-market valuations. As of December 31, 2006, TEP had total credit exposure of $34 million related to its wholesale marketing and gas hedging activities, of which five counterparties individually composed greater than 10% of the total credit exposure. As of December 31, 2006, MEG had total credit exposure related to its trading activities of $5 million and was concentrated primarily with two counterparties. As of December 31, 2006, UNS Gas had no credit exposure related to its forward contracts with its gas supply counterparty. As of December 31, 2006, UNS Electric had a total credit exposure related to its forward power purchase contracts of less than $1 million, primarily related to its relationship with two counterparties. TEP calculates counterparty credit exposure by
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adding any outstanding receivables (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts.
NOTE 6. COMMITMENTS AND CONTINGENCIES
TEP COMMITMENTS
Purchase and Transportation Commitments
TEP has several long-term coal purchase and transportation contracts with various expiration dates from 2008 through 2020. Amounts paid under these contracts depend on the number of tons of coal purchased and transported. Some of these contracts (i) include a price adjustment clause that will affect the future cost of coal and (ii) require TEP to pay a take-or-pay charge or liquidated damages if certain minimum quantities of coal are not purchased and/or transported. Current fuel requirements are in excess of the take-or-pay minimums. TEP made payments under these contracts of $184 million in 2006 and $175 million in 2005 and 2004.
In November 2005, TEP entered into a natural gas Transportation Supply Agreement (TSA) with El Paso Natural Gas (EPNG) to fuel TEP’s portion of the Luna facility. The contract began in February 2006 and has an initial term of three years. TEP made payments under this contract of $2 million in 2006.
Tri-State Generation and Transmission Association, Inc. (Tri-State) leases Springerville Unit 3, a 400 MW coal-fired generating facility at TEP’s existing Springerville Generating Station, from a financial owner. TEP provides operating, maintenance and other services to Springerville Unit 3 under a 99-year operating agreement subject to cancellation by either party with 30 days notice. TEP also agreed to purchase up to 100 MW of Tri-State system capacity for no more than five years beginning September 1, 2006. Tri-State may reduce the 100 MW available to TEP in 25 MW increments by submitting written notice to TEP at least 90 days in advance. To date, TEP has received no such notice. TEP made minimum capacity payments under this contract of $10 million in 2006.
At December 31, 2006, TEP estimates that future minimum payments under the contracts for purchased power, coal, and gas referred to above are as follows:
Operating Leases
TEP’s consolidated operating lease expense, which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates, was $1 million in each of the years 2006, 2005 and 2004. TEP’s estimated future minimum payments under non-cancelable operating leases are approximately $1 million per year from 2007 to 2010.
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Environmental Regulation
Federal Clean Air Act Amendments
TEP generating facilities are subject to EPA limits on the amount of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions into the atmosphere. TEP capitalized $1 million in each of 2006 and 2005, and $9 million in 2004 in construction costs to comply with environmental requirements and expects to capitalize $18 million in 2007 and $42 million in 2008. In addition, TEP recorded operating expenses of $10 million in 2006, $11 million in 2005 and $9 million in 2004 related to environmental compliance, including the cost of lime used to scrub the stacks. TEP expects environmental expenses to be $11 million in each of the years 2007 and 2008.
In 1993, the EPA allocated TEP’s generating units SO2 Emissions Allowances based on past operational history. Beginning in 2000, TEP’s generating units were required to hold Emissions Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years. To date TEP has had sufficient Emissions Allowances to comply with the SO2 regulations. However, due to potential changes in the legislation affecting SO2 emission levels, TEP may have to purchase additional Emissions Allowances for future compliance in years 2011 or beyond.
Mercury Emissions
In 2005, the EPA adopted regulations relating to mercury emissions requiring states to develop rules for implementing federal requirements. Arizona adopted its mercury emission limits in 2007 and TEP must meet these limits by 2013. TEP is analyzing the potential impact of the Arizona regulations on its operations but does not expect the capital costs to exceed $5 million. TEP is also monitoring the New Mexico and Navajo Nation mercury emission regulations affecting plants for which TEP has an ownership share. Until these state procedures are adopted, TEP cannot determine if it will be significantly affected.
Greenhouse Gas Emissions
Federal, state and local legislative and regulatory bodies are considering the regulation of greenhouse gas emissions. At this time, we do not know whether any such regulations will be adopted, the scope of such regulations or how any such regulations could affect our operations.
Regional Haze
The EPA's Regional Haze Rule requires states to develop plans to restore visibility in various areas to their natural conditions by 2064. State plans, which must be submitted to the EPA in December 2007, could require pollution control upgrades at some of TEP's power plants. The level of control required, if any, will not be known until the state plans are submitted and approved by EPA. If required, controls must be in place by 2013 or later.
TEP may incur additional costs to comply with recent and future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.
Tucson to Nogales Transmission Line
TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson to Nogales, Arizona. This project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona.
In 2002, the ACC approved the location and construction of the proposed 345-kV line along the Western Corridor route subject to a number of conditions, including obtaining all required permits from state and federal agencies. TEP is currently seeking approvals for the project from the Department of Energy (DOE), the US Forest Service, the Bureau of Land Management, and the International Boundary and Water Commission.
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The DOE has completed a Final Environmental Impact Statement (EIS) for the project in which it would accept any of the routes in the EIS, but the U.S. Forest Service has indicated the Central route as its preferred alternative, rather than the Western Corridor route.
Based on the alternative proposals and passage of time since it approved the location of the line, the ACC, in January 2005, ordered TEP to review the status of electric service reliability in Nogales, Arizona and the need for the 345-kV line. The ACC also indicated that it would review any new information regarding the location of the proposed transmission line. In December 2005, an Administrative Law Judge (ALJ) for the ACC issued a recommended opinion and order reaffirming the ACC’s original position requiring the construction of the Tucson to Nogales transmission line. After a hearing on the issue, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona. TEP expects the ACC to address the ALJ’s amended recommended opinion and order in 2007.
If TEP does not receive the required approvals it may need to expense a portion of the $11 million of costs that have been capitalized related to the project.
TEP Guarantee Home Program
TEP provides incentives to new home builders to construct TEP Guarantee Homes that meet the highest construction and energy-efficiency standards available. TEP made builder incentive payments of $2 million in 2006 and $1 million in 2005 and 2004. TEP has commitments to make payments under this program of $2 million in 2007 and less than $0.5 million in 2008.
UNS GAS COMMITMENTS
UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its load requirements. The EPNG contract expires in August 2011 and the Transwestern contract expires in February 2012. EPNG provides gas transportation service under a converted full requirements contract in which UNS Gas pays a fixed reservation charge. The minimum expected annual payment is $7 million. UNS Gas made payments under the EPNG and Transwestern contracts of $10 million in 2006 and $7 million in 2005 and 2004.
At December 31, 2006, UNS Gas estimates its future minimum payments under these contracts to be:
See Note 8 for a description of the UNS Gas and UNS Electric long-term debt.
UNS ELECTRIC COMMITMENTS
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 February 2008 and June 2011. The contract that expires in 2008 also contains a capacity adjustment clause. UNS Electric made payments under these contracts of $8 million in 2006, $7 million in 2005, and $6 million in 2004.
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UNS Electric’s all requirements contract expires in 2008. During 2006, UNS Electric entered into agreements to purchase power beginning in 2008 through 2011. The contracts are valued based on either fixed prices or indexed to NYMEX natural gas prices as of December 31, 2006.
At December 31, 2006, UNS Electric estimates its future minimum payments under these contracts to be:
UNS GAS and UNS ELECTRIC OPERATING LEASES
UNS Gas and UNS Electric’s combined operating lease expense which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates was $1 million in each of the years 2006, 2005 and 2004. UNS Gas and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are approximately $1 million per year from 2007 to 2011 and $2 million thereafter.
MILLENNIUM COMMITMENTS
Millennium has a remaining obligation to fund its subsidiaries for capital and operations up to an additional $1 million over the next two years.
UED COMMITMENTS
In October 2006, UED purchased two electric generating turbines for $17 million. The turbines will be part of a 90 MW power project to be constructed in Kingman, Arizona in UNS Electric’s service area. Construction is expected to begin during the third quarter of 2007 with an estimated completion date of May 2008. Including installation and refurbishment of the turbines, the total cost of the project for UED is expected to be $60 million, of which $40 million remains unpaid.
TEP CONTINGENCIES
Litigation and Claims Related to San Juan Generating Station
Public Service Company of New Mexico (PNM), operator of San Juan, and the coal supplier to San Juan have been participating in sessions sponsored by the Environmental Protection Agency (EPA) to consider rulemaking for the disposal of coal combustion products because of claims by third parties that San Juan has contaminated water resources in the region as a result of disposing of fly ash in the surface mine pits adjacent to the generating station. A contractor for the EPA has determined that there is no conclusive evidence that contamination can be attributed to fly ash disposal. TEP owns 50% of San Juan Units 1 and 2, which equates to 19.8% of the total San Juan Generating Station. TEP does not believe that this issue will have a material adverse impact on TEP or its operations.
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Claims Related to San Juan Coal Company
San Juan Coal Company, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine. Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine. These gas producers allege that San Juan Coal Company’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover. San Juan Coal Company has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant shutting down the well. These settlements, however, do not resolve all potential claims by gas producers in the underground mine area. TEP cannot estimate the outcome of any future claims by these gas producers on the cost of coal at San Juan.
Litigation and Claims Related to Navajo Generating Station
In 2004, Peabody Western Coal Company (Peabody), the coal supplier to the Navajo Generating Station, filed a complaint in the Circuit Court for the City of St. Louis, Missouri (Circuit Court) against the participants at Navajo, including TEP, for reimbursement of royalties and other costs and breach of the coal supply agreement. Because TEP owns 7.5% of the Navajo Generating Station, its share of the current claimed damages would be approximately $35 million. TEP believes these claims are without merit and intends to continue to contest them.
Postretirement and Pension Benefit Costs at Navajo Generating Station
Peabody contends that the Navajo Generating Station participants are responsible under the coal supply agreements for postretirement benefit costs payable to the coal supplier’s employees. In 1996, SRP filed a lawsuit in Maricopa County Superior Court on behalf of the participants at Navajo Generating Station, including TEP, seeking declaratory judgment that the participants are not responsible for these costs. The Navajo participants and Peabody have agreed to stay the discovery process in this litigation to allow the parties additional time to negotiate a potential settlement. We expect resolution of this matter in 2007. To the extent that amounts become estimable and payment probable, TEP will record a liability for additional postretirement benefit costs for the Navajo Generating Station.
Environmental Reclamation at Remote Generating Stations
TEP currently pays on-going reclamation costs related to the coal mines which supply the remote generating stations, and it is probable that TEP will have to pay a portion of final reclamation costs upon mine closure. When a reasonable estimate of final reclamation costs is available, the liability will be recognized as a cost of coal over the remaining term of the corresponding coal supply agreement. TEP estimates its undiscounted final reclamation liability to be $41 million, and the present value of TEP’s liability for final reclamation approximates $11 million at the expiration dates of the coal supply agreements. TEP recorded reclamation costs of $1 million in 2006 and 2005 and $0.5 million in 2004 in Fuel Expense.
Amounts recorded for final reclamation are subject to various assumptions and determinations, such as estimating the costs of reclamation, estimating when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount 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 post-term reclamation. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year since recognition occurs over the remaining lives of its coal supply agreements.
TEP Wholesale Accounts Receivable and Allowances
TEP’s Accounts Receivable from Electric Wholesale Sales, includes $16 million of receivables at December 31, 2006 and December 31, 2005 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000. TEP’s Allowance for Doubtful Accounts on the balance sheet includes $13 million at December 31, 2006 and December 31, 2005 related to these sales. There are several outstanding legal issues, complaints and lawsuits concerning the California energy crisis related to the FERC, wholesale power suppliers, Southern California Edison Company, Pacific Gas and Electric Company, the
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CPX and the CISO. We cannot predict the outcome of these issues or lawsuits. We believe, however, that TEP is adequately reserved for its transactions with the CPX and the CISO.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. The most significant of these guarantees are:
·
UES’ guarantee of $160 million of aggregate principal amount of senior unsecured notes issued by UNS Gas and UNS Electric to purchase the Citizens Arizona gas and electric utility assets,
·
UES’ guarantee of a $40 million unsecured revolving credit agreement for UNS Gas and UNS Electric,
·
UniSource Energy’s guarantee of approximately $5 million in natural gas transportation and supply payments in addition to building and equipment lease payments for UNS Gas and UNS Electric.
To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in our consolidated balance sheets.
In addition, we have indemnified the purchasers of interests in certain investments from additional taxes due for years before the sale of such investments. The terms of the indemnifications do not include a limit on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations. We have not made any payments under the terms of these indemnifications to date.
We believe that the likelihood UniSource Energy or UES would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.
NOTE 7. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Utility Plant in Service by company and major class at December 31:
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Intangible Plant primarily represents computer software costs. TEP’s unamortized computer software costs were $32 million as of December 31, 2006 and $18 million as of December 31, 2005. UNS Gas’ unamortized computer software costs were $1 million as of December 31, 2006 and $1 million as of December 31, 2005. UNS Electric’s unamortized computer software costs were $1 million as of December 31, 2006 and $2 million as of December 31, 2005.
All TEP Utility Plant under Capital Leases is used in TEP’s generation operations.
The following table reconciles the gross investment in utility plant to net investment in utility plant, segregated between regulated and non-regulated utility plant.
*The ACC does not set rates on TEP’s generation operations on a cost-of-service basis, and; therefore, these operations are not accounted for under the provisions of FAS 71. Rates for the remaining utility operations appearing in this table are set by the ACC on a cost-of-service basis, and are accounted for under the provisions
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of FAS 71. The category T&D includes all transmission and distribution Plant in Service. The category Gen includes the generation assets.
The depreciable lives currently used by TEP are as follows:
During the second quarter 2005, the results of a study requested by the participants in the San Juan Generating Station (San Juan) indicated San Juan’s economic useful life had changed from previous estimates. As a result of the study and other analysis performed, TEP lengthened the estimated useful life of San Juan from 40 to 60 years beginning April 1, 2005. This change in the estimated useful life reduces annual depreciation expense by $6 million.
See TEP Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 8.
The depreciable lives currently used by UES are as follows:
JOINTLY-OWNED FACILITIES
At December 31, 2006, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:
*Included in Utility Plant shown above.
TEP has financed or provided funds for the above facilities and TEP’s share of their operating expenses is reflected in the income statements. See Note 6 for commitments related to TEP’s jointly-owned facilities.
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NOTE 8. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
Long-term debt matures more than one year from the date of the financial statements. We summarize UniSource Energy and TEP’s long-term debt in the statements of capitalization.
UNISOURCE ENERGY DEBT
Convertible Senior Notes
In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due 2035. The Convertible Senior Notes are unsecured and are not guaranteed by TEP or any other UniSource Energy subsidiary. Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.
Beginning on March 5, 2010, UniSource Energy will have the option to redeem the Convertible Senior Notes, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued interest. Holders of the Convertible Senior Notes may require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain change of control transactions occur, or if our common stock is no longer listed on a national securities exchange. The repurchase price will be 100% of the principal amount of the Convertible Senior Notes plus accrued interest.
Certain of the Convertible Senior Notes features are considered to be embedded derivatives. Based on accounting requirements, we concluded that the embedded derivatives either do not have any value or they are not required to be separated from the debt and accounted for separately.
In March 2005, UniSource Energy used $106 million of the net proceeds from this offering to repay the $95 million promissory note to TEP plus accrued interest of $11 million. TEP used these funds, along with borrowings under its revolving credit facility to repurchase and redeem $225 million of industrial development bonds (IDBs). See TEP Debt - Unsecured IDBs, below.
Intercompany Notes Payable
In 1998, TEP and UniSource Energy exchanged all the outstanding common stock of TEP on a share-for-share basis for the Common Stock of UniSource Energy in a transaction which resulted in UniSource Energy becoming a holding company with TEP as its subsidiary. Following the share exchange, TEP transferred the stock of Millennium to UniSource Energy for a $95 million promissory note due in 2008. On March 1, 2005, UniSource Energy used $106 million of the $146 million of net proceeds from the convertible debt offering, as discussed above, to repay the $95 million promissory note to TEP plus accrued interest of $11 million. Approximately $25 million of this note represented a gain to TEP. TEP did not record this gain in income. Instead, this gain was reflected as an increase in TEP’s common stock equity when UniSource Energy repaid the note.
TEP DEBT
Mortgage IDBs
In March 2005, TEP redeemed, at par, all of the remaining $52 million of its Mortgage IDBs.
Unsecured IDBs
In May 2005, TEP purchased $221 million of fixed rate Unsecured IDBs at a price of $101.50 per $100 principal amount and redeemed, at par, the remaining $4 million of bonds outstanding under those series. In connection with the repurchase, TEP recognized a loss of approximately $3 million related to previously deferred debt costs. TEP does not plan to cancel the IDBs that it repurchased, but is holding the bonds as treasury bonds. This means the bonds remain outstanding under their indentures but are not reflected as debt on the balance sheet. TEP may choose to cancel or resell these treasury bonds to third parties in the future.
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Mortgage Indentures
In June 2005, TEP terminated its 1941 Mortgage Indenture. TEP’s remaining mortgage is its 1992 Mortgage Indenture.
TEP's indenture 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 or 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 $1 billion at December 31, 2006.
TEP CAPITAL LEASE OBLIGATIONS
The terms of TEP’s capital leases are as follows:
·
The Sundt Lease has an initial term to January 2011 and provides for renewal periods of two or more years through 2020.
·
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.
·
The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030.
·
The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for one renewal period of six years, then additional renewal periods of five or more years through 2035.
TEP has agreed with the owners of Springerville Units 3 and 4 that, upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP is obligated to acquire the facilities at fixed prices of $120 million in 2015, $38 million in 2017, and $68 million in 2021. Upon such acquisitions by TEP, each of the owners of Unit 3 and Unit 4 have the obligation to purchase from TEP a 17% and 14% interest, respectively, in such facilities. On or before the Sundt and Springerville Unit 1 Lease expiration dates, TEP will determine if it will purchase the assets at the fair market value or renegotiate the lease terms.
In January 2007, TEP made the following scheduled lease payments: Sundt Lease $11 million; Springerville Common Facilities Leases $2 million; Springerville Unit 1 Leases $70 million; and Springerville Coal Handling Facilities Leases $4 million.
Investments in Springerville Lease Debt and Equity
In June 2006, TEP purchased a 14% undivided equity ownership interest in the Springerville Unit 1 Lease and now is the owner participant under the leveraged lease arrangements relating to such undivided interest. As a result, TEP amended the Springerville Unit 1 Lease related to the 14% interest to reduce rental (lease) payments to equal the scheduled principal and interest payments for debt issued in respect of such interest. TEP recorded a $19 million reduction to the capital lease obligation and capital lease asset.
TEP held an investment in Springerville Unit 1 lease debt totaling $82 million at December 31, 2006 and $91 million at December 31, 2005. TEP also held an investment in Springerville Coal Handling Facilities lease debt totaling $52 million at December 31, 2006 and $65 million at December 31, 2005.
Springerville Common Lease Debt Refinancing
In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station. TEP refinanced the lease debt totaling $68 million in June 2006, and the leases were amended to remove the requirement that the notes be periodically refinanced to avoid the occurrence of a special event of loss. The lease debt now matures when the leases expire. Interest is payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. The refinancing had no impact on the Springerville Common Facilities capital lease obligation or asset.
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A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the underlying floating rate lease debt. In June 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest portion of rent at a rate of 7.27% on $37 million of the lease debt. The interest rate swap has been recorded by TEP as a cash flow hedge for financial reporting purposes. See Note 5.
UNS GAS AND UNS ELECTRIC LONG-TERM DEBT
Senior Unsecured Notes
In 2003, UNS Gas and UNS Electric issued a total of $160 million of senior unsecured notes in a private placement. UNS Gas issued $50 million of 6.23% notes due August 11, 2011 and $50 million of 6.23% notes due August 11, 2015. UNS Electric issued $60 million of 7.61% notes due August 11, 2008. All three series of notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity U.S. Treasury security yield plus 50 basis points. UES guarantees the notes. UNS Gas and UNS Electric incurred a total of $2 million in debt costs related to the issuance of the notes. We deferred these costs and are amortizing them over the life of the notes.
The note purchase agreements for both UNS Gas and UNS Electric contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, additional indebtedness, dividend restrictions, and minimum net worth requirements.
As of December 31, 2006, UNS Gas and UNS Electric complied with the terms of the note purchase agreements.
MATURITIES AND SINKING FUND REQUIREMENTS
Long-term debt, including sinking funds, term loan payments, revolving credit facilities, and capital lease obligations mature on the following dates:
TEP’s Variable Rate IDBs are backed by letters of credit (LOC) issued pursuant to TEP’s Credit Agreement which expires in August 2011. Although the Variable Rate IDBs mature between 2018 and 2022, the above table reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.
Effective with commercial operation of Springerville Unit 3 on September 1, 2006, Tri-State is reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% of the Springerville Common Lease payments and 17% of the Springerville Coal Handling Facilities Lease payments. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement.
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UNISOURCE ENERGY CREDIT AGREEMENT
In August 2006, UniSource Energy amended its existing credit agreement (UniSource Credit Agreement). As amended, the UniSource Credit Agreement includes a $30 million term loan facility and a $70 million revolving credit facility. The UniSource Credit Agreement expires on August 11, 2011.
The UniSource Credit Agreement requires quarterly principal payments of $1.5 million on the outstanding term loan with the balance due at maturity. At December 31, 2006, there was $27 million outstanding under the term loan facility and $20 million outstanding under the revolving credit facility at a weighted average interest rate of 6.67%. In January 2007, UniSource Energy repaid the $20 million outstanding under its revolving credit facility.
We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.
The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, sales of assets, and certain investments and acquisitions. We must also meet: (1) a minimum cash flow to interest coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis. We may pay dividends if, after giving effect to the dividend payment, we have more than $15 million of unrestricted cash and unused revolving credit. As of December 31, 2006, we were in compliance with the terms of the UniSource Credit Agreement.
TEP CREDIT AGREEMENT
In August 2006, TEP amended its credit agreement (TEP Credit Agreement). The amendment reduced the interest rate and fees payable on TEP’s borrowings and letters of credit, increased the amount of its revolving credit facility from $60 million to $150 million, and extended the maturity to August 2011. In addition to the revolving credit facility, the TEP Credit Agreement includes a $341 million LOC facility which supports the $329 million of tax-exempt Variable Rate IDBs. The TEP Credit Agreement is secured by 1992 Mortgage Bonds. The ACC approved the increase in the amount and term of the revolving credit facility in December 2006.
Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. Letter of credit fees are 0.55% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.55% per annum. TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.55% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.
The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leasebacks agreements. The TEP Credit Agreement also requires TEP to meet a minimum cash coverage ratio and a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UniSource Energy. As of December 31, 2006, TEP was in compliance with the terms of the TEP Credit Agreement.
As of December 31, 2006, TEP had $30 million outstanding under its Revolving Credit Facility included in Current Liabilities in the UniSource Energy and TEP Consolidated Balance Sheets.
UNS GAS/UNS ELECTRIC REVOLVER
In August 2006, UNS Gas and UNS Electric amended their unsecured revolving credit agreement (the UNS Gas/UNS Electric Revolver). The amendment reduced the interest rate payable on borrowings and, upon ACC approval, will increase the amount of the revolving credit facility to $60 million from $40 million, and extend the maturity from April 2008 to August 2011. Either UNS Gas or UNS Electric may borrow up to a maximum of $30 million, but the combined amount borrowed cannot exceed $40 million. Upon ACC approval of the increase in the revolving credit facility, either borrower may borrow up to a maximum of $45 million, so long as the combined amount borrowed does not exceed $60 million. This matter is pending before the ACC.
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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. UES guarantees the obligations of both UNS Gas and UNS Electric.
UNS Gas and UNS Electric each have the option of paying interest at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.
The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, mergers and sales of assets. The UNS Gas/UNS Electric Revolver also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower. As of December 31, 2006, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.
As of December 31, 2006, UNS Gas had no borrowings outstanding and UNS Electric had $19 million of borrowings outstanding under the UNS Gas/UNS Electric Revolver included in Long-Term Debt in the UniSource Energy Consolidated Balance Sheets.
NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values and fair values of our financial instruments are as follows:
See Note 8 for a description of TEP’s investment in Springerville Lease Debt and Equity. TEP intends to hold the $133 million investment in Springerville Lease Debt Securities to maturity (Springerville Coal Handling Facilities lease debt totaling $52 million matures through July 1, 2011, and Springerville Unit lease debt totaling $82 million matures through January 1, 2013). This investment is stated at amortized cost, which means the purchase cost has been adjusted for the amortization of the premium and discount to maturity.
·
TEP considers the purchase price of the Springerville Lease Equity to be a reasonable estimate of its fair value.
·
UniSource Energy and TEP used quoted market prices to determine the fair value of the UNS Convertible Senior Notes and TEP’s tax-exempt fixed rate obligations (Unsecured IDBs).
·
TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value.
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We determined the fair value of our remaining financial instruments (TEP Springerville Lease Debt Securities, TEP Collateral Trust Bonds, and UNS Gas and UNS Electric Senior Unsecured Notes) by calculating the present value of the cash flows using a discount rate consistent with market yields generally available as of December 31, 2006 and December 31, 2005 for bonds with similar characteristics with respect to credit rating and time-to-maturity. The use of different market assumptions and/or estimation methodologies may yield different estimated fair value amounts.
The carrying amounts of our current assets and liabilities approximate fair value.
NOTE 10. STOCKHOLDERS’ EQUITY
DIVIDEND LIMITATIONS
UniSource Energy
In February 2007, UniSource Energy declared a first quarter dividend to shareholders of $0.225 per share of UniSource Energy Common Stock. The dividend, totaling approximately $8 million, will be paid on March 14, 2007 to common shareholders of record as of February 20, 2007. In 2006, UniSource Energy paid quarterly dividends to the shareholders of $0.21 per share, for a total of $0.84 per share, or $29 million for the year. In 2005, UniSource Energy paid quarterly dividends to the shareholders of $0.19 per share, for a total of $0.76 per share, or $26 million, for the year. During 2004, UniSource Energy paid quarterly dividends to the shareholders of $0.16 per share, for a total of $0.64 per share, or $22 million, for the year.
Our 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. As of December 31, 2006, we complied with the terms of all such debt covenant requirements.
TEP
TEP paid dividends of $62 million in 2006, $46 million in 2005, and $32 million in 2004. UniSource Energy is the holder of TEP’s common stock. TEP met the requirements discussed below before paying these dividends.
As a result of the capital contribution, the intercompany note repayment, and the bond purchases and redemptions, TEP’s ratio of equity to total capitalization (excluding capital leases) reached 40%. As of December 31, 2006 and December 31, 2005, TEP met this ACC requirement that allowed TEP to dividend up to 100% of its current year Net Income to UniSource Energy.
In May 2005, UniSource Energy contributed $110 million of capital to TEP.
Bank Credit Agreement
TEP’s new Credit Agreement as of August 2006 allows TEP to pay dividends as long as TEP complies with the agreement and certain financial covenants.
Federal Power Act
This Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP’s 2006, 2005 and 2004 dividends were paid from current year earnings.
UNS Gas and UNS Electric
Restrictions placed on UNS Gas and UNS Electric limit UES’ ability to pay dividends. The 2003 UES Settlement Agreement allows UNS Gas and UNS Electric to pay dividends greater than 75% of its earnings to UniSource Energy when the ratio of common equity to total capitalization reaches 40%. As of December 31, 2006 and December 31, 2005, both UNS Gas and UNS Electric met this ratio requirement. Additionally, the terms of the senior unsecured note agreements entered into by both UNS Gas and UNS Electric contain dividend restrictions. See Note 8. UES did not pay any dividends to UniSource Energy in 2006 or 2005.
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UniSource Energy made the following capital contributions to UNS Gas and UNS Electric:
Millennium and UED
Neither Millennium nor UED paid dividends to UniSource Energy in 2006, 2005 or 2004. Millennium and UED have no dividend restrictions. In February 2007, Millennium paid a $5 million dividend to UniSource Energy.
UNISOURCE ENERGY SHAREHOLDER RIGHTS PLAN
In March 1999, UniSource Energy adopted a Shareholder Rights Plan. As of April 1, 1999, each Common Stock shareholder receives one Right for each share held. Each Right initially allows shareholders to purchase UniSource Energy’s Series X Preferred Stock at a specified purchase price. However, the Rights are exercisable only if a person or group (the “acquirer”) acquires or commences a tender offer to acquire 15% or more of UniSource Energy Common Stock. Each Right would entitle the holder (except the acquirer) to purchase a number of shares of UniSource Energy Common or Preferred Stock (or, in the case of a merger of UniSource Energy into another person or group, common stock of the acquiring person) having a fair market value equal to twice the specified purchase price. At any time until any person or group has acquired 15% or more of the Common Stock, UniSource Energy may redeem the Rights at a redemption price of $0.001 per Right. The Rights trade automatically with the Common Stock when it is bought and sold. The Rights expire on March 31, 2009.
NOTE 11. INCOME AND OTHER TAXES
INCOME TAXES
We record deferred income tax liabilities for amounts that will increase income taxes on future tax returns. We record deferred income tax assets for amounts that could be used to reduce income taxes on future tax returns. We record a deferred tax assets valuation allowance for the amount of deferred income tax assets that we may not be able to use on future tax returns. We estimate the valuation allowance based on our interpretation of the tax rules, prior tax audits, tax planning strategies, scheduled reversal of deferred income tax liabilities, and projected future taxable income.
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Deferred tax assets (liabilities) consist of the following:
The balance sheets display the net deferred income tax liability as follows:
There is no valuation allowance at December 31, 2006. The valuation allowance of $7 million at December 31, 2005, which reduces the Deferred Tax Asset balance, relates to Global Solar’s Net Operating Loss (NOL). Global Solar was sold at a capital loss in March 2006 and is no longer included in the consolidated income tax return.
As of December 31, 2006, UniSource Energy’s deferred income tax assets include $15 million related to capital loss carryforwards. UniSource Energy expects to fully utilize the capital loss carryforwards prior to the expiration dates of the carryforwards; therefore no valuation allowance is required.
As of December 31, 2006, UniSource Energy’s deferred income tax assets include $7 million related to unregulated investment losses of Millennium. These losses have not been reflected on our consolidated income tax returns. If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the foreseeable future, it would have to write-off these deferred tax assets. Millennium restructured its
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ownership in one of these investments in 2005. As a result of this restructuring, Millennium liquidated this investment for tax purposes resulting in a taxable loss that was reflected on our consolidated income tax return for 2005. Millennium is in the process of restructuring its ownership in its remaining investments and expects to dispose of its interests in the foreseeable future.
TEP’s net intercompany tax receivable from affiliates equaled $10 million at December 31, 2006 and its net intercompany tax payable to affiliates equaled $4 million at December 31, 2005. TEP includes these amounts under intercompany accounts on its balance sheet.
The tax effect of the exercise of certain employee stock options that are recognized differently for financial reporting and tax purposes was not recorded as a timing difference, but rather was credited to shareholder’s equity. This resulted in a $2 million increase for 2006 and an $2 million increase for 2005 to the capital of UniSource Energy.
Income tax expense (benefit) included in the income statements consists of the following:
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The differences between the income tax expense and the amount obtained by multiplying pre-tax income by the U.S. statutory federal income tax rate of 35% are as follows:
The Total Federal and State Income Tax Expense in the tables above is included on UniSource Energy and TEP’s income statements.
At December 31, 2006, UniSource Energy and TEP had, for federal and state income tax filing purposes, the following carryforward amounts:
OTHER TAX MATTERS
Income Tax Assessments
On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets. We also used the new accounting method on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.
In 2005, the Internal Revenue Service issued a ruling which draws into question the ability of electric and gas utilities to use the new accounting method. As a result, TEP, UNS Gas and UNS Electric amended their 2002, 2003 and 2004 tax returns to remove the benefit previously claimed using the accounting method. In September 2006, TEP and UNS Electric remitted tax and interest of $23 million and $1 million, respectively to the IRS. In October 2006, TEP, UNS Gas and UNS Electric remitted $8 million, $0.1 million and $0.3 million, respectively to state tax authorities. Payment of interest that had previously not been accrued resulted in $3 million of expense. In December 2006, the IRS issued final notice disallowing the use of the accounting method. We are filing a protest and will proceed to appeals.
In 2004, the Company settled the audit of state income tax returns for the period 1990 - 2000 with the Arizona Department of Revenue. As a result, UniSource Energy and TEP recorded $1 million of income in 2004.
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Sales Tax Assessments
In 2004, the City of Tucson issued its assessment for the 1998 - 2001 sales tax audit. After reviewing the audit findings, as well as assessing their impact on years following the audit period, TEP recorded a combined $1 million of sales tax and interest expense in 2005. The audit was settled during the first quarter of 2005.
OTHER TAXES
TEP and UES act as conduits or collection agents for excise tax (sales tax) as well as franchise fees and regulatory assessments. They record liabilities payable to governmental agencies when they bill their customers for these amounts. Neither the amounts billed nor payable are reflected in the income statement.
NOTE 12. EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees. Employees receive benefits based on their years of service and average compensation. TEP, UNS Gas and UNS Electric fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by IRS benefit or compensation limitations.
In 2007, TEP expects to contribute $10 million and UNS Gas and UNS Electric expect to contribute $1 million to the pension plans.
OTHER POSTRETIREMENT BENEFIT PLANS
TEP provides limited health care and life insurance benefits for retirees. All regular 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 postretirement medical benefits for current retirees and a small group of active employees.
INCREMENTAL EFFECT OF APPLYING FAS 158
As a result of adopting FAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, in December 2006, we recognized the underfunded status of our defined benefit pension and other postretirement plans as a liability. The underfunded status was measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated postretirement benefit obligation for other postretirement benefit plans. The adjustment required to recognize the pension liability on adoption of this statement resulted in recognition of a regulatory asset for our regulated operations and an adjustment to Accumulated Other Comprehensive Loss for our unregulated operations. We recorded the underfunded status of our other postretirement benefit plans as an adjustment to Accumulated Other Comprehensive Loss as the ACC allows TEP, UNS Gas and UNS Electric to recover other postretirement costs through rates only as benefit payments are made.
The following table presents the incremental effect of applying FAS 158, in combination with FAS 71, as well as the change to the additional minimum pension liability, on individual line items in TEP’s balance sheet at December 31, 2006:
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Prior to the application of FAS 158, the accounting guidance (Pre-FAS 158) required TEP to adjust its minimum pension liability in Accumulated Other Comprehensive Loss to reflect the underfunded status of its plans based on the accumulated benefit obligation. After the adoption of FAS 158 and before applying the provisions of FAS 71, TEP had an accumulated comprehensive loss balance (net of tax) of $35 million attributable to its pension and other postretirement benefit obligations. TEP subsequently recorded a regulatory asset of $32 million and an offsetting reduction on an after-tax basis of accumulated other comprehensive loss of $19 million, representing a reasonable approximation of the actuarial losses and prior service costs of TEP’s pension plans that are probable of recovery in rates by its regulated operations in future periods.
UNS Gas and UNS Electric were not required to record a minimum pension liability under pre-FAS 158 accounting guidance. Following the adoption of FAS 158, UNS Gas and UNS Electric recorded a combined regulatory pension asset and increase in pension liability of $3 million. The impact of FAS 158 on the postretirement plans of UNS Gas and UNS Electric was less than $1 million.
The pension and other postretirement benefit related amounts (excluding tax balances) included in the UniSource Energy balance sheet are:
The table above includes a combined accrued pension benefit liability of less than $4 million and a postretirement benefit liability of less than $2 million for UNS Gas and UNS Electric, for each period presented, in addition to the minimal FAS impact previously noted.
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OBLIGATIONS AND FUNDED STATUS
We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 1. FAS 158 requires the measurement date to be changed to the end of the year effective December 31, 2008. The tables below include TEP, UNS Gas and UNS Electric plans. The change in projected benefit obligation and plan assets and reconciliation of the funded status are as follows:
The tables above include a combined pension benefit obligation of less than $8 million and plan assets of less than $4 million for UNS Gas and UNS Electric for all periods presented.
The following table provides the components of UniSource Energy’s accumulated other comprehensive loss and regulatory assets that have not been recognized as components of periodic benefit cost as of December 31, 2006:
The accumulated benefit obligation for all defined benefit pension plans was $184 million at December 31, 2006 and $173 million at December 31, 2005. Changes in actuarial assumptions including an increase in the discount rate impacted the accumulated benefit obligation.
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The components of net periodic benefit costs and other amounts recognized in other comprehensive income 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 $2 million estimated net loss and $2 million prior service cost from accumulated other comprehensive income and other regulatory assets into net periodic benefit cost in 2007. The estimated net loss and prior service benefit for the defined benefit postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 are $1 million and $2 million, respectively.
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 estimated the expected return on plan assets based on a review of the plans’ asset allocations. We also consulted with a third-party investment consultant and the plans’ actuary who consider factors such as:
·
market and economic indicators
·
historical market returns
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·
correlations and volatility
·
central banks’ and government treasury departments’ forecasts and objectives, and
·
recent professional or academic research.
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.
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, 2006 amounts:
PENSION PLAN ASSETS
TEP, UNS Gas and UNS Electric calculate the fair value of plan assets on December 1, the measurement date. TEP’s pension plan asset allocations at December 31, 2006 and 2005 by asset category follow:
TEP’s investment policy for the pension plans targets exposure to the various asset classes in the following allocations: equity securities 65%, debt securities 23% and real estate 12%. TEP rebalances the portfolio when the portfolio allocation is not within the desired range of exposure. The plan seeks to provide returns in excess of a portfolio benchmark. A third party investment consultant tracks the plan’s portfolio relative to the benchmark and provides quarterly investment reviews which consist of a performance and risk assessment on all investment managers and on the portfolio.
Investment managers for the plan may use derivative financial instruments for risk management purposes or as a part of their investment strategy. Currency hedges have also been used for defensive purposes. Real estate managers use leverage but it is limited by investment policy.
The UNS Gas and UNS Electric pension plan provides exposure to equity and debt securities by investing in a balanced fund. At December 31, 2006, the fund held 64% equity securities, 31% fixed income securities, and 5% cash. The fund will hold no more than 75% of its total assets in equity securities.
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ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects to pay the following benefit payments, which reflect future service, as appropriate.
UNS Gas and UNS Electric expect to pay pension and postretirement benefits of approximately $1 million in 2007 through 2011 and $3 million in 2012 through 2016.
DEFINED CONTRIBUTION PLANS
TEP, UNS Gas and UNS Electric offer defined contribution savings plans to all eligible employees and certain affiliate employees. The Internal Revenue Code identifies the plans as qualified 401(k) plans. Participants direct the investment of contributions to certain funds in their account. TEP, UNS Gas, and UNS Electric match part of a participant’s contributions to the plans. TEP made matching contributions to these plans of approximately $4 million in 2006 and $3 million in 2005 and 2004. UNS Gas and UNS Electric made matching contributions of less than $0.5 million in each of 2006, 2005, and 2004.
NOTE 13. SHARE-BASED COMPENSATION PLANS
On May 5, 2006, UniSource Energy shareholders approved the 2006 Omnibus Stock and Incentive Plan (Plan), a new share-based compensation plan. This Plan supersedes and replaces prior equity compensation plans or programs maintained by UniSource Energy. The total number of shares which may be awarded under the Plan cannot exceed 2.25 million shares. Any prior stock option plans of UniSource Energy remain nominally in effect until all stock options granted under such prior plans have been exercised, forfeited, canceled, expired or otherwise terminated in accordance with the terms of such grants.
Awards granted under these compensation plans and the compensation expense recognized are described below.
STOCK OPTIONS
Stock options are granted on a scheduled basis 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 equal to the fair value of the option at the grant date is recorded on a straight-line basis over the vesting period. For awards granted to retirement eligible officers, compensation expense is recorded immediately. We discuss the compensation expense recorded for each share-based award below.
The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table. The expected term of options granted is derived using the “simplified” method in accordance with Staff Accounting Bulletin 107, Topic 14: Share-Based Payment where the expected term equals the time from grant to reaching the midpoint between vesting and the contractual term considering the vesting tranches. The risk-free rate is based on the rate available on a U.S. Treasury Strip with a maturity equal to the expected term of the option at the time of the grant. Expected volatility is based on historical volatility for UniSource Energy’s stock. The expected dividend yield on a share of stock is calculated
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using the historical dividend yield with the implicit assumption that current dividend yields will continue in the future.
A summary of the stock option activity follows:
Exercise prices for stock options outstanding and exercisable as of December 31, 2006 ranged from $11.00 to $33.55, summarized as follows:
We recognized compensation expense of $1 million in 2006 and less than $0.1 million for the options issued in 2005. As discussed in Note 1, before January 1, 2005, we applied APB 25 to account for our stock option plans. We did not recognize any compensation expense for these options because our stock options were granted with an exercise price equal to the market value of the stock at the grant date. We previously adopted the disclosure-only provisions of FAS 123. We present, in Note 1, the effect on net income and earnings per share as if the company had applied the fair value recognition provisions of FAS 123.
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Stock options awarded on January 1, 2002 accrue dividend equivalents that we pay in cash on the earlier of the date of exercise of the underlying option or the date the option expires. We recognize compensation expense as dividends are declared. In 2006, 2005 and 2004, we recognized compensation expense of less than $1 million for dividend equivalents on stock option grants. We did not capitalize any compensation costs associated with these awards during the years ended December 31, 2006, 2005, and 2004.
We summarize the status of nonvested stock options as of December 31, 2006, and changes during 2006 below:
As of December 31, 2006, total unrecognized compensation cost related to nonvested stock options granted under the Plan was $1 million. We expect that cost to be recognized over the remaining vesting period that is through April 2009. The total fair value of shares vested was $0.1 million during the year ended December 31, 2006, less than $0.1 million during the year ended December 31, 2005 and approximately $2 million during the year ended December 31, 2004.
The actual tax benefit realized from the exercise of share-based payment arrangements totaled $2 million in 2006, $3 million in 2005 and $1 million in 2004.
RESTRICTED STOCK AND STOCK UNITS
Restricted stock and stock units are generally granted under the Plan 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 are payable in Common Stock. Stock units vest either immediately or over periods ranging from one to three years. 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. Compensation expense is recognized when dividends are paid.
We did not grant any restricted stock awards to directors in 2006. In 2005, we granted 3,264 restricted stock awards to directors at a fair value of $24.51 per share on the grant date. In 2004, we granted 3,240 restricted stock awards to directors at a fair value of $24.68 per share on the grant date.
In 2006, we granted 17,151 stock unit awards to directors at a fair value of $30.76 per share on the grant date. In 2005, we granted 13,213 stock unit awards at a fair value of $29.72 per share on the grant date. In 2004, we granted 3,240 stock unit awards at a fair value of $24.68 per share on the grant date.
A summary of the status of nonvested restricted stock awards and stock unit awards as of December 31, 2006, and changes during 2006 is presented below:
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We recorded compensation expense for the awards described above of $1 million in 2006 and less than $1 million in 2005 and 2004. As of December 31, 2006, total unrecognized compensation cost related to nonvested restricted stock awards and stock unit awards granted was $1 million. We expect that cost to be recognized over the remaining vesting period that is through December 2007. The total fair value of restricted stock awards and stock unit awards vested during the year ended December 31, 2006 was $0.5 million and during the years ended December 31, 2005 and 2004 was approximately $0.1 million.
PERFORMANCE SHARES
On May 5, 2006, the Compensation Committee of the UniSource Energy Board of Directors granted 45,520 performance share awards (targeted shares) to Officers at a grant date fair value of $28.39 per share (market price of $30.55 less the present value of expected dividends of $2.16). The performance share awards are paid out in shares of UniSource Energy common stock based on UniSource Energy’s performance over the period of January 1, 2006 through December 31, 2008. The performance criteria specified in the awards is determined based on targeted UniSource Energy cumulative Earnings per Share and cumulative Cash Flow from Operations during the performance period. The performance shares vest ratably over the performance period and any unearned awards are forfeited.
Compensation expense equal to the fair market value on the grant date less the present value of expected dividends is recognized over the vesting period if it is probable that the performance criteria will be met. We recorded compensation expense of $0.3 million during 2006 for performance share awards. As of December 31, 2006, total unrecognized compensation cost related to nonvested performance share awards was $1 million. We expect that cost to be recognized over the remaining vesting period that is through December 2008.
NOTE 14. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)
We compute basic 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 notes. The numerator in calculating diluted earnings per share is Net Income adjusted for the interest on convertible notes (net of tax) that would not be paid if the notes were converted to common shares.
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The following table shows the effects of potential dilutive common stock on the weighted average number of shares:
Stock options to purchase an average of 67,000 shares of Common Stock were outstanding during the year ended December 31, 2006 but were not included in the computation of EPS because the stock option’s exercise price was greater than the average market price of the Common Stock. There were no outstanding options excluded from the computation of EPS during the years ended December 31, 2005 and 2004.
NOTE 15. RELATED PARTIES
UniSource Energy incurs corporate costs that are allocated to its subsidiaries, including TEP. Corporate costs are allocated based on a weighted-average residual allocation factor. Management believes this method of allocation is reasonable and approximates the cost that TEP and its other affiliates would have incurred as stand-alone entities. Charges allocated to TEP were $7 million in 2006, $5 million in 2005 and $12 million in 2004.
TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UniSource Energy, UNS Gas and UNS Electric as well as to UniSource Energy’s non-utility businesses. Costs are directly assigned to the benefiting entity where possible. Common costs are allocated on a cost-causative basis. Management believes this method of allocation is reasonable. The charges by TEP to the other companies were $9 million in 2006, $8 million in 2005 and $7 million in 2004.
Global Solar, previously Millennium’s largest subsidiary, develops and manufactures light weight thin-film photovoltaic cells and panels. Global Solar is reflected in these financial statements as a discontinued operation. See Note 16. Global Solar did not record any revenue from transactions with TEP in 2006. Global Solar recorded revenue from transactions with TEP of less than $1 million in 2005 and $4 million in 2004.
Southwest Energy Solutions, Inc. (SES), a subsidiary of Millennium, provides a supplemental workforce for TEP and UNS Electric. Types of services provided for TEP include dusk to dawn lighting, facilities maintenance, meter reading, transmission and distribution, and general supplemental support. SES bills TEP for these services. Management believes that the charges for services are reasonable and approximate the cost that TEP would have incurred if it performed these services directly. SES charged TEP $14 million in 2006, $12 million in 2005 and $13 million in 2004 for these services. SES provides meter reading services for UNS Electric. SES charged UNS Electric less than $1 million for these services in 2006, 2005 and 2004.
Haddington Energy Partners II, LP (Haddington) funds energy-related investments. A member of the UniSource Energy Board of Directors has an investment in Haddington and is a managing director of the general partner of the limited partnership.
Valley Ventures III, LP (Valley Ventures) is a venture capital fund that invests in information technology, microelectronics and biotechnology, primarily within the southwestern U.S. Another member of the UniSource Energy Board of Directors was a general partner of the company that manages the fund until January 1, 2006, at
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which time the Board member ended his role and interest as a general partner but maintained a non-voting financial interest in the company.
Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 megawatts (MW) of coal-fired generation in the Sabinas region of Coahuila, Mexico. Millennium owns 50% of Sabinas. Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates own the other 50%. UniSource Energy’s Chairman, President and Chief Executive Officer is on the board of directors of AHMSA. As of December 31, 2006, Millennium’s remaining investment in Sabinas is $14 million.
NOTE 16. DISCONTINUED OPERATION
In January 2006, UniSource Energy’s Board of Directors approved a plan to dispose of its investment in Global Solar to a third party. Global Solar appears in these financial statements as a discontinued operation.
On March 31, 2006, UniSource Energy sold all of the capital stock of Global Solar to a third party. UniSource Energy received $16 million in cash as part of the transaction; a portion of the proceeds was used to satisfy $10 million of secured promissory notes held by a UniSource Energy subsidiary. In addition to the cash purchase price, UniSource Energy received a ten-year option to purchase between 5 and 10 percent of the common stock of Global Solar. The option is only exercisable after the seventh anniversary of the closing or upon the occurrence of certain events including a sale of all or substantially all of the assets of Global Solar, a merger, a change of control transaction, an initial public offering of Global Solar common stock or the payment by Global Solar of dividends in excess of specified amounts. For accounting purposes, no value was assigned to this repurchase option.
Listed below are the major classes of assets and liabilities related to the sale of Global Solar as of December 31:
The following summarizes the amounts included in Discontinued Operation - Net of Tax for all periods presented:
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NOTE 17. SUPPLEMENTAL CASH FLOW INFORMATION
A reconciliation of net income to net cash flows from operating activities follows:
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Non-cash investing and financing activities of UniSource Energy and TEP that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments in 2006, 2005 and 2004.
The non-cash preliminary engineering fees represent costs incurred related to potential capital projects that are recorded in other assets and subsequently reclassified to construction work in progress upon affirmation the capital project will be undertaken.
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
NOTE 18. 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 months and peak sales periods for UNS Gas generally occur during the winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
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UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 principal unusual items for TEP and UniSource Energy include:
TEP and UniSource Energy
·
Third Quarter 2005: TEP recognized a $1 million income tax benefit due to anticipated use of previously reserved ITC carryforwards.
UniSource Energy
·
First Quarter 2006: On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar at a future date. The option is exercisable, upon the occurrence of certain events, beginning in April 2013 and expires in April 2016. In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar.
·
Fourth Quarter 2005: Millennium recognized a $4 million pre-tax gain from the sale of a Haddington investment and Millennium recognized a $2 million impairment loss upon sale of its MicroSat investment. UES collected $1 million of previously fully reserved accounts receivable related to amounts owed from Citizens in relation to the 2003 Citizens purchase. UES recognized a $1 million pre-tax gain in non-operating income for this collection.
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UniSource Energy
Schedule II - Valuation and Qualifying Accounts
(1) The deferred tax assets valuation allowance reduces the deferred tax asset balance. It relates to NOL and ITC carryforward amounts. The $7 million valuation allowance at December 31, 2005, relates to losses generated by Global Solar. Global Solar was sold in March 2006 and is no longer included in our consolidated tax returns. The decrease in 2005 of $1 million relates to TEP’s anticipated utilization of ITC carryforward. UniSource Energy and TEP charged $1 million to income in related to TEP’s ITC carryforwards that may expire before utilization.
(2) TEP, UNS Gas and UNS Electric record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Balances related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001. See Note 6 of Notes to Consolidated Financial Statements.
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TEP
Schedule II - Valuation and Qualifying Accounts
(1) The deferred tax assets valuation allowance reduces the deferred tax asset balance. It relates to NOL and ITC carryforward amounts. The 2005 reduction of $1 million related to TEP’s anticipated utilization of ITC carryforwards. TEP charged $1 million to income in 2004 related to ITC carryforwards that may expire before utilization.
(2) TEP records additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Balances related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001. See Note 11 of Notes to Consolidated Financial Statements.
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ITEM 9.
ITEM 9. - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. - CONTROLS AND PROCEDURES
UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a - 15(e) or Rule 15d - 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2006. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSource 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 UniSource 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, UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSource Energy and TEP’s disclosure controls and procedures are effective.
While UniSource 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 UniSource Energy or TEP’s internal control over financial reporting during the fourth quarter of 2006, that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal control over financial reporting.
UniSource Energy’s Management’s Report on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appears as the first report under Item 8 in UniSource Energy’s and TEP’s 2006 Annual Report on Form 10-K and the Report of Independent Registered Public Accounting Firm appears as the second report under Item 8.
ITEM 9B.
ITEM 9B. - OTHER INFORMATION
None.
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PART III
ITEM 10.
ITEM 10. - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Directors
Certain of the individuals serving as Directors of UniSource Energy also serve as the Directors of TEP. Information concerning Directors will be contained under Election of Directors in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, which information is incorporated herein by reference.
Executive Officers - UniSource Energy
Executive Officers of UniSource Energy, who are elected annually by UniSource Energy’s Board of Directors, are as follows:
James S. Pignatelli
Mr. Pignatelli joined TEP as Senior Vice President in August 1994 and was elected Senior Vice President and Chief Operating Officer in 1996. He was named Senior Vice President and Chief Operating Officer of UniSource Energy in January 1998, and Executive Vice President and Chief Operating Officer of TEP in March 1998. On June 23, 1998, Mr. Pignatelli was named Chairman, President and CEO of UniSource Energy and TEP. Prior to joining TEP, he was President and Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a subsidiary of SCE Corp.
Michael J. DeConcini
Mr. DeConcini joined TEP in 1988 and served in various positions in finance, strategic planning and wholesale marketing. He was Manager of TEP’s Wholesale Marketing Department in 1994, adding Product Development and Business Development in 1997. In November 1998, he was elected Vice President of MEH and elected Vice President, Strategic Planning of UniSource Energy in February 1999. He was named Senior Vice President, Investments and Planning of UniSource Energy in October 2000. Mr. DeConcini 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.
Raymond S. Heyman
Mr. Heyman was elected to the position of Senior Vice President and General Counsel of TEP and UniSource Energy in September 2005. Prior to joining TEP, Mr. Heyman was a member from 1995 - 2005 of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC, and has represented UniSource Energy, TEP and UES in proceedings before the Arizona Corporation Commission, as well as in other legal and regulatory matters.
Kevin P. Larson
Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. In January 1991, he was elected Assistant Treasurer of TEP and named Manager of Financial Programs. He was elected
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Treasurer of TEP in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer of both UniSource Energy and TEP and remains Treasurer of both organizations. He was named Senior Vice President in September 2005.
Dennis R. Nelson
Mr. Nelson joined TEP as a staff attorney in 1976. He was manager of the Legal Department from 1985 to 1990. He was elected Vice President, General Counsel and Corporate Secretary in January 1991. He was named Vice President, General Counsel and Corporate Secretary of UniSource Energy in January 1998. Mr. Nelson was named Senior Vice President and General Counsel of TEP in November 1998. In 1998, he was named Chief Operating Officer, Corporate Services of TEP. In 2000, he was named Senior Vice President, Governmental Affairs of UniSource Energy and Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP. Mr. Nelson was elected Senior Vice President of Utility Services in 2003 and named Senior Vice President and Chief Operating Officer of UES in August 2003.
Kentton C. Grant
Mr. Grant joined TEP in 1995 and was named Director of Capital Resources and Assistant Treasurer in 1997. He was promoted to Manager of Financial Planning in 1998 and General Manager of Financial Planning in 2003. In January 2007, Mr. Grant was elected Vice President of Finance and Rates at UniSource Energy and TEP. Prior to joining TEP, Mr. Grant worked as a staff member at the Public Utility Commission of Texas.
Arie Hoekstra
Mr. Hoekstra joined TEP in 1979 as a Maintenance Superintendent. He was promoted to Manager of Tucson Power Production in 1983 and Manager of Springerville Power Production in 1995. He was named General Manager of Energy Resources - Power Production in 2003. In January 2007, Mr. Hoekstra was elected Vice President of Generation at UniSource Energy and TEP. Prior to joining TEP, Mr. Hoekstra worked in various roles for Arizona Public Service Company and Westinghouse Electric Corporation.
David G. Hutchens
Mr. Hutchens joined TEP in 1995 and was named Supervisor of Wholesale Power Operations in 1999. He was promoted to Manager of Wholesale Marketing in 2001 and General Manager of Fuels and Wholesale Power in 2003. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Marketing at UniSource Energy and TEP, and Vice President of UNS Gas. Prior to joining TEP, Mr. Hutchens served in the United States Navy, achieving the rank of Lieutenant.
Karen G. Kissinger
Ms. Kissinger joined TEP as Vice President and Controller in January 1991. She was named Vice President, Controller and Principal Accounting Officer of UniSource Energy in January 1998. In November 1998, Ms. Kissinger was also named Chief Information Officer of TEP. She was named Chief Compliance Officer of UniSource Energy and TEP, effective January 1, 2003.
Steven W. Lynn
Mr. Lynn joined TEP in 2000 as Manager of Corporate Relations for UniSource Energy and was named Manager of Corporate Relations of both TEP and UniSource Energy during 2000. In January 2003, he was elected Vice President of Communications and Government Relations at UniSource Energy and TEP. Prior to joining TEP, Mr. Lynn was an owner-partner from 1984 - 2000 of Nordensson Lynn & Associates, Inc., a Tucson-based advertising, marketing and public relations firm.
Thomas A. McKenna
Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998, as Director of Project Development. In 2001, he was named Manager of Project Development for UniSource Energy. In January 2007, Mr. McKenna was elected Vice President of Engineering at UniSource Energy and TEP, and Vice President of UNS Electric. Prior to joining UniSource Energy, Mr. McKenna was a Vice President of Sargent & Lundy Engineers.
Herlinda H. Kennedy
Ms. Kennedy joined TEP as an administrative assistant in 1980. She was promoted to Assistant to the CEO in 1986. Ms. Kennedy was named assistant Corporate Secretary of TEP and UniSource Energy in 1999 and was elected Corporate Secretary of UniSource Energy and TEP in September 2006.
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Executive Officers - TEP
Executive Officers of TEP, who are elected annually by TEP’s Board of Directors, are:
James S. Pignatelli
See description shown under UniSource Energy Corporation above.
Michael J. DeConcini
See description shown under UniSource Energy Corporation above.
Raymond S. Heyman
See description shown under UniSource Energy Corporation above.
Kevin P. Larson
See description shown under UniSource Energy Corporation above.
Kentton C. Grant
See description shown under UniSource Energy Corporation above.
Thomas N. Hansen
Mr. Hansen joined TEP in December 1992 as Vice President, Power Production. Prior to joining TEP, Mr. Hansen was Century Power Corporation’s Vice President, Operations from 1989 and Plant Manager at Springerville from 1987 through 1988. In 1994, he was named Vice President / Technical Advisor. In 2007, he was named Vice President, Environmental Services, Conservation and Renewable Energy.
Arie Hoekstra
See description shown under UniSource Energy Corporation above.
David G. Hutchens
See description shown under UniSource Energy Corporation above.
Karen G. Kissinger
See description shown under UniSource Energy Corporation above.
Steven W. Lynn
See description shown under UniSource Energy Corporation above.
Thomas A. McKenna
See description shown under UniSource Energy Corporation above.
Herlinda H. Kennedy
See description shown under UniSource Energy Corporation above.
Information required by Items 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, which information is incorporated herein by reference.
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ITEM 11.
ITEM 11. - EXECUTIVE COMPENSATION
Information concerning Executive Compensation will be contained in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, 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 23, 2007, UniSource Energy had outstanding 35 million shares of Common Stock. As of February 23, 2007, the number of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to approximately 4% of the outstanding Common Stock.
At February 23, 2007, UniSource 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 UniSource Energy will be contained in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, which information is incorporated herein by reference.
Security Ownership of Management
Information concerning the security ownership of the Directors and Executive Officers of UniSource Energy and TEP will be contained in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, which information is incorporated herein by reference.
Securities Authorized for Issuance Under Equity Compensation Plans
Information concerning securities authorized for issuance under equity compensation plans will be contained in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, 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 UniSource Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks and Insider Participation in UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, 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 UniSource Energy’s Proxy Statement relating to the 2007 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2006, which information is incorporated herein by reference.
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PART IV
ITEM 15.
ITEM 15. - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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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.
UNISOURCE ENERGY CORPORATION
Date: March 28, 2007 By: /s/ Kevin P. Larson
Kevin P. Larson
Senior Vice President and Principal
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.
Date: March 28, /s/ James S. Pignatelli*
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
Date: March 28, /s/ Kevin P. Larson
Kevin P. Larson
Principal Financial Officer
Date: March 28, /s/ Karen G. Kissinger*
Karen G. Kissinger
Principal Accounting Officer
Date: March 28, /s/ Lawrence J. Aldrich*
Lawrence J. Aldrich
Director
Date: March 28, /s/ Barbara Baumann*
Barbara Baumann
Director
Date: March 28, /s/ Larry W. Bickle*
Larry W. Bickle
Director
Date: March 28, /s/ Elizabeth T. Bilby*
Elizabeth T. Bilby
Director
Date: March 28, /s/ Harold W. Burlingame*
Harold W. Burlingame
Director
Date: March 28, /s/ John L. Carter*
John L. Carter
Director
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Date: March 28, /s/ Robert A. Elliott*
Robert A. Elliott
Director
Date: March 28, /s/ Daniel W.L. Fessler*
Daniel W.L. Fessler
Date: March 28, /s/ Kenneth Handy*
Kenneth Handy
Director
Date: March 28, 2007 /s/ Warren Y. Jobe*
Warren Y. Jobe
Director
Date: March 28, /s/ Joaquin Ruiz*
Joaquin Ruiz
Director
Date: March 28, By: /s/ Kevin P. Larson
Kevin P. Larson
As attorney-in-fact for each
of the persons indicated
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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: March 28, By: /s/ Kevin P. Larson
Kevin P. Larson
Senior Vice President and Principal
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.
Date: March 28, /s/ James S. Pignatelli*
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
Date: March 28, /s/ Kevin P. Larson
Kevin P. Larson
Principal Financial Officer
Date: March 28, /s/ Karen G. Kissinger*
Karen G. Kissinger
Principal Accounting Officer
Date: March 28, /s/ Lawrence J. Aldrich*
Lawrence J. Aldrich
Director
Date: March 28, /s/ Barbara Baumann*
Barbara Baumann
Director
Date: March 28, /s/ Larry W. Bickle*
Larry W. Bickle
Director
Date: March 28, /s/ Elizabeth T. Bilby*
Elizabeth T. Bilby
Director
Date: March 28, /s/ Harold W. Burlingame*
Harold W. Burlingame
Director
Date: March 28, /s/ John L. Carter*
John L. Carter
Director
K-156
Date: March 28, /s/ Robert A. Elliott*
Robert A. Elliott
Director
Date: March 28, /s/ Daniel W.L. Fessler*
Daniel W.L. Fessler
Date: March 28, /s/ Kenneth Handy*
Kenneth Handy
Director
Date: March 28, /s/ Warren Y. Jobe*
Warren Y. Jobe
Director
Date: March 28, /s/ Joaquin Ruiz*
Joaquin Ruiz
Director
Date: March 28, By: /s/ Kevin P. Larson
Kevin P. Larson
As attorney-in-fact for each
of the persons indicated
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EXHIBIT INDEX
*2(a)
--
Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc.
*3(a)
--
Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for year ended December 31, 1996, File No. 1-5924 -- Exhibit 3(a).)
*3(b)
--
Bylaws of TEP, as amended May 20, 1994. (Form 10-Q for the quarter ended June 30, 1994, File No. 1-5924 -- Exhibit 3.)
*3(c)
--
Amended and Restated Articles of Incorporation of UniSource Energy. (Form 8-A/A, dated January 30, 1998, File No. 1-13739 -- Exhibit 2(a).)
*3(d)
--
Bylaws of UniSource Energy, as amended December 11, 1997. (Form 8-A, dated December 23, 1997, File No. 1-13739 -- Exhibit 2(b).)
*4(a)(1)
--
Installment Sale Agreement, dated as of December 1, 1973, among the City of Farmington, New Mexico, Public Service Company of New Mexico and TEP. (Form 8-K for the month of January 1974, file No. 0-269 -- Exhibit 3.)
*4(a)(2)
--
Ordinance No. 486, adopted December 17, 1973, of the City of Farmington, New Mexico. (Form 8-K for the month of January 1974, File No. 0-269 -- Exhibit 4.)
*4(a)(3)
--
Amended and Restated Installment Sale Agreement dated as of April 1, 1997, between the City of Farmington, New Mexico and TEP relating to Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31,1997, File No. 1-5924 -- Exhibit 4(a).)
*4(a)(4)
--
City of Farmington, New Mexico Ordinance No. 97-1055, adopted April 17, 1997, authorizing Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(b).)
*4(b)(1)
--
Loan Agreement, dated as of October 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(a).)
*4(b)(2)
--
Indenture of Trust, dated as of October 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(b).)
*4(b)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(3).)
*4(b)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(4).)
*4(c)(1)
--
Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(1).)
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*4(c)(2)
--
Indenture of Trust dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(2).)
*4(c)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(3).)
*4(c)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(4).)
*4(d)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(I)(1).)
*4(d)(2)
--
Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File no. 1-5924 -- Exhibit 4(I)(2).)
*4(d)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(3).)
*4(d)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(4).)
*4(d)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(5).)
*4(d)(6)
--
Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(6).)
*4(e)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(1).)
*4(e)(2)
--
Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds. 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(2).)
*4(e)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Developmental Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(3).)
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*4(e)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(4).)
*4(e)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(5).)
*4(e)(6)
--
Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(6).)
*4(f)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(1).)
*4(f)(2)
--
Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(2).)
*4(f)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(3).)
*4(f)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(4).)
*4(f)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(5).)
*4(f)(6)
-- Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(6).)
*4(g)
--
Reimbursement Agreement, dated as of September 15, 1981, as amended, between TEP and Manufacturers Hanover Trust Company. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 4(o)(4).)
*4(h)(1)
--
Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(1).)
*4(h)(2)
--
Indenture of Trust dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(2).)
K-160
*4(h)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(3).)
*4(h)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(4).)
*4(i)(1)
--
Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(1).)
*4(i)(2)
--
Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series A, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(2).)
*4(i)(3)
--
Supplemental Indenture No. 2 creating a series of bonds designated Second Mortgage Bonds, Collateral Series B, dated as of December 1, 1997. (Form 10-K for year ended December 31, 1997, File No. 1-5924 -- Exhibit 4(m)(3).)
*4(i)(4)
--
Supplemental Indenture No. 3 creating a series of bonds designated Second Mortgage Bonds, Collateral Series, dated as of August 1, 1998. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(c).)
*4(i)(5)
--
Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series C, dated as of November 1, 2002. (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 -- Exhibit 99.2.)
*4(i)(6)
--
Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series D, dated as of March 1, 2004. (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 -- Exhibit 10 (b).)
*4(i)(7)
--
Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series E, dated as of May 1, 2005. (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 - Exhibit 4(b).)
*4(i)(8)
--
Supplemental Indenture No. 7 creating a series of bonds designated First Mortgage Bonds, Collateral Series F, dated as of December 1, 2006. (Form 8-K dated December 22, 2006, File Nos. 1-5924 and 1-13739 - Exhibit 4.1.)
*4(j)(1)
--
Loan Agreement, dated as of April 1, 1997 between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(c).)
*4(j)(2)
--
Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(d).)
*4(k)(1)
--
Loan Agreement, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(e).)
*4(k)(2)
--
Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(f).)
K-161
*4(l)(1)
--
Loan Agreement, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(a).)
*4(l)(2)
--
Indenture of Trust, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(b).)
*4(m)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(a).)
*4(m)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(b).)
*4(n)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(c).)
*4(n)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(d).)
*4(o)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(e).)
*4(o)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(f).)
*4(p)(1)
--
Indenture of Trust, dated as of August 1, 1998, between TEP and the Bank of Montreal Trust Company. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(d).)
*4(q)(1)
--
Rights Agreement dated as of March 5, 1999, between UniSource Energy Corporation and The Bank of New York, as Rights Agent. (Form 8-K dated March 5, 1999, File No. 1-13739 -- Exhibit 4.)
*4(r)(1)
--
Amended and Restated TEP Credit Agreement dated as of August 11, 2006, among TEP, the Lenders Party Thereto, the Issuing Banks Party Thereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.3.)
*4(s)(1)
--
Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.2.)
K-162
*4(t)(1)
--
Note Purchase and Guaranty Agreement date August 11, 2003 among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.3.)
*4(u)(1)
--
Indenture dated as of March 1, 2005, to The Bank of New York, as Trustee. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1).
*4(v)(1)
--
Registration Rights Agreement dated as of March 1, 2005, between UniSource Energy Corporation and Credit Suisse First Boston LLC, as representative of the several initial purchasers. (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.2).
*4(w)(1)
--
Amended and Restated Credit Agreement dated as of August 11, 2006, among UniSource Energy, the Lenders Party Hereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1.)
*4(x)(1)
--
Amended and Restated Credit Agreement dated as of August 11, 2006, among UNS Electric and UNS Gas, UniSource Energy Services as Guarantor, and the Banks Named Herein and the Other Lenders from Time to Time party Hereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.4.)
*10(a)(1)
--
Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(1).)
*10(a)(2)
--
Guaranty and Agreements, dated as of December 1, 1984, between TEP and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(2).)
*10(a)(3)
--
General Indemnity Agreements, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(3).)
*10(a)(4)
--
Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and TEP, Indemnitors. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(4).)
*10(a)(5)
--
Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(5).)
*10(a)(6)
--
Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(6).)
*10(a)(7)
--
Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and
K-163
Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(7).)
*10(a)(8)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(8).)
*10(a)(9)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(9).)
*10(a)(10)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(10).)
*10(a)(11)
--
Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(11).)
*10(a)(12)
--
Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(12).)
*10(a)(13)
--
Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(13).)
*10(a)(14)
--
Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(14).)
*10(a)(15)
--
Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4 Registration No. 33-52860 -- Exhibit 10(f)(15).)
*10(a)(16)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(12).)
*10(a)(17)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(13).)
K-164
*10(a)(18)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(14).)
*10(a)(19)
--
Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(19).)
*10(a)(20)
--
Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 --Exhibit 10(f)(20).)
*10(a)(21)
--
Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(21).)
*10(a)(22)
--
Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(22).)
*10(a)(23)
--
Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(15).)
*10(a)(24)
--
Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(16).)
*10(a)(25)
--
Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(25).)
*10(a)(26)
--
Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(26).)
K-165
*10(a)(27)
--
Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(f)(27).)
*10(b)(1)
--
Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(1).)
*10(b)(2)
--
Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(2).)
*10(b)(3)
--
Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(3).)
*10(b)(4)
--
Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(4).)
*10(b)(5)
--
Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(5).)
*10(b)(6)
--
Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(6).)
*10(b)(7)
--
Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(7).)
*10(b)(8)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(8).)
*10(b)(9)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(9).)
K-166
*10(b)(10)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(10).)
*10(b)(11)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(11).)
*10(b)(12)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(12).)
*10(b)(13)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(13).)
*10(b)(14)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.
*10(b)(15)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant.
*10(b)(16)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant.
*10(b)(17)
--
Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.
*10(b)(18)
--
Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.
*10(b)(19)
--
Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.
K-167
*10(b)(20) --
Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.
*10(b)(21)
--
Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Selco Service Corporation as Owner Participant.
*10(b)(22)
--
Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Emerson Finance LLC as Owner Participant.
*10(b)(23)
--
Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor.
*10(b)(24)
--
Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Selco Service Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor.
*10(b)(25)
--
Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Emerson Finance LLC as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor.
*10(c)(1)
--
Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Financial Security Assurance Inc., as Surety, Wilmington Trust Company and William J. Wade in their respective individual capacities as provided therein, but otherwise solely as Owner Trustee and Co-Trustee under the Trust Agreement, and Morgan Guaranty, in its individual capacity as provided therein, but Secured Party. (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(1).)
*10(c)(2)
--
Lease Agreement, dated as of January 14, 1988, between Wilmington Trust Company and William J. Wade, as Owner Trust Agreement described therein, dated as of November 15, 1987,between such parties and Ford Motor Credit Company, as Lessor, and TEP, as Lessee. (Form 10-K for the year ended December 31, 1987, File No.1-5924 -- Exhibit 10(j)(2).)
*10(c)(3)
--
Tax Indemnity Agreement, dated as of January 14, 1988, between TEP, as Lessee, and Ford Motor Credit Company, as Owner Participant, beneficiary under a Trust Agreement, dated as of November 15, 1987, with Wilmington Trust Company and William J. Wade, Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(3).)
*10(c)(4)
--
Loan Agreement, dated as of January 14, 1988, between the Pima County Authority and Wilmington Trust Company and William J. Wade in their respective individual capacities as expressly stated, but otherwise solely as Owner Trustee and Co-Trustee, respectively, under and pursuant to a Trust Agreement, dated as of November 15, 1987, with Ford Motor Credit Company as Trustor and Debtor relating to Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (TEP’s Sundt Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(4).)
K-168
*10(c)(5)
--
Indenture of Trust, dated as of January 14, 1988, between the Pima County Authority and Morgan Guaranty authorizing Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (Tucson Electric Power Company Sundt Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(5).)
*10(c)(6)
--
Lease Amendment No. 1, dated as of May 1, 1989, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively under a Trust Agreement dated as of November 15, 1987 with Ford Motor Credit Company. (Form 10-K for the year ended December 31, 1990, File No. 1-5924 -- Exhibit 10(i)(6).)
*10(c)(7)
--
Lease Supplement, dated as of January 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(8).)
*10(c)(8)
--
Lease Supplement, dated as of March 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(9).)
*10(c)(9)
--
Lease Supplement No. 4, dated as of December 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(10).)
*10(c)(10)
--
Supplemental Indenture No. 1, dated as of December 1, 1991, between the Pima County Authority and Morgan Guaranty relating to Industrial Lease Development Obligation Revenue Project. (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(l)(11).)
*10(c)(11)
--
Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and Morgan Guaranty, as Indenture Trustee and Refunding Trustee, relating to the restructuring of the Registrant’s lease of Unit 4 at the Sundt Generating Station. (Form S-4, Registration No. 33-52860 -- Exhibit 10(i)(12).)
*10(c)(12)
--
Amendment No. 1, dated as of December 15, 1992, to Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, Financial Security Assurance Inc., as Surety, and Morgan Guaranty, as Indenture Trustee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(12).)
*10(c)(13)
--
Amended and Restated Lease, dated as of December 15, 1992, between TEP as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(13).)
*10(c)(14)
--
Amended and Restated Tax Indemnity Agreement, dated as of December 15, 1992, between TEP as Lessee and Ford Motor Credit Company, as Owner Participant. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(14).)
*10(d)
--
Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732 -- Exhibit 10(u).)
*10(e)
--
Lease Agreement, dated as of December 15, 1992, between TEP, as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(v).)
K-169
*10(f)
--
Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and TEP, as Lessee. (Form S-1, Registration No. 33-55732 -- Exhibit 10(w).)
*10(g)
--
Restructuring Agreement, dated as of December 1, 1992, between TEP and Century Power Corporation. (Form S-1, Registration No. 33-55732 -- Exhibit 10(x).)
+*10(h)
--
Omnibus Stock and Incentive Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43767.)
+*10(i)
--
Management and Directors Deferred Compensation Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43769.)
+*10(j)
--
TEP Supplemental Retirement Account for Classified Employees. (Form S-8 dated May 21, 1998, File No. 333-53309.)
+*10(k)
--
TEP Triple Investment Plan for Salaried Employees. (Form S-8 dated May 21, 1998, File No. 333-53333.)
+*10(l)
--
UniSource Energy Management and Directors Deferred Compensation Plan. (Form S-8 dated May 21, 1998, File No. 333-53337.)
+10(m)
--
Officer Change in Control Agreement between TEP and Karen G. Kissinger, dated as of December 4, 1998 (including a schedule of other officers who are covered by substantially identical agreements.)
+10(n)
--
Notice of Termination of Change in Control Agreement from TEP to Karen G. Kissinger, dated as of March 3, 2005 (including a schedule of other officers who received substantially identical notices.)
+*10(o)
--
Amended and Restated UniSource Energy 1994 Outside Director Stock Option Plan of UniSource Energy. (Form S-8 dated September 9, 2002, File No. 333-99317.)
*10(p)(1)
--
Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Electric Utility Business in the State of Arizona. (Form 8-K dated October 31, 2002. File No. 1-13739 -- Exhibit 99-1.)
*10(p)(2)
--
Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Gas Utility Business in the State of Arizona. (Form 8-K dated October 31, 2002. File No. 1-13739 -- Exhibit 99-2.)
*+10(q)
--
UniSource Energy 2006 Omnibus Stock and Incentive Plan (Form S-8 dated January 31, 2007. File No. 333-140353.)
12(a)
--
Computation of Ratio of Earnings to Fixed Charges - TEP.
12(b)
--
Computation of Ratio of Earnings to Fixed Charges - UniSource Energy.
--
Subsidiaries of the Registrants.
--
Consent of Independent Registered Public Accounting Firm.
24(a)
--
Power of Attorney - UniSource Energy.
24(b)
--
Power of Attorney - TEP.
31(a)
--
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UniSource Energy, by James S. Pignatelli.
K-170
31(b)
--
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - UniSource Energy by Kevin P. Larson.
31(c)
--
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act - TEP, by James S. Pignatelli.
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).
(*) 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 Exchange Act of 1934, as amended.
K-171