UNS Energy Corporation | | | | | | | |
Large Accelerated Filerþx | | Accelerated Filero | | Accelerated Filer ¨ | | Non-accelerated filero¨ | | | Smaller Reporting Companyo¨ |
Tucson Electric Power Company
| | | | | | | | Tucson Electric Power Company | | Large Accelerated Filero¨ | | Accelerated Filer ¨ | | Non-accelerated filerþx | | | Smaller Reporting Companyo¨ | | | | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | | | | | | | | | | | | | | | | | | |
UniSourceUNS Energy Corporation | | Yeso¨ | | Noþx | | | | | Tucson Electric Power Company | | Yeso¨ | | Noþx | | |
The aggregate market value of UniSourceUNS Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,082,660,902$1,574,040,179 based on the last reported sale price thereof on the consolidated tape on June 30, 2010. 2012.At February 15, 2011, 36,605,74813, 2013, 41,386,469 shares of UniSourceUNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. At February 15, 2011,13, 2013, 32,139,434 shares of Tucson Electric Power Company’s common stock,Common Stock, no par value, were outstanding, all of which were held by UniSourceUNS Energy Corporation. Tucson Electric Power Company meets the conditions set forth in General Instructions (I)(1)(a) and (b) on Form 10-K and is therefore filing this report with the reduced disclosure format. Documents incorporated by reference: Specified portions of UniSourceUNS Energy Corporation’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders are incorporated by reference into Part III.
v
DEFINITIONS DEFINITIONS
The abbreviations and acronyms used in the 20102012 Form 10-K are defined below: | | | |
| 1992 Mortgage | | TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented | 1999 Settlement2010 TEP Reimbursement Agreement | | TEP’s SettlementReimbursement Agreement approved by the ACC in November 1999 that provided for electric retail competitiondated December 14, 2010 among TEP as borrower and transition asset recovery | 2008 TEP Rate Order | | A rate order issued by the ACC resulting in a new retail rate structure for TEP,effective December 1, 2008financial institution | | ACC | | Arizona Corporation Commission | AMTAFUDC | | Alternative Minimum TaxAllowance for Funds Used During Construction | | AOCI | | Accumulated Other Comprehensive Income | | APS | | Arizona Public Service Company | | ARO | | Asset Retirement Obligation | | BART | | Best Available Retrofit Technology | | Base O&M | | A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business | | Base Rates | | The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs, and customer charge; and UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs. | | BHP | | BHP Minerals International, Inc. | | BMGS | | Black Mountain Generating Station | | Btu | | British thermal unit(s) | CCRs | | Coal combustion residuals | | Capacity | | The ability to produce power; the most power a unit can produce or the maximum that can be taken under a contract; measured in MWsmegawatts | | CC&N | | Certificate of Convenience and Necessity | | CCRs | | Coal Combustion Residuals | | Circuit Court | | United States Court of Appeals | | CO2 | | Carbon dioxideDioxide | | Common Stock | | UniSourceUNS Energy’s common stock, without par value | Company or UniSourceUNS Energy | | UniSourceUNS Energy Corporation and its subsidiaries | | Convertible Senior Notes | | UNS Energy Corporation’s 4.5% Convertible Senior Notes | | Cooling Degree Days | | An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures | | DSM | | Demand side managementSide Management | | ECA | | Environmental Compliance Adjustor | | EEIP | | Energy Efficiency Implementation Plan | | Electric EE Standards | | Electric Energy Efficiency Standards | | Emission Allowance(s) | | An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide; allowances can be bought and sold.sold | | Energy | | The amount of power produced over a given period of time; measured in MWhmegawatt-hours | | EPA | | The Environmental Protection Agency | | EL Paso | | El Paso Electric Company | | EPNG | | El Paso Natural Gas Company | | EPS | | Earnings Per Share | | ESP | | EnergyElectric Service Provider | Express LineFAA | | A dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service areaFederal Arbitration Act | | FERC | | Federal Energy Regulatory Commission | | Fixed CTC | | Competition Transition Charge of approximately $0.009 per kWh that was included in TEP’s retail rate for the purpose of recovering TEP’s TRA;Transition Recovery Asset; approximately $58 million is beingwas credited to customers through the PPFAC | | Four Corners | | Four Corners Generating Station | | GAAP | | Generally Accepted Accounting Principles | | Gas EE Standards | | Gas Utility Energy Efficiency Standards |
vi
| | | | GHG | | Greenhouse gasesGases | | GWh | | Gigawatt-hour(s) | Haddington | | Haddington Energy Partners II, LP, a limited partnership that funds energy-related investments | | Heating Degree Days | | An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65 | | IDBs | | Industrial development revenue or pollution control revenue bonds | | IRS | | Internal Revenue Service | | kV | | Kilovolt(s) | | kWh | | Kilowatt-hour(s) |
v
| LFCR | | | |
kV | | Kilovolt(s)Lost Fixed Cost Recovery Mechanism | | LIBOR | | London Interbank Offered Rate | | LOC | | Letter of Credit | Long-Term Wholesale Margin Revenues | | A non-GAAP measure that demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts | | Luna | | Luna Energy FacilityGenerating Station | | Mark-to-Market Adjustments | | ForwardAdjustments to forward energy sales and purchase contracts that are considered to be Derivativesderivatives and are adjusted monthly by recording unrealized gains and losses to reflect the market prices at the end of each month | | MATS | | Mercury and Air Toxics Standards | | Millennium | | Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource UNS Energy | | MMBtu | | Million British Thermal Units | | Mortgage Bonds | | Mortgage Bonds issued under the 1992 Mortgage | | MW | | Megawatt(s) | | MWh | | Megawatt-hour(s) | | Navajo | | Navajo Generating Station | | NERC | | North American Electric Reliability Corporation | NMED | | New Mexico Environmental Improvement Board | | NOx | | Nitrogen oxide | | NSP | | Negotiated Sales Program | | NTUA | | Navajo Tribal Utility Authority | | O&M | | Operations and Maintenance Expense | | PBI | | Performance Based Incentives | | PGA | | Purchased Gas Adjuster a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers | Pima Authority | | The Industrial Development Authority of the County of Pima | | PNM | | Public Service Company of New Mexico | | PNMR | | PNM Resources, Incorporated, PNM’s parent company | | PPA | | Power Purchase Agreement | | PPFAC | | Purchased Power and Fuel Adjustment Clause | | PV | | Photovoltaic | | RCRA | | Resource Conservation and Recovery Act | | REC | | Renewable Energy Credit | | RES | | Renewable Energy Standard and Tariff | Reimbursement AgreementRetail Margin Revenues | | Reimbursement Agreement datedA non-GAAP financial measure that demonstrates the underlying revenue trend | | | and performance of our core utility businesses | | Retail Rates | | Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service. Retail Rates include the recovery of fuel and purchased power costs, as of December 14, 2010 among TEPwell as borrowerother surcharges and a group of financial institutions.adjustor mechanisms charged to retail customers. | | Rules | | Retail Electric Competition Rules | Sabinas | | Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability company; prior to June 2009, Millennium owned 50% of Sabinas established by the ACC in 1999 | | San Carlos | | San Carlos Resources Inc., a wholly-owned subsidiary of TEP | | San Juan | | San Juan Generating Station | | SERP | | Supplemental Executive Retirement Plan | | SCR | | Selective catalytic reductionCatalytic Reduction | | SES | | Southwest Energy Solutions, a wholly-owned subsidiary of Millennium | | SO2 | | Sulfur dioxideDioxide | | Springerville | | Springerville Generating Station |
vii
| | | Springerville Coal Handling Facilities Leases | | Leveraged lease arrangements relating to the coal handling facilities serving Springerville | | Springerville Common Facilities | | Facilities at Springerville used in common withby all four Springerville Unit 1 and Springerville Unit 2units | | Springerville Common Facilities Leases | | Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities.Facilities | | Springerville Unit 1 | | Unit 1 of the Springerville Generating Station.Station | | Springerville Unit 1 Leases | | Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities | | Springerville Unit 2 | | Unit 2 of the Springerville Generating Station | | Springerville Unit 3 | | Unit 3 of the Springerville Generating Station | | Springerville Unit 4 | | Unit 4 of the Springerville Generating Station | | SRP | | Salt River Project Agricultural Improvement and Power District | | Sundt | | H. Wilson Sundt Generating Station (formerly known as the Irvington Generating Station) | | Sundt Lease | | The leveraged lease arrangement relating to Sundt Unit 4 | | Sundt Unit 4 | | Unit 4 of the H. Wilson Sundt Generating Station | | SWG | | Southwest Gas Corporation | | TEP | | Tucson Electric Power Company, the principal subsidiary of UniSourceUNS Energy Corporation | | TEP Credit Agreement | | Second Amended and Restated Credit Agreement between TEP and a syndicate of Banks,banks, dated as of November 9, 2010 (as amended) |
vi
| | | |
| TEP Letter of Credit Facility | | Letter of credit facility under the TEP Credit Agreement | | TEP Revolving Credit Facility | | Revolving credit facility under the TEP Credit Agreement | | Therm | | A unit of heating value equivalent to 100,000 British thermal units (Btu) | TRA | | Transition Recovery Asset, a $450 million regulatory asset established in TEP’s 1999 Settlement Agreement that was fully recovered in May 2008.Btus | | Transwestern | | Transwestern Pipeline Company | | Tri-State | | Tri-State Generation and Transmission Association, Inc. | | UED | | UniSource Energy Development Company, a wholly-owned subsidiary of UniSourceUNS Energy which engages in developing generation resources and other project development services and related activitiesCorporation | | UES | | UniSource Energy Services, Inc., an intermediate holding company established to own the operating companies (UNSUNS Gas and UNS Electric) which acquired the Citizens Arizona gas and electric utility assets in 2003Electric | UniSourceUNS Credit Agreement | | Second Amended and Restated Credit Agreement between UniSourceUNS Energy and a syndicate of banks, dated as of November 9, 2010 (as amended) | UniSourceUNS Energy | | UNS Energy Corporation (formerly known as UniSource Energy CorporationCorporation) | | UNS Electric | | UNS Electric, Inc., a wholly-owned subsidiary of UES | | UNS Electric Term Loan | | Four-year $30 million term loan agreement dated as of August 10, 2011 | | UNS Gas | | UNS Gas, Inc., a wholly-owned subsidiary of UES | | UNS Gas/UNS Electric Revolver | | Revolving credit facility under the Second Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, and UES as guarantor, and a syndicate of banks, dated as of November 9, 2010 (as amended) | | Valencia | | Valencia power plant owned by UNS Electric | | VEBA | | Voluntary Employee Beneficiary Association | | WAPA | | Western Area Power Administration |
vii
PART I This combined Form 10-K is being filed separately by UniSourceUNS Energy Corporation (UNS Energy) and Tucson Electric Power Company (TEP) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. TEP does not make any representation as to information relating to any other subsidiary of UniSourceUNS Energy. This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. You should read forward-looking statements together with the cautionary statements and important factors included elsewhere in this Form 10-K.10-K (SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, Safe Harbor for Forward-Looking Statements). Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions. Forward-looking statements are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. In addition, UniSourceUNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report. OVERVIEW OF CONSOLIDATED BUSINESS UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, is a utility services holding company that has no significant operationsengaged, through its subsidiaries, in the electric generation and energy delivery business. Each of its own. Operations are conducted by UniSourceUNS Energy’s subsidiaries each of which is a separate legal entity with its own assets and liabilities. UniSourceUNS Energy owns the outstanding common stock100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED) and Millennium Energy Holdings, Inc. (Millennium). We conduct our business in four primary business segments — TEP UNS Gas, Inc. (UNS Gas), UNS Electric, Inc. (UNS Electric), and Millennium Energy Holdings, Inc. (Millennium). TEP, an electricis a regulated public utility provides electric service to the community of Tucson, Arizona. UES, through its two operating subsidiaries, UNS Gas and UNS Electric, provides gas and electric service to 30 communities in northern and southern Arizona.
UED developed and owns the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility, which includes two natural gas-fired combustion turbines, provides energy toEnergy’s largest operating subsidiary, representing approximately 84% of UNS Electric through a power sales agreement.
Millennium has existing investments in unregulated businesses that represent less than 1% of UniSource Energy’s total assets as of December 31, 2010; no new investments are planned2012. TEP generates, transmits and distributes electricity to approximately 406,000 retail electric customers in Millennium. Southwest Energy Solutions (SES), a subsidiary1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Millennium, provides supplemental laborTri-State Generation and meter reading services to TEP,Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric. UniSource Energy was incorporatedElectric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 149,000 retail customers in the stateMohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated public utility, which generates, transmits and distributes electricity to approximately 92,000 retail customers in Mohave and Santa Cruz counties.UED and Millennium’s investments in unregulated businesses represent less than 1% of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997. TEP and UniSource Energy exchanged sharesUNS Energy’s assets as of stock in 1998, making TEP a subsidiary of UniSource Energy. December 31, 2012. K-1
BUSINESS SEGMENT CONTRIBUTIONS The table below shows the contributions to our consolidated after-tax earnings by our fourthree business segments. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | TEP | | $ | 107 | | | $ | 89 | | | $ | 4 | | | UNS Gas | | | 9 | | | | 7 | | | | 9 | | | UNS Electric | | | 10 | | | | 6 | | | | 4 | | | Millennium | | | (13 | ) | | | 2 | | | | — | | Other(1) | | | (2 | ) | | | — | | | | (3 | ) | | | | | | | | | | | | | Consolidated Net Income | | $ | 111 | | | $ | 104 | | | $ | 14 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | TEP | | $ | 65 | | | $ | 85 | | | $ | 108 | | UNS Gas | | | 9 | | | | 10 | | | | 9 | | UNS Electric | | | 17 | | | | 18 | | | | 15 | | Other Non-Reportable Segments and Adjustments(1) | | | — | | | | (3 | ) | | | (19 | ) | | | | | | | | | | | | | | Consolidated Net Income | | $ | 91 | | | $ | 110 | | | $ | 113 | | | | | | | | | | | | | | |
| | | | (1) | | Includes: UniSourceUNS Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on UniSource Energy Convertible Senior Notesexpenses, Millennium, UED, and on the Unisource Credit Agreement; and UED.intercompany eliminations. |
See Note 3 for additional financial information regarding our business segments. References in this report to “we” and “our” are to UniSourceUNS Energy and its subsidiaries, collectively. Rates and Regulation of TEP, UNS Gas, and UNS Electric The Arizona Corporation Commission (ACC) regulates portions of TEP, UNS Gas, and UNS Electric’s utility accounting practices and energy rates. The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties. Our regulated utility rates for retail electric and natural gas service are determined on a “cost of service” basis. Retail Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for usour utility businesses to earn a reasonable return on rate base. Rate base is generally determined by reference to the original cost (net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items, plus a working capital component. Over time, additions to utility plant in service increase rate base while depreciation and retirementretirements of utility plant reduce the rate base. The retail rates charged to retail customers by TEP, UNS Gas, and UNS Electric also include pass-through mechanisms that allow each utility to recover the actual costs of theirits fuel, transmission, and powerenergy purchases. The Federal Energy Regulatory Commission (FERC) regulates the terms and prices of transmission services and wholesale electricity sales, wholesale transport and purchases of natural gas, and portions of our accounting practices. TEP and UNS Electric have FERC tariffs to sell power at market basedmarket-based rates. TEP TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UniSourceUNS Energy. In 2010,2012, TEP’s electric utility operations contributed 77%78% of UniSourceUNS Energy’s operating revenues and comprised 81%84% of its assets. SERVICE AREA AND CUSTOMERS TEP is a vertically integrated utility that provides regulated electric service to approximately 403,000406,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately 1one million people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to other utilities and power marketing entities in the western United States. TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases, and other governmental entities. TEP’s retail sales are influenced by several factors, including economic conditions, seasonal weather patterns, demand side management (DSM) initiatives and the increasing use of energy efficient products. products, and opportunities for customers to generate their own electricity. K-2
Customer Base The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. Over the next several years,In 2013, the retail energy consumption by customer class is expected to be similar to the historical distribution. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | Residential | | | 42 | % | | | 42 | % | | | 41 | % | | Commercial | | | 21 | % | | | 21 | % | | | 21 | % | | Non-mining Industrial | | | 23 | % | | | 23 | % | | | 24 | % | | Mining | | | 12 | % | | | 11 | % | | | 11 | % | | Public Authority | | | 2 | % | | | 3 | % | | | 3 | % |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | Residential | | | 41 | % | | | 42 | % | | | 42 | % | Commercial | | | 21 | % | | | 21 | % | | | 21 | % | Non-mining Industrial | | | 23 | % | | | 23 | % | | | 23 | % | Mining | | | 12 | % | | | 11 | % | | | 12 | % | Public Authority | | | 3 | % | | | 3 | % | | | 2 | % |
Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. As a result of weak economic conditions during the last three years, TEP’s customer base grew at a slower rate than it had in prior years. In 2008, 20092012, 2011, and 2010, TEP’s average number of retail customers increased by less than 1% perin each year. This compares with average annual increases We expect the number of 2% from 2003TEP’s retail customers to 2007. increase at a rate of less than 1% in 2013 and 2014.Two of TEP’s largest retail customers are in the copper mining industry. TEP’s kilowatt-hour (kWh) sales to mining customers depend on a variety of factors including the market price of copper, the rateselectricity rate paid by mining customers, and the mines’ potential development of their own electric generation resources. We expect TEP’s kWh sales to mining customers increased by 0.9% in 2012 and 0.3% in 2011 as a result of increased production due to high copper prices.Retail Sales Volumes During the number ofpast three years, economic conditions and state requirements for energy efficiency and distributed generation have negatively affected retail electricity sales. TEP’s retail sales volumes in 2012 were approximately 9,265 Gigawatt-hours (GWh) or 1.1% below 2009. Energy Service Providers Although the Retail Electric Competition Rules established by the ACC in 1999 (Rules) contemplated that TEP’s retail customers to increase at a rate of 0.5% in 2011 and approximately 1% in 2012. We cannot predict if the rate of growth will return to historic levels. Sales Volumes
Weak economic conditions and the implementation of energy efficiency programs have had a negative impact on electricity sales. In 2008, TEP’s total retail kWh sales decreased by 1.4% compared with 2007. This was the first year-over-year decrease in TEP’s retail kWh sales since 2002. In 2009 and 2010, TEP’s kWh sales declined by 1.4% and 0.8%, respectively, below the prior year level.
This compares with average annual increases in retail kWh sales of 4% from 2003 to 2007. In 2011, we expect kWh sales to TEP’s retail customers to increase by less than 1% over the 2010 sales level.
Energy Service Providers
TEP’s retail customers aremay be eligible to choose an alternative energy service provider (ESP); however, none, portions of those Rules have been invalidated by the Arizona courts and there are no ESPs currently being served by anauthorized to provide alternative ESP.retail electric service to TEP’s customers. SeeRates and Regulation,below for more information regarding the status of retail competition in Arizona.
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. SeeGenerating and Other Resources, Purchases and Interconnections, below. K-3
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 generating capacity and energy (usually in the first, second and fourth calendar quarters), itsTEP’s wholesale sales consist primarily of two types of sales: Long-term wholesale sales contracts cover periods of more than one year. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers. TEP currently hasTEP’s long-term contracts with three entities to sell firm capacity and energy: From January 1, 2012 through the end of the contract in May 2016, Salt River Project (SRP) AgriculturalAgriculture Improvement and Power District — 100 MW, expires in May 2016. Under the current terms of the contract, TEP receives a demand charge of approximately $1.8 million per month, or $22 million annually, and provides the energy at a price based on TEP’s average fuel cost. Beginning in June 2011, SRP will be(SRP) is required to purchase 73,000 MWhs500,000 MWh of on-peak energy per month, or 876,000 MWhs annually.year. TEP willdoes not receive a demand charge and the price of energy will beis based on a slight discount to the Dow Jones Palo Verde Electricity Price Indexes (Palo Verde Market Index).Index. Prior to June 1, 2011, TEP received an annual demand charge of approximately $22 million. TEP’s contract with the Navajo Tribal Utility Authority (NTUA) expires in December 2015. TEP serves the portion of NTUA’s load that is not served from NTUA’sby the authority’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWhs.MWh per year. Since 2010, the price of 50% of the MWh sales to NTUA from June to September has been based on the Palo Verde Market Index. In 2010,2012, approximately 25%13% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA. TEP’s 2 MW contract with the Tohono O’odham Utility Authority — 2 MW, expires in 2014. Forward contracts commit TEP to sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one-month, three-month, or one-year periods. TEP also engages in short-term sales by selling energy in the daily or hourly markets at fluctuating spot market prices and making other non-firm energy sales. Since January 1, 2009, allAll revenues from short-term wholesale sales offset fuel and purchased power costs and are passed through to TEPTEP’s retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. SeeRates and Regulation,below. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations,for additional discussion of TEP’s wholesale marketing activities. K-4
GENERATING AND OTHER RESOURCES At December 31, 2010,2012, TEP owned or leased 2,2452,267 MW of net generating capability, as set forth in the following table: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net | | | | | | | | | | | Unit | | | | | | | Date | | | Fuel | | Capability | | | Operating | | | TEP’s Share | | | Generating Source | | No. | | | Location | | In Service | | | Type | | MW | | | Agent | | | % | | | MW | | Springerville Station(1) | | | 1 | | | Springerville, AZ | | | 1985 | | | Coal | | | 387 | | | TEP | | | 100.0 | | | | 387 | | | Springerville Station | | | 2 | | | Springerville, AZ | | | 1990 | | | Coal | | | 390 | | | TEP | | | 100.0 | | | | 390 | | | San Juan Station | | | 1 | | | Farmington, NM | | | 1976 | | | Coal | | | 340 | | | PNM | | | 50.0 | | | | 170 | | | San Juan Station | | | 2 | | | Farmington, NM | | | 1973 | | | Coal | | | 340 | | | PNM | | | 50.0 | | | | 170 | | | Navajo Station | | | 1 | | | Page, AZ | | | 1974 | | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | | Navajo Station | | | 2 | | | Page, AZ | | | 1975 | | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | | Navajo Station | | | 3 | | | Page, AZ | | | 1976 | | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | | Four Corners Station | | | 4 | | | Farmington, NM | | | 1969 | | | Coal | | | 784 | | | APS | | | 7.0 | | | | 55 | | | Four Corners Station | | | 5 | | | Farmington, NM | | | 1970 | | | Coal | | | 784 | | | APS | | | 7.0 | | | | 55 | | | Luna Energy Facility | | | 1 | | | Deming, NM | | | 2006 | | | Gas | | | 570 | | | PNM | | | 33.3 | | | | 190 | | | Sundt Station | | | 1 | | | Tucson, AZ | | | 1958 | | | Gas/Oil | | | 81 | | | TEP | | | 100.0 | | | | 81 | | | Sundt Station | | | 2 | | | Tucson, AZ | | | 1960 | | | Gas/Oil | | | 81 | | | TEP | | | 100.0 | | | | 81 | | | Sundt Station | | | 3 | | | Tucson, AZ | | | 1962 | | | Gas/Oil | | | 104 | | | TEP | | | 100.0 | | | | 104 | | | Sundt Station | | | 4 | | | Tucson, AZ | | | 1967 | | | Coal/Gas | | | 156 | | | TEP | | | 100.0 | | | | 156 | | | Sundt Internal Combustion Turbines | | | | | | Tucson, AZ | | | 1972-1973 | | | Gas/Oil | | | 50 | | | TEP | | | 100.0 | | | | 50 | | | DeMoss Petrie | | | | | | Tucson, AZ | | | 1972 | | | Gas/Oil | | | 85 | | | TEP | | | 100.0 | | | | 85 | | | North Loop | | | | | | Tucson, AZ | | | 2001 | | | Gas | | | 95 | | | TEP | | | 100.0 | | | | 95 | | | Springerville Solar Station | | | | | | Springerville, AZ | | | 2002-2010 | | | Solar | | | 6 | | | TEP | | | 100.0 | | | | 6 | | | Community Solar Projects | | | | | | Tucson, AZ | | | 2010 | | | Solar | | | 2 | | | TEP | | | 100.0 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total TEP Capacity(2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,245 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net | | | | | | | | | | Unit | | | | Date | | Resource | | Capability | | | Operating | | TEP’s Share | | Generating Source | | No. | | Location | | In Service | | Type | | MW | | | Agent | | % | | | MW | | Springerville Station(1) | | 1 | | Springerville, AZ | | 1985 | | Coal | | | 401 | | | TEP | | | 100.0 | | | | 401 | | Springerville Station | | 2 | | Springerville, AZ | | 1990 | | Coal | | | 403 | | | TEP | | | 100.0 | | | | 403 | | San Juan Station | | 1 | | Farmington, NM | | 1976 | | Coal | | | 340 | | | PNM | | | 50.0 | | | | 170 | | San Juan Station | | 2 | | Farmington, NM | | 1973 | | Coal | | | 340 | | | PNM | | | 50.0 | | | | 170 | | Navajo Station | | 1 | | Page, AZ | | 1974 | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | Navajo Station | | 2 | | Page, AZ | | 1975 | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | Navajo Station | | 3 | | Page, AZ | | 1976 | | Coal | | | 750 | | | SRP | | | 7.5 | | | | 56 | | Four Corners Station | | 4 | | Farmington, NM | | 1969 | | Coal | | | 784 | | | APS | | | 7.0 | | | | 55 | | Four Corners Station | | 5 | | Farmington, NM | | 1970 | | Coal | | | 784 | | | APS | | | 7.0 | | | | 55 | | Luna Generating Station | | 1 | | Deming, NM | | 2006 | | Gas | | | 555 | | | PNM | | | 33.3 | | | | 185 | | Sundt Station | | 1 | | Tucson, AZ | | 1958 | | Gas/Oil | | | 81 | | | TEP | | | 100.0 | | | | 81 | | Sundt Station | | 2 | | Tucson, AZ | | 1960 | | Gas/Oil | | | 81 | | | TEP | | | 100.0 | | | | 81 | | Sundt Station | | 3 | | Tucson, AZ | | 1962 | | Gas/Oil | | | 104 | | | TEP | | | 100.0 | | | | 104 | | Sundt Station | | 4 | | Tucson, AZ | | 1967 | | Coal/Gas | | | 156 | | | TEP | | | 100.0 | | | | 156 | | Sundt Internal Combustion Turbines | | | | Tucson, AZ | | 1972-1973 | | Gas/Oil | | | 50 | | | TEP | | | 100.0 | | | | 50 | | DeMoss Petrie | | | | Tucson, AZ | | 1972 | | Gas/Oil | | | 75 | | | TEP | | | 100.0 | | | | 75 | | North Loop | | | | Tucson, AZ | | 2001 | | Gas | | | 95 | | | TEP | | | 100.0 | | | | 95 | | Springerville Solar Station Tucson Solar Projects | | | | Springerville, AZ
Tucson, AZ | | 2002-2010
2010-2012 | | Solar
Solar | |
| 6
12 |
| | TEP
TEP | |
| 100.0
100.0 |
| |
| 6
12 |
| | | | | | | | | | Total TEP Capacity(2) | | | | | | | | | | | | | | | | | | | | | 2,267 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1) | | Leased assets,asset as of December 31, 2010.2012. |
| | (2) | | Excludes 799683 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2010,2012, total owned capacity was 1,8581,866 MW and leased capacity was 387401 MW. |
Springerville Generating Station SpringervilleTEP currently owns a 14% undivided interest in Unit 1 of the Springerville Generating Station (Springerville Unit 1) and the remainder is leased by TEP. TheUnit 2 of the Springerville Generating Station also includes(Springerville Unit 2) is owned by San Carlos Resources, Inc. (San Carlos), a wholly-owned subsidiary of TEP. TEP’s other interests in the Springerville Generating Station (Springerville) include leasehold interests in the Springerville Coal Handling Facilities and the facilities at Springerville used in common by all four Springerville units (Springerville Common Facilities. Facilities).Springerville Unit 1 Leases The terms of the leveraged lease arrangement relating to Springerville Unit 1 Leases, which include a 50%and an undivided one-half interest in thecertain Springerville Common Facilities (Springerville Unit 1 Leases), expire in 2015 but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back athe remaining 50% interest in the Springerville Common Facilities. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure to determine the fair market value purchase price. The formal appraisal process was completed in accordance with the Springerville Unit 1 lease agreements. The purchase price was determined to be $478 per kW of capacity, based on a continuous capacity rating of 387 MW. TEP has until September 1, 2013 to give notice that it will exercise its purchase option, with the purchase occurring in January 2015. TEP can choose to exercise this option to purchase any or all of the lease interests not currently owned by TEP. If TEP chooses to purchase all of the remaining interests in Springerville Unit 1 from the owner participants, the aggregate purchase price would be $159 million. SeeItem 3. – Legal Proceedings,Springerville Unit 1 Appraisal. Springerville Common Facilities Leases The leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities (Springerville Common Facilities Leases), which expire in 2017 and 2021, have optional fair market value renewal options as well as a fixed-price purchase provision. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 and $68 million in 2021. Springerville Coal Handling Facilities Lease In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. Since entering the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. The terms of the Springerville Coal Handling Facilities Leases expire in April 2015 but have optional fair market valuefixed-rate renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million. TEP is currently exploring its purchase and lease renewal options on all of these leases. Since entering into the Springerville leases, TEP has purchased a 14% equity ownership interest in the Springerville Unit 1 Leases and a 13% equity ownership interest in the Springerville Coal Handling Facilities Leases.
See Note 6 andItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for more information regarding the Springerville leases. K-5
Sundt Generating Station The H. Wilson Sundt Generating Station (Sundt) and the internal combustion turbines located in Tucson are designated as “must-run generation” facilities. Must-run generation units are required to run in certain circumstances to maintain distribution system reliability and to meet local load requirements. Until March 2010, Sundt Unit 4 was leased by TEP with a lease term expiration of January 2011. In March 2010, TEP purchased 100% of the equity interest in the Sundt Unit 4 from the equity ownerlease for approximately $52 million. In April 2010, TEP$51 million, redeemed the outstanding Sundt Unit 4 lease debt of $5 million, and terminated the lease agreement and caused the title of Sundt Unit 4 to be transferred to TEP. agreement.Renewable Energy Resources As of December 31, 2012, TEP owned 18 MW of photovoltaic (PV) solar generating capacity. The Springerville Generating Station Solar System,solar system, which is located near TEP’sthe Springerville coal-fired facility in eastern Arizona, includes 43,380 photovoltaic (PV) modules, withGenerating Station, has a total capacity of 6.46 MW. TEP began buildingTEP’s remaining 12 MW of PV solar generating capacity is located in the system in 2000 and has continued to expand it for several years, including a 1.8 MW addition in 2010. In 2010, TEP completed the constructionCity of a 1.6 MW single axis tracking PV array in Tucson.
Power Purchase Agreements In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 130125 MW of capacity from solar resources, 50 MW of capacity from wind resources and 2 MW of capacity from a landfill gas generation plant. TheseAs of December 31, 2012, approximately 74 MW of contracted solar resources and 50 MW of contracted wind resources were operational. The remaining resources are expected to be developed over the next several years. The 20-year solar PPAs contain options that would allow TEP to purchase all or part of the related project at a future period. SeeRates and Regulation, Renewable Energy Standard and Tariffbelow for more information. Purchases and Interconnections TEP purchases power from other utilities and power marketers. TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy for resale to certain wholesale customers under load and resource management agreements. TEP typically uses generation from its gas-fired units, supplemented by purchased power purchases, to meet the summer peak demands of its retail customers. Some of these PPAs are price-indexed to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years. TEP also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when doing so is more economical than generating its own energy. TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry. As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory reliability standards that are developed and enforced by the North American Electric Reliability Corporation (NERC) and subject to the oversight of the FERC. TEP is reviewingperiodically reviews its operating policies and procedures to ensure continued compliance with these standards. Springerville Units 3 and 4 Springerville Units 3 and 4 are each approximately 400 MW coal-fired generating facilities that are operated, but not owned by TEP. These facilities are located at the same site as TEP’s Springerville Units 1 and 2. Tri-State Generation and Transmission Association, Inc. (Tri-State) is leasing 100% of Unit 3 from a financial owner. Unit 4 began commercial operation in December 2009 and is owned by Salt River Project (SRP). The owners of Springerville Units 3 and 4 compensate TEP for operating the facilities and pay an allocated portion of the fixed costs related to the Springerville Common Facilities and Coal Handling Facilities. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations.Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4. K-6
Peak Demand and Resources | | | | | | | | | | | | | | | | | | | | | | | Peak Demand | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | | | | | | | | | | | -MW- | | | | | | | | | | Retail Customers | | | 2,333 | | | | 2,354 | | | | 2,376 | | | | 2,386 | | | | 2,365 | | | Firm Sales to Other Utilities | | | 340 | | | | 385 | | | | 394 | | | | 369 | | | | 331 | | | | | | | | | | | | | | | | | | | | Coincident Peak Demand (A) | | | 2,673 | | | | 2,739 | | | | 2,770 | | | | 2,755 | | | | 2,696 | | | | | | | | | | | | | | | | | | | | | | | | | Total Generating Resources | | | 2,245 | | | | 2,229 | | | | 2,204 | | | | 2,204 | | | | 2,194 | | Other Resources(1) | | | 799 | | | | 781 | | | | 966 | | | | 785 | | | | 719 | | | | | | | | | | | | | | | | | | | | Total TEP Resources (B) | | | 3,044 | | | | 3,010 | | | | 3,170 | | | | 2,989 | | | | 2,913 | | | | | | | | | | | | | | | | | | | | | | | | | Total Margin (B) — (A) | | | 371 | | | | 271 | | | | 400 | | | | 234 | | | | 217 | | | Reserve Margin (% of Coincident Peak Demand) | | | 14 | % | | | 10 | % | | | 14 | % | | | 8 | % | | | 8 | % | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Peak Demand | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | | | -MW- | | Retail Customers | | | 2,290 | | | | 2,334 | | | | 2,333 | | | | 2,354 | | | | 2,376 | | Firm Sales to Other Utilities | | | 286 | | | | 322 | | | | 340 | | | | 385 | | | | 394 | | | | | | | | | | | | | | | | | | | | | | | Coincident Peak Demand (A) | | | 2,576 | | | | 2,656 | | | | 2,673 | | | | 2,739 | | | | 2,770 | | | | | | | | Total Generating Resources | | | 2,267 | | | | 2,262 | | | | 2,245 | | | | 2,229 | | | | 2,204 | | Other Resources(1) | | | 683 | | | | 1,009 | | | | 799 | | | | 781 | | | | 966 | | | | | | | | | | | | | | | | | | | | | | | Total TEP Resources (B) | | | 2,950 | | | | 3,271 | | | | 3,044 | | | | 3,010 | | | | 3,170 | | | | | | | | Total Margin (B) – (A) | | | 374 | | | | 615 | | | | 371 | | | | 271 | | | | 400 | | Reserve Margin (% of Coincident Peak Demand) | | | 15 | % | | | 23 | % | | | 14 | % | | | 10 | % | | | 14 | % |
| | | | (1) | | Other Resources include firm power purchases and interruptible retail and wholesale loads. Additional firm power purchases were made in 2009 and 2010 to displace more expensive owned gas generation. |
Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions, and other factors. TEP’s retail peak demand peaked in 2007 and subsequently declined inover the period of 2008 through 2010to 2012 due primarily to weak economic conditions. conditions and the implementation of energy efficiency programs.The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s total margin is the difference between total energy resources and coincident peak demand, and the reserve margin is the ratio of margin to coincident peak demand. TEP’s reserve margin in 20102012 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC. Forecasted retail peak demand for 20112013 is 2,2412,243 MW, compared with actual peak demand of 2,3332,290 MW in 2010. In 2010, cooling degree days were 5% above2012 when Cooling Degree Days exceeded the ten-year average.average by 4.9%. TEP’s 20112013 estimated retail peak demand is based on normal weather patterns and total retail kWh sales similar to 2010 levels.patterns. TEP believes it will have sufficient resources to meet expected demand in 2011 with its existing generation capacity and power purchase agreements. agreements are sufficient to meet expected demand in 2013.Future Generating Resources TEP will add generating resources and/or transmission import capability to meet forecasted retail and firm wholesale load. TEP expects to add approximately 2865 MW of new solar PV resources in 2011 through 2014. We will 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 projects that additional import capacity and/or additional local peaking resources of 75 to 150 MW may be required in 2018. 2013. K-7
FUEL SUPPLY Fuel cost and usage information is provided below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Average Cost per MMBtu | | | Percentage of Total Btu | | | | | Consumed | | | Consumed | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | Coal | | $ | 2.23 | | | $ | 2.11 | | | $ | 2.08 | | | | 90 | % | | | 90 | % | | | 93 | % | | Gas | | $ | 4.69 | | | $ | 4.51 | | | $ | 8.02 | | | | 10 | % | | | 10 | % | | | 7 | % | | All Fuels | | $ | 2.47 | | | $ | 2.34 | | | $ | 2.52 | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Average Cost per MMBtu | | | Percentage of Total Btu | | | | | Consumed | | | Consumed | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | Coal | | $ | 2.44 | | | $ | 2.42 | | | $ | 2.23 | | | | 88 | % | | | 92 | % | | | 90 | % | Gas | | $ | 3.92 | | | $ | 5.20 | | | $ | 4.69 | | | | 12 | % | | | 8 | % | | | 10 | % | All Fuels | | $ | 2.63 | | | $ | 2.65 | | | $ | 2.47 | | | | 100 | % | | | 100 | % | | | 100 | % |
Coal TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico, and Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. The average cost per ton of coal, including transportation, forwas $45.84 in 2012, $46.64 in 2011, and $41.99 in 2010 2009 and 2008 was $41.99, $39.81, and $39.67, respectively. | | | | | | | | | | | | | | | | | | | | | | | 2010 Coal | | | | | | | Avg. | | | | | | | | | Consumption | | | Contract | | | Sulfur | | | | | Station | | Coal Supplier | | (tons in 000’s) | | | Expiration | | | Content | | | Coal Obtained From (A) | | Springerville | | Peabody Coalsales | | | 5,154 | | | | 2020 | | | | 0.9 | % | | Lee Ranch Coal Co. | | Four Corners | | BHP Billiton | | | 362 | | | | 2016 | | | | 0.8 | % | | Navajo Indian Tribe | | San Juan | | San Juan Coal Co. | | | 1,194 | | | | 2017 | | | | 0.8 | % | | Federal and State Agencies | | Navajo | | Peabody Coalsales | | | 510 | | | | 2019 | | | | 0.4 | % | | Navajo and Hopi Indian Tribes | | Sundt | | Peabody Coalsales | | | 220 | | | | 2012 | | | | 0.5 | % | | Twentymile Mine |
| | | | | | | | | | | | | | | | | Station | | Coal Supplier | | 2012 Coal
Consumption
(tons in 000’s) | | | Contract
Expiration | | | Avg.
Sulfur
Content | | | Coal Obtained From(1) | Springerville | | Peabody Coalsales | | | 3,287 | | | | 2020 | | | | 0.9 | % | | Lee Ranch Coal Co. | Four Corners | | BHP Billiton | | | 400 | | | | 2016 | | | | 0.8 | % | | Navajo Indian Tribe | San Juan | | San Juan Coal Co. | | | 1,098 | | | | 2017 | | | | 0.8 | % | | Federal and State Agencies | Navajo | | Peabody Coalsales | | | 475 | | | | 2019 | | | | 0.4 | % | | Navajo and Hopi Indian Tribes |
| (1) | | | (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 operator, and sole owner (or lessee), of the Springerville Units 1 and 2 and Sundt Unit 4. 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 Springerville Units 1 and 2 for their presently estimated remaining lives. The coal supplies for Sundt Unit 4 are transported approximately 1,300 miles by railroad from Colorado. In the past,Prior to 2010, Sundt Unit 4 has beenwas predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with methane, a renewable energy resource, piped in from a nearby landfill. From September through December ofSince 2010, TEP has fueled Sundt Unit 4 onwith both coal and natural gas taking advantage of the more economic natural gas prices.depending on which resource is most economic. In 2011 and 2012,2013, TEP expects to obtain coal forfuel Sundt Unit 4 with coal from the Twentymile Mine in Colorado. inventory. SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations andNote 4 of Notes to Consolidated Financial Statements — Commitments and Contingencies, TEP Commitments, Firm Purchase Commitments. for more information.Generating Facilities Operated by Others TEP also participates in jointly-owned coal-fired generating facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo), and the San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service (APS), and San Juan, which is operated by PNM,Public Service Company of New Mexico (PNM), are mine mouthmine-mouth generating stations located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. The coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining presently estimated lives of the stations. K-8
Natural Gas Supply TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from Southwest Gas Corporation under a retail tariff for North Loop’s 95 MWsMW of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie, an 85a 75 MW internal combustion turbine, both of which are located in Tucson.turbine. TEP purchases capacity from El Paso Natural Gas Company (EPNG) for transportation from the San Juan and Permian Basins to its Sundt plant under a contract that expires in April 2013, with right-of-first-refusal for continuation thereafter. TEP also buys gas from third-party suppliers for Sundt and DeMoss Petrie. TEP purchases gas transportation for Luna Generating Station (Luna) from EPNG from the Permian Basin to the plant site under an agreement that expires ineffective through January 2012,2017, with right-of-first-refusal for continuation thereafter. TEP purchases gas for its share of Luna from various suppliers in the Permian Basin region. WATER SUPPLY
The Four Corners region of New Mexico, where the San Juan and Four Corners generating facilities are located, experiences drought conditions periodically that could affect the water supply for these plants. 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 United States, combined with increased water usage in Arizona, Nevada and Southern California, have periodically caused water levels to recede at Lake Powell, which supplies operating water for Navajo. TEP has a 7.5% ownership interest in Navajo Units 1, 2 and 3 (totaling 168 MW of capacity). A project was completed in December 2009, which lowered the water intake structures to ensure adequate water supply at Navajo 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. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability, capacity and efficiency of its existing transmission and distribution systems. TEP is participating in the continuation of the 500 kV transmission line from the Pinal West substation to the Pinal Central substation. TEP is also in the process of obtaining permitshas obtained ACC approval to build a 40 mile40-mile 500-kV transmission line from the Pinal Central substation to the Tortolita substation northwest of Tucson to further enhance its ability to access the region’s energy resources. TEP expects the transmission lines to be in-service in 2014.service in 2016. As a result of these high-voltage transmission additions, TEP anticipatesexpects that its ability to import energy into its service territory shouldwould increase by at least 250 MW. Tucson to Nogales Transmission Line TEP and UNS Electric are parties to a project development agreement initiated in 2000 for the joint construction of a 60-mile 345kV transmission line from Tucson, Arizona to Nogales, Arizona. TheThis project development agreement was initiated in response to an order by the ACC to UNS Electric to improve the reliability to UNS Electric’s retail customersof electric service in Nogales and surrounding Santa Cruz County by building a second transmission line to Nogales. Since receiving approval from the ACC for construction along a specific route in 2002, TEP has been working to obtain all other required permits from state and federal agencies in addition to evaluating alternatives for improving service reliability in the area. As of December 31, 2010, TEP had previously capitalized $11 million related to the project, including $2 million ofto secure land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes that cost recovery is probable for prudent and reasonably incurred costsUNS Electric had previously capitalized $0.4 million related to the project.TEP and UNS Electric expect to abandon the project as a consequencebased on the cost of the ACC’s requirementproposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting the elimination of this project. In TEP’s pending rate case proceeding before the ACC, TEP entered into a second transmission line serving Santa Cruz County. proposed settlement agreement in which it agrees to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. In the fourth quarter of 2012, TEP and UNS Electric wrote off a portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and $0.2 million, respectively, of costs incurred through 2012. See Note 4 and seeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for more information. K-9
RATES AND REGULATION CaseIn November 2008, the ACC issuedJuly 2012, TEP filed an order that resolved a rate case filed by TEP in July 2007. Prior to the 2008 TEP Rate Order, TEP’s rates had remained unchanged since 2000. Base Retail Rates
TEP receivedapplication for a base rate increase effective December 1, 2008,with the ACC. SeeItem 7. – Management’s Discussion and Analysis of approximately 6% over its previous average retail rateFinancial Condition and Results of 8.4 cents per kWh. The average base rateOperations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, for the 12 months ended December 31, 2010 was 8.94 cents per kWh and includes approximately 3.01 cents per kWh for fuel and purchased power costs.
more information.Purchased Power and Fuel Adjustment Clause TEP’s PPFAC became effective January 1, 2009. The PPFACPurchased Power and Fuel Adjustment Clause (PPFAC) allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component. The forward component is updated on April 1 of each year. The forward component is based on the forecasted fuel and purchased power costs for the 12-month period from April 1 to March 31 lessof the base cost of fuel and purchased power embedded in base rates.following year. The true-up component will reconcile any over/under collected amounts from the preceding 12-month period and will be credited to or recovered from customers in the subsequent year. As of April 1, 2010, the PPFAC rate of 0.09 cents per kWh includes a forward component credit of 0.08 cents per kWh and a true-up component charge of 0.17 cents per kWh.
As part of the reconciliation of fuel and purchased power costs and PPFAC revenues, TEP credits, the following against the recoverable costs:among other things, 100% of short-term wholesale revenues; 10%revenues against the recoverable costs. In March 2012, the ACC approved a PPFAC rate of 0.77 cents per kWh effective April 2012 to recover $77 million of under-collected fuel and purchased power costs. At December 31, 2012, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $12 million. A proposed settlement agreement in TEP’s pending rate case proceeding includes certain modifications to TEP’s PPFAC. In February 2013, TEP filed a request with the ACC to defer the effective date of resetting the PPFAC until the effective date of new rates in TEP’s pending rate case. This request is consistent with a provision of the profit on trading activity; and 50% of the revenues from the sales of sulfur dioxide (SO2) emission allowances. On a cash basis, Fixed CTC revenue to be refunded ($58 million collected from May 2008 to November 30, 2008) is being credited to customers as an offset to the PPFAC. This credit will offset the forward and true-up components of the PPFAC, resulting in a PPFAC charge of zero until the Fixed CTC revenue to be refunded is fully credited, which is expected to occur by the end of 2011.
Base Rate Increase Moratorium
TEP’s base rates are frozen through December 31, 2012.settlement agreement. TEP is prohibited from submitting an application for new base rates before June 30, 2012. The test year to be used in TEP’s next base rate application must conclude no earlier than December 31, 2011.
Notwithstanding the rate increase moratorium, base rates and adjustor mechanisms may be changed in emergency conditions beyond TEP’s controlcannot predict if or when the ACC concludes such changes are requiredwill respond to protect the public interest. The moratorium does not precludeits request. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP from seeking rate relief in the event of the imposition of a federal carbon tax or related regulations.
Rate Case,PPFAC Modifications, for more information.Renewable Energy Standard and Tariff The ACC’s Renewable Energy Standard and Tariff (RES) requires TEP, UNS Electric, and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC and theACC. The approved cost of carrying out those plans areis recovered from retail customers through the RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in TEP’s financial statements as a regulatory asset or liability. K-10
In 2010, the ACC approved a funding mechanism that allows TEP to recover operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through RES funds until such costs are reflected in TEP’s Base Rates.In 2011, the ACC approved TEP’s RES implementation plan including investments of $28 million in 2012 and $8 million in 2013 for company-owned solar projects. In 2012, TEP’s solar energy investments totaled $28 million. During 2012, TEP earned approximately $2 million pre-tax on its non-rate base investments in solar projects. In 2012, TEP spent $36$30 million on its 2012 RES implementation plan and met the 20102012 renewable energy target of 2.5%.3.5% of retail kWh sales. In January 2013, the ACC approved TEP’s 2013 RES implementation plan. Under the plan, TEP expects to collect approximately $36 million in surcharges from retail customers during 2013. The plan includes an investment of $28 million in 2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2013 on solar investments made in 2010, 2011, to implement its RES plan and 2012. TEP expects to meet the 20112013 renewable energy target of 3%. For more information, seeItem 7. Management’s Discussion and Analysis4.0% of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff.
retail kWh sales.Electric Energy Efficiency Standards and Decoupling In August 2010, the ACC approved new Electric Energy Efficiency Standards (EE(Electric EE Standards) designed to require TEP, UNS Electric, and other affected electric utilities to implement cost effective DSM programs.cost-effective programs to reduce customers’ energy consumption. In 2011,2012, the Electric EE Standards target total kWh savings of 3% of 2011 retail kWh sales; in 2013, the Electric EE Standards target total kWh savings equal to 1.25% of 20105% of 2012 retail kWh sales. Targeted savingsThe Electric EE Standards increase annually in subsequent years until they reachthereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. The EE Standards provide for the recoverycumulative annual energy savings from TEP’s energy efficiency and DSM programs equaled approximately 2.5% of costs to implement the DSM programs. The EE Standards can be met by: newits 2011 retail kWh sales.New and existing DSM programs;programs, direct load control programs;programs, and by a portion of energy efficient building codes.codes are acceptable means to meet the Electric EE Standards as set forth by the ACC. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s DSM programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC. A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. SeeItem. 7—Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Energy Efficiency Resource Plan. Decoupling In December 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to make Arizona’s Electric EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring utility rates to separate the recovery of fixed costs from the level of energy consumed. The policy statement allows affected utilities to file rate decoupling proposals in their next general rate case. TEP expects to file its next generalA proposed settlement agreement in TEP’s pending rate case on or after June 30, 2012. proceeding includes a partial decoupling mechanism. SeeItem. 7—Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2012 TEP Rate Case, Lost Fixed Cost Recovery Mechanism.Retail Electric Competition Rules In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled ESPsElectric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2005.2004. In 2008, the ACC opened an administrative proceeding to address the Rules.Rules but has since taken no action. During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP’s service territory as an ESP. Unless and until the ACC clarifies the competition rules and ESPs offerRules and/or grants a CC&N to provide energy in TEP’s service area,an ESP, it is not possible for TEP’s retail customers to use an alternative ESPs.ESP. We cannot predict what changes, if any, the ACC will make to the Rules. Line Extension Policy
Pursuant to the 2008 TEP Rate Order, TEP began charging customers for the total cost of new line extensions, eliminating TEP’s prior practice of providing a portion of line extensions free of charge to its customers. Such charges are accounted for by TEP as contributions in-aid of construction. The policy became effective June 1, 2009. Prior to this ruling byRules or if the ACC will grant a portion of the cost of line extensions was capitalized by TEP and was eligible for inclusion in rate base.
Based on actions recently taken by the ACC in other utility proceedings, it is possible the ACC may take actionCC&N to reinstate free footage for TEP customers in the future. Such a change would serve to decrease contributions in-aid of construction and increase net capital outlays by TEP.
an ESP. K-11
TEPTEP’S UTILITY OPERATING STATISTICS
| | | | | | | | | | | | | | | | | | | | | | | | | For Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | Generation and Purchased Power — kWh (000) | | | | | | | | | | | | | | | | | | | | | | Remote Generation (Coal) | | | 9,077,032 | | | | 9,134,183 | | | | 10,438,864 | | | | 11,001,318 | | | | 10,854,710 | | | Local Tucson Generation (Oil, Gas & Coal) | | | 1,492,885 | | | | 1,131,399 | | | | 1,016,254 | | | | 1,065,778 | | | | 966,476 | | | Purchased Power | | | 2,760,002 | | | | 3,677,930 | | | | 3,692,873 | | | | 2,046,864 | | | | 1,680,495 | | | | | | | | | | | | | | | | | | | | Total Generation and Purchased Power | | | 13,329,919 | | | | 13,943,512 | | | | 15,147,991 | | | | 14,113,960 | | | | 13,501,681 | | | Less Losses and Company Use | | | 779,993 | | | | 793,791 | | | | 1,265,831 | | | | 921,024 | | | | 885,120 | | | | | | | | | | | | | | | | | | | | Total Energy Sold | | | 12,549,926 | | | | 13,149,721 | | | | 13,882,160 | | | | 13,192,936 | | | | 12,616,561 | | | | | | | | | | | | | | | | | | | | | | | | | Sales — kWh (000) | | | | | | | | | | | | | | | | | | | | | | Residential | | | 3,869,540 | | | | 3,905,696 | | | | 3,852,707 | | | | 4,004,797 | | | | 3,778,269 | | | Commercial | | | 1,963,469 | | | | 1,988,356 | | | | 2,034,453 | | | | 2,057,982 | | | | 1,959,141 | | | Industrial | | | 2,138,749 | | | | 2,160,946 | | | | 2,263,706 | | | | 2,341,025 | | | | 2,278,344 | | | Mining | | | 1,079,327 | | | | 1,064,830 | | | | 1,095,962 | | | | 983,173 | | | | 924,898 | | | Public Authorities | | | 240,703 | | | | 250,915 | | | | 255,817 | | | | 247,430 | | | | 260,767 | | | | | | | | | | | | | | | | | | | | Total — Electric Retail Sales | | | 9,291,788 | | | | 9,370,743 | | | | 9,502,645 | | | | 9,634,407 | | | | 9,201,419 | | | Electric Wholesale Sales | | | 3,258,138 | | | | 3,778,978 | | | | 4,379,515 | | | | 3,558,529 | | | | 3,415,142 | | | | | | | | | | | | | | | | | | | | Total Electric Sales | | | 12,549,926 | | | | 13,149,721 | | | | 13,882,160 | | | | 13,192,936 | | | | 12,616,561 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues (000) | | | | | | | | | | | | | | | | | | | | | | Residential | | $ | 372,212 | | | $ | 377,761 | | | $ | 351,079 | | | $ | 362,967 | | | $ | 343,459 | | | Commercial | | | 217,032 | | | | 219,694 | | | | 211,639 | | | | 213,364 | | | | 203,284 | | | Industrial | | | 159,937 | | | | 163,720 | | | | 164,849 | | | | 168,279 | | | | 165,068 | | | Mining | | | 62,112 | | | | 61,033 | | | | 55,619 | | | | 48,707 | | | | 43,724 | | | Public Authorities | | | 19,128 | | | | 19,865 | | | | 19,146 | | | | 18,332 | | | | 18,935 | | | RES and DSM | | | 37,767 | | | | 25,443 | | | | 2,781 | | | | — | | | | — | | | Other | | | — | | | | — | | | | 415 | | | | 4,822 | | | | 2,684 | | | | | | | | | | | | | | | | | | | | Total — Electric Retail Sales | | | 868,188 | | | | 867,516 | | | | 805,528 | | | | 816,471 | | | | 777,154 | | | CTC To Be Refunded | | | — | | | | — | | | | (58,092 | ) | | | — | | | | — | | | Wholesale Revenue-Long Term | | | 55,653 | | | | 48,249 | | | | 57,493 | | | | 55,788 | | | | 51,442 | | | Wholesale Revenue-Short Term | | | 71,146 | | | | 84,059 | | | | 197,415 | | | | 125,369 | | | | 112,309 | | | California Power Exchange Provision for Wholesale Refunds | | | (2,970 | ) | | | (4,172 | ) | | | — | | | | — | | | | — | | | Transmission | | | 20,863 | | | | 18,974 | | | | 17,173 | | | | 14,842 | | | | 13,391 | | | Other Revenues | | | 112,099 | | | | 84,361 | | | | 72,292 | | | | 58,033 | | | | 34,698 | | | | | | | | | | | | | | | | | | | | Total Operating Revenues | | $ | 1,124,979 | | | $ | 1,098,987 | | | $ | 1,091,809 | | | $ | 1,070,503 | | | $ | 988,994 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Customers (End of Period) | | | | | | | | | | | | | | | | | | | | | | Residential | | | 366,217 | | | | 365,157 | | | | 363,861 | | | | 361,945 | | | | 357,646 | | | Commercial | | | 35,877 | | | | 35,759 | | | | 35,432 | | | | 34,759 | | | | 34,104 | | | Industrial | | | 635 | | | | 629 | | | | 633 | | | | 641 | | | | 664 | | | Mining | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | Public Authorities | | | 62 | | | | 61 | | | | 61 | | | | 61 | | | | 61 | | | | | | | | | | | | | | | | | | | | Total Retail Customers | | | 402,793 | | | | 401,608 | | | | 399,989 | | | | 397,408 | | | | 392,477 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Average Retail Revenue per kWh Sold (cents) | | | | | | | | | | | | | | | | | | | | | | Residential | | | 9.6 | | | | 9.7 | | | | 9.1 | | | | 9.1 | | | | 9.1 | | | Commercial | | | 11.1 | | | | 11.0 | | | | 10.4 | | | | 10.4 | | | | 10.4 | | | Industrial and Mining | | | 6.9 | | | | 7.0 | | | | 6.6 | | | | 6.6 | | | | 6.6 | | | Average Retail Revenue per kWh Sold | | | 9.3 | | | | 9.3 | | | | 8.5 | | | | 8.5 | | | | 8.4 | | | | | | | | | | | | | | | | | | | | | | | | | Average Revenue per Residential Customer | | $ | 1,018 | | | $ | 1,036 | | | $ | 965 | | | $ | 1,003 | | | $ | 971 | | | Average kWh Sales per Residential Customer | | | 10,580 | | | | 10,708 | | | | 10,621 | | | | 11,129 | | | | 10,681 | |
K-12
| | | | | | | | | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | | Generation and Purchased Power – kWh (000) | | | | | | | | | | | | | | | | | | | | | Remote Generation | | | 10,284,612 | | | | 10,005,127 | | | | 9,077,032 | | | | 9,134,183 | | | | 10,438,864 | | Local Tucson Generation (Oil, Gas, & Coal) | | | 803,146 | | | | 906,496 | | | | 1,492,885 | | | | 1,131,399 | | | | 1,016,254 | | Renewable Generation | | | 44,930 | | | | 28,049 | | | | 24,511 | | | | 23,712 | | | | 33,776 | | Purchased Power | | | 2,328,420 | | | | 2,686,918 | | | | 2,846,005 | | | | 3,809,890 | | | | 3,358,577 | | | | | | | | | | | | | | | | | | | | | | | Total Generation and Purchased Power | | | 13,461,108 | | | | 13,626,590 | | | | 13,440,443 | | | | 14,099,184 | | | | 14,847,471 | | Less Losses and Company Use | | | 789,613 | | | | 822,220 | | | | 879,423 | | | | 936,206 | | | | 953,036 | | | | | | | | | | | | | | | | | | | | | | | Total Energy Sold | | | 12,671,495 | | | | 12,804,370 | | | | 12,561,010 | | | | 13,162,978 | | | | 13,894,435 | | | | | | | | Sales – kWh (000) | | | | | | | | | | | | | | | | | | | | | Residential | | | 3,820,637 | | | | 3,888,011 | | | | 3,869,540 | | | | 3,905,696 | | | | 3,852,707 | | Commercial | | | 1,973,931 | | | | 1,972,526 | | | | 1,963,469 | | | | 1,988,356 | | | | 2,034,453 | | Industrial | | | 2,132,214 | | | | 2,145,163 | | | | 2,138,749 | | | | 2,160,946 | | | | 2,263,706 | | Mining | | | 1,092,518 | | | | 1,083,071 | | | | 1,079,327 | | | | 1,064,830 | | | | 1,095,962 | | Public Authorities | | | 245,519 | | | | 243,336 | | | | 240,703 | | | | 250,915 | | | | 255,817 | | | | | | | | | | | | | | | | | | | | | | | Total – Electric Retail Sales | | | 9,264,819 | | | | 9,332,107 | | | | 9,291,788 | | | | 9,370,743 | | | | 9,502,645 | | Electric Wholesale Sales | | | 3,406,676 | | | | 3,472,263 | | | | 3,269,222 | | | | 3,792,235 | | | | 4,391,790 | | | | | | | | | | | | | | | | | | | | | | | Total Electric Sales | | | 12,671,495 | | | | 12,804,370 | | | | 12,561,010 | | | | 13,162,978 | | | | 13,894,435 | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues (000) | | | | | | | | | | | | | | | | | | | | | Residential | | $ | 387,840 | | | $ | 383,908 | | | $ | 372,212 | | | $ | 377,761 | | | $ | 351,079 | | Commercial | | | 228,940 | | | | 223,621 | | | | 217,032 | | | | 219,694 | | | | 211,639 | | Industrial | | | 166,739 | | | | 164,024 | | | | 159,937 | | | | 163,720 | | | | 164,849 | | Mining | | | 66,158 | | | | 65,720 | | | | 62,112 | | | | 61,033 | | | | 55,619 | | Public Authorities | | | 20,910 | | | | 20,024 | | | | 19,128 | | | | 19,865 | | | | 19,146 | | RES and DSM | | | 45,292 | | | | 46,633 | | | | 37,767 | | | | 25,443 | | | | 2,781 | | Other | | | — | | | | — | | | | — | | | | — | | | | 415 | | | | | | | | | | | | | | | | | | | | | | | Total – Electric Retail Sales | | | 915,879 | | | | 903,930 | | | | 868,188 | | | | 867,516 | | | | 805,528 | | CTC To Be Refunded | | | — | | | | — | | | | — | | | | — | | | | (58,092 | ) | Wholesale Revenue- Long-Term | | | 24,910 | | | | 41,056 | | | | 55,653 | | | | 48,249 | | | | 57,493 | | Wholesale Revenue- Short-Term | | | 71,257 | | | | 72,798 | | | | 71,435 | | | | 84,410 | | | | 197,754 | | California Power Exchange Provision for Wholesale Refunds | | | — | | | | — | | | | (2,970 | ) | | | (4,172 | ) | | | — | | Transmission | | | 15,793 | | | | 16,392 | | | | 20,863 | | | | 18,974 | | | | 17,173 | | Other Revenues | | | 133,821 | | | | 122,210 | | | | 112,098 | | | | 84,361 | | | | 72,292 | | | | | | | | | | | | | | | | | | | | | | | Total Operating Revenues | | $ | 1,161,660 | | | $ | 1,156,386 | | | $ | 1,125,267 | | | $ | 1,099,338 | | | $ | 1,092,148 | | | | | | | | | | | | | | | | | | | | | | | Customers (End of Period) | | | | | | | | | | | | | | | | | | | | | Residential | | | 369,480 | | | | 367,396 | | | | 366,217 | | | | 365,157 | | | | 363,861 | | Commercial | | | 36,214 | | | | 36,203 | | | | 35,877 | | | | 35,759 | | | | 35,432 | | Industrial | | | 632 | | | | 636 | | | | 635 | | | | 629 | | | | 633 | | Mining | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | Public Authorities | | | 62 | | | | 62 | | | | 62 | | | | 61 | | | | 61 | | | | | | | | | | | | | | | | | | | | | | | Total Retail Customers | | | 406,390 | | | | 404,299 | | | | 402,793 | | | | 401,608 | | | | 399,989 | | | | | | | | | | | | | | | | | | | | | | | Average Retail Revenue per kWh Sold (cents) | | | | | | | | | | | | | | | | | | | | | Residential | | | 10.2 | | | | 9.9 | | | | 9.6 | | | | 9.7 | | | | 9.1 | | Commercial | | | 11.6 | | | | 11.3 | | | | 11.1 | | | | 11.0 | | | | 10.4 | | Industrial and Mining | | | 7.2 | | | | 7.1 | | | | 6.9 | | | | 7.0 | | | | 6.6 | | Average Retail Revenue per kWh Sold (excludes RES and DSM) | | | 9.4 | | | | 9.2 | | | | 8.9 | | | | 9.0 | | | | 8.4 | | | | | | | | Average Revenue per Residential Customer | | $ | 1,050 | | | $ | 1,045 | | | $ | 1,016 | | | $ | 1,035 | | | $ | 965 | | Average kWh Sales per Residential Customer | | | 10,341 | | | | 10,583 | | | | 10,566 | | | | 10,696 | | | | 10,588 | |
ENVIRONMENTAL MATTERS Air and water quality, resource extraction, waste management and land use are regulated by federal, state and local authorities. TEP facilities are in substantial compliance with existing regulations.
Clean Air Act Requirements TEP generating facilities are subject toThe Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere.atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 $24 million in 2009 and $73 million in 2008 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan described below.Juan. TEP expects to capitalize environmental compliance costs of $8$10 million in 2013 and $27 million in 2014. In addition, TEP recorded Operations and Maintenance (O&M) expense of $15 million in 2012, $12 million in 2011, and $56 million in 2012. In addition, TEP recorded operating expenses of $14 million in 2010 $13 million in 2009 and $14 million in 2008 related to environmental compliance. TEP expects environmental O&M expenses to record $10be $16 million in operating expenses related to environmental compliance in 2011. 2013. TEP may incur additionaladded costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at existing electric generating facilities. Complianceits power plants. Complying with these changes may reduce operating efficiency. As a result TEP expects to recover the cost of the PNM Consent Decree, a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department — the co-owners of San Juan installed new pollution control equipment at the generating station to reduce the emissions of mercury, particulate matter, NOx, and SO2. TEP owns 50% of San Juan Units 1 and 2. The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan. TEP’s share of stipulated penalties at San Juan was $1 million in 2008. TEP cannot deduct these penalties for income tax purposes. With the installation of new pollution control equipment designed to remedy emission violations, we do not expect to incur similar penalties in the future.
compliance from its retail customers.TEP has sufficient Emission Allowancesemission allowances to comply with Acid Rainacid rain SO2 regulations. EPA Information Request
TEP is responding to a request received in October 2010 from the EPA under Section 114 of the Clean Air Act for information regarding projects at, and operations of, the Sundt Generating Station. TEP owns and operates all four units at Sundt. Units 1, 2 and 3 can be operated on either gas or diesel oil. Unit 4 can be operated on either gas or coal.
In April 2009, APS received a request from the EPA under Section 114 of the Clean Air Act for information regarding projects at, and operations of, Four Corners. Four Corners is operated by APS and includes five coal-fired generating units. TEP has a 7% ownership interest in Units 4 and 5, totaling 110 MW. APS responded to the request in August 2009.
The EPA uses information obtained from such requests to determine if additional action is necessary. TEP cannot predict whether the EPA will take further action at Sundt or Four Corners, or project the impact of any such action.
Hazardous Air Pollutant Requirements The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In October 2009,February 2012, the EPA entered into a consent order through which it agreed to developissued final rules establishing standardscalled the Mercury and Air Toxics Standards (MATS) setting limits for the control ofmercury emissions of mercury and other hazardous air pollutants from electric generating units and to issue final rules by November 2011. Dependingpower plants.Navajo Based on the stringencyEPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the EPA rule,estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which includes the regional haze final Best Available Retrofit Technology (BART) rules. San Juan TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards. Four Corners Based on the EPA’s final standards, Four Corners may be required at some or all coal-fired units by 2014 or later. Whetherneed mercury emission controls are required at a particular unit, the level of control required, and the cost to achieve that level of control will not be known until the rule has been promulgated. As stipulated in the PNM Consent Decree described above, the co-owners of San Juan installed new pollution control equipment atby 2015. TEP’s share of the generating stationestimated capital cost of this equipment is less than $1 million. We expect TEP’s share of the annual operating cost of the mercury emission control equipment to reduce mercury emissions. The installation of mercury emissions controls for San Juanbe less than $1 million.Springerville Generating Station Based on the EPA’s final standards, Springerville Units 1 and 2 were completed in 2009. These controls are expected to be adequate to achieve compliance with mercury requirements under the federal standard. K-13
Arizona adopted mercury emission rules in 2007 requiring a 90% reduction in emissions from coal-fired units. Due to potential inconsistency between the Arizona rule and the pending EPA rule, TEP and the Arizona Department of Environmental Quality reached an agreement in January 2009 that (1) defers the 90% reduction requirement to 2016, (2) improves regulatory certainty regarding mercury compliance obligations under existing Arizona rules, and (3) achieves mercury reductions substantially similar to those that would be required by the existing Arizona rules. In 2010, the agreement provisions were incorporated into the Springerville and Sundt operating permits and the agreement was terminated.
To comply with the Arizona rule, TEP expectsmay need mercury emission control equipment may be required at Springerville by 2016.2015. The associatedestimated capital cost forof this equipment is estimated to be $5 million for Springerville Units 1 and 2.2 is about $5 million. TEP expects the annual operating expenses for suchcost of the mercury emission control equipment wouldto be approximatelyabout $3 million, once all installations were completed.
million.Sundt Generating Station TEP expects the final EPA standards will have little effect on capital expenditures at Sundt. Climate Change In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et alal. v. EPA that carbon dioxide (CO2) and other greenhouse gases (GHGs)Greenhouse Gases (GHG) are air pollutants under the Clean Air Act. In December 2009, the EPA issued a final Endangerment Finding stating that GHGs endanger public health and welfare. The EPA issued final GHG regulations for new motor vehicles in April 2010 triggering GHG permitting requirements for power plants under the Clean Air Act. As of January 2, 2011, air quality permits for new sources and modifications of existing sources must include an analysis for GHG controls. In the near term, based on our current construction plans, we do not expect the new permitting requirements to impact TEP or UNS Electric. On a national level,In March 2012, the debate continues over the direction of domestic climate policy. Meanwhile, several statesEPA released its proposed new source performance standard for GHGs. TEP does not anticipate this standard will have developed state-specific policies or regional initiatives to reduce GHG emissions. In 2007, the governors of several western states, including the then-governor of Arizona, signed the Western Regional Climate Action Initiative (the Western Climate Initiative) that directed their respective states to develop a regional target for reducing greenhouse gases. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020. In 2008, the Western Climate Initiative participants submitted their design recommendation for the Western Climate Initiative cap-and-trade program for greenhouse gas emissions, with an implementation date set for 2012. In February 2010, the Governor of Arizona issued an executive order which, among other things, stated that Arizona will not implement the GHG cap-and-trade proposal advanced by the Western Climate Initiative. The executive order expires December 31, 2012.
In 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western Climate Initiative. Several parties are attempting to modify or rescind these regulations. We cannot predict if, or when, these new regulations willany material impact the generating output or cost of operations at San Juan and Luna.
on its existing facilities.Based on the competing proposals to regulate GHG emissions by federal, state, and local regulatory and legislative bodies and uncertainty in the regulatory and legislative processes, the scope of such requirements and initiatives and their effect on our operations cannot be determined at this time. The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART)BART for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areasareas. States must submit these goals and to submit a state implementation planstrategies to the EPA. The San Juan,EPA for approval. Because Navajo and Four Corners andare located on the Navajo participants’ obligationsIndian Reservation, they are not subject to complystate oversight. The EPA oversees Regional Haze planning for these power plants.Complying with the EPA’s BART determinations, coupledfindings, and with other future environmental rules, may make it economically impractical to continue operating the financial impact of future climate change legislation, other environmental regulationsNavajo, San Juan, and other business considerations, could jeopardize the economic viability of theseFour Corners power plants or the ability offor individual participantsowners to meet their obligations and continue their participationto participate in these power plants. TEP cannot predict the ultimate outcome of these matters. K-14
San Juan
In December 2010,January 2013, the EPA proposed a federal implementation plan under the Clean Air Act, addressing, among other things, regional haze requirements for San Juan. The EPA plan proposesan alternative BART determination that the BART for nitrogen oxides at San Juan is a technology known as selective catalytic reduction (SCR). The EPA’s proposal gives the San Juan participants three years from the date of the final rule to achieve compliance. A final federal implementation plan is expected in 2011. In June 2010, the New Mexico Environment Department (NMED) filed its proposed regional haze state implementation plan with the New Mexico Environmental Improvement Board. The plan also proposed that the BART for nitrogen oxides at San Juan iswould require the installation of SCRs. However, the NMED’s plan alsoSelective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. If SCR technology is ultimately required a technology known as sorbent injection, and it gave the San Juan participants five years to achieve compliance. The NMED withdrewat Navajo, TEP estimates its proposed implementation plan after the EPA filed its proposal.
PNM, the operator at San Juan, has indicated that it intends to vigorously challenge the EPA’s proposal, based on its own analysis concluding that SCR is not the BART for that plant.
TEP’s share of the capital expenditures related to the installation of SCRs at San Juan is estimated tocost will be $202$42 million. This estimate is based on a 2010 cost analysis ofAlso, the installation of SCR technology over a five-year period. The costat Navajo could increase the power plant’s particulate emissions which may require that baghouses be installed. TEP estimates that its share of the three-year installationcapital expenditure for baghouses would be about $43 million. TEP’s share of annual operating costs are estimated at less than $1 million for each of the control technologies (SCR and baghouses).San Juan In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the EPA could increase the costState of compliance. Adding this technology to San Juan would also increase operating costs at the generating station. Four Corners
In October 2010, EPA issued a proposed federal implementation plan for BART at Four Corners, which was supplemented in February 2011. If approved, the revised plan would requireNew Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit United States Court of Appeals (Circuit Court). In addition, PNM filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA’s reconsideration and the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. Several environmental groups were granted permission to join in opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP’s five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the Court’s decision. In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction (SNCR) technology on San Juan Units 1 and 4 by January 31, 2016. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $25 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At December 31, 2012, the book value of TEP’s share of San Juan Units 1 and 2 was $217 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. If the proposed plan is not accepted and agreed to by the EPA, New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in 2013 to meet the FIP compliance deadline. TEP cannot predict the outcome of this matter. Four Corners In August 2012, the EPA finalized the Regional Haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install these SCRsSCR technology is approximatelyabout $35 million. OnceTEP’s share of annual operating costs for SCR is estimated at $2 million. Springerville Regional Haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018. Sundt In December 2012, the EPA finalizesissued a proposed rule on provisions, that had not been previously addressed, in the Arizona State Implementation Plan related to regional haze. Contrary to the Arizona plan the EPA disapproved, among other things, the determination that Sundt Unit 4 is not subject to the BART rule for Four Corners, the Four Corners participants would have until 2018 to achieve compliance. Navajo
SRP, on behalfprovisions of the owners,regional haze rule and is currently participating in an EPA-sanctioned stakeholder process designedtherefore subject to determine BART for Navajo.requirements. If SCRthe BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART rule which is determined by the EPAlikely to be completed in October 2013. The EPA is expected to release a proposed BART at Navajo,requirement for Sundt Unit 4 in March 2013.Environmental Investments and Expenses The table below provides a summary of the estimated impact of pending environmental regulations on TEP’s annual O&M expense and capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCRs at Navajo could result in an increase in the level of particulate emissions from the plant and require the installation of baghouses. TEP’s estimated share of capital expenditures related to the installation of baghouses at Navajo is $43 million. The exact level and cost of pollution control required will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance. expenditures. | | | | | | | | | | | | | Generating Station | | Estimated
Annual O&M
Expense | | | Estimated
Capital
Expenditures | | | Regulation
(Compliance Date) | | Upgrades | | | | -Millions of Dollars- | | | | | | San Juan Units 1 & 2 | | $ | 6 | | | $ | 180 – $200 | | | Regional Haze/BART (2016) | | SCRs(1) | Navajo Units 1-3 | | $ | 3 | | | $ | 86 | | | MATS (2015)
Regional Haze/BART
(2023) | | Mercury Controls;
SCRs; Baghouses | Four Corners Units 4 & 5 | | $ | 3 | | | $ | 36 | | | MATS (2015)
Regional Haze/BART
(2018) | | Mercury Controls; SCRs | Springerville Units 1 & 2 | | $ | 3 | | | $ | 5 | | | MATS (2015) | | Mercury Controls |
| (1) | If SNCR technology is installed on San Juan Unit 1, TEP estimates its share of the cost would be approximately $25 million. SeeRegional Haze Rules, San Juan,above. |
Coal Combustion Residuals In June 2010, the EPA published its proposed regulations governinga rule to regulate the handling and disposal of coal combustion residualsash and other Coal Combustion Residuals (CCRs), which are primarily composed of coal ash.. The EPA proposeshas proposed regulating CCRs as either non-hazardous solid waste or as a hazardous waste. The hazardous waste proposalalternative would require certain additional capital investments and operational costs for both storage and handling at plants and transportation to disposal locations while phasing outlocations. Both the use of ash ponds for disposal of CCRs. The EPA advanced two proposals for regulating CCRs ashazardous waste and non-hazardous solid waste. One of these proposals would require retrofitting or closure of currently unlined ash ponds andwaste alternatives would require liners for new ash landfill expansions. The other proposal would not require pond closures and would allowlandfills or expansions to existing ash ponds to continue operating for the remainder of their useful lives without installation of liners.landfills. The rules will apply to CCRs produced by all of TEP’s coal-fired generating assets exceptassets. San Juan which ismay also be subject to separate regulations. regulations being drafted by the Office of Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits.The EPA has not yet indicated a preference for any of the alternatives.an alternative. Each alternativeoption would allow CCRs to be beneficially reused or recycled as components of other products instead of placed in impoundments or landfills.products. We do not know whenexpect the EPA willto issue a final rule including required compliance dates, andin 2013 or 2014. TEP cannot predictdetermine the outcome of the EPA’s actions. The financial impact of this rulemaking to TEP, if any, cannot be determined at this time. K-15
Ozone National Ambient Air Quality Standard
In January 2010, the EPA issued a proposed rule to reduce the National Ambient Air Quality Standard for ozone. Based on the range of standards proposed, certain counties in which TEP conducts operations could be in violation of the standard. A final rule is expected in July 2011. The financial impact to TEP, if any, cannot be determined at this time.
Notice of Intent to Sue
On May 7, 2010, APS received a Notice of Intent to Sue (the Notice) from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners. The Notice alleges New Source Review-related violations and New Source Performance Standard violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit. The 60-day period lapsed in early July without EPA action. At this time, TEP cannot predict whether or when Earthjustice might file a lawsuit.
UNS GAS SERVICE TERRITORY AND CUSTOMERS UNS Gas is a gas distribution company serving approximately 146,500149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as Santa Cruz County in southeastern Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 700,000. UNS Gas’ customer base is primarily residential. Sales to residential customers provided approximately 61%58% of total revenues in 2010, while sales to other retail customer classes accounted for about 27% of total revenues. From 2003 to 2007, the customer growth rate in UNS Gas’ service territory averaged 3% per year. As a result of weak economic conditions, 2012.UNS Gas’ annual retail customer growth rate was less than 1% from 20082010 through 2010.2012. In 2011,2013, we expect UNS Gas’ retail customer base to increase by less than 1%approximately 0.4%. GAS SUPPLY AND TRANSMISSION UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased and is affected by weather, supply issues, the economy, and other factors. UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month. UNS Gas buys most of the gas it distributes from the San Juan Basin in the Four Corners region.Basin. The gas is delivered on the EPNG and Transwestern Pipeline Company (Transwestern) interstate pipeline systems under firm transportation agreements with combined capacity sufficient to meet UNS Gas’ customers’ demands. With EPNG, the average daily capacity right of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000 therms per day in the winter season (November through March) to serve its northern and southern Arizona service territories. UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline. The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman and also the Griffith Power Plant in Mohave County. UNS Gas signed a separate agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line. The 15-year agreement beganLine that expires in 2009, when construction of that pipeline was completed.2024. UNS Gas’ average daily capacity right is 126,100 therms per day, with an average of 221,900 therms per day in the winter season (November through March). season.SeeItem 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. K-16
RATES AND REGULATION 2012 UNS Gas Rate Order In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a Lost Fixed Cost Recovery (LFCR) mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the Gas Energy Efficiency Standards (Gas EE Standards). The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012. The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills was offset by a temporary credit adjustment to the PGA. SeePurchased Gas Adjustor,below, for more information. 2010 UNS Gas Rate Order In November 2008, UNS Gas filedThe ACC authorized a general rate case with the ACC. In March 2010, the ACC issued an order authorizing a base rateBase Rate increase of $3 million, or 2%, effective in April 2010. | | | | | | | | | | | Test year – 12 months ended June 30, 2008 | | Requested by UNS Gas | | | 2010 ACC Order | | Original cost rate base | | $182 million | | $180 million | | Revenue deficiency | | $10 million | | $3 million | | Total rate increase (over test year revenues) | | 6% | | | 2% | | | Cost of equity | | 11.0% | | | 9.5% | | | Actual capital structure | | 50% equity / 50% debt | | 50% equity / 50% debt | | Weighted average cost of capital | | 8.75% | | | 8.0% | |
Purchased Gas Adjustor (PGA) The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism. The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that calculates the twelve-month12-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month12-month period. The annual cap on the maximum increase in the PGA factor is $0.1515 cents per therm in a twelve month12-month period. At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customersbilled-to-customer basis, UNS Gas is required to make a filing so thatwith the ACC canto determine how the over-collected balance should be returned to customers. On In April 2012, the ACC approved a temporary PGA credit adjustment of 4.5 cents per therm which became effective on May 1, 2012. At December 31, 2010,2012, the PGA bank balance was over-collected by $2$10 million on a billed-to-customersbilled-to-customer basis. Gas Utility Energy Efficiency Standards and Decoupling In August 2010, the ACC approved new Gas Utility Energy EfficiencyEE Standards (Gas EE Standards)which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2012, the Gas EE Standards targeted total retail therm savings equal to 1.2% of 2011 sales; in 2013, the Gas EE Standards target total retail therm savings equal to 0.5% of 20101.8% of 2012 retail therm sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020. The Gas EE Standards can be met by: new UNS Gas’ programs, during 2011 and 2012, saved cumulative energy equal to approximately 0.35% of its 2011 retail therm sales.New and existing DSM programs, renewable energy technology that displaces gas, and by a portion ofcertain energy efficient building codes.codes are acceptable means to meet the Gas EE Standards. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas’ DSM programs and rates charged to retail customers for these programs are subject to ACC approval. In December 2010,2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC approved a policy statement recognizingwill rule on the need to adopt rate decoupling or another mechanism to make Arizona’s Gas EE Standards viable. For more information about decoupling, seeTEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above. plan or the subsequent requests.
ENVIRONMENTAL MATTERS UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Gas’ facilities are in substantial compliance with existing regulations. SeeItem. 1 —– Business, TEP, Environmental Matters, for more information. K-17
UNS ELECTRIC SERVICE TERRITORY AND CUSTOMERS UNS Electric is ana vertically integrated electric transmission and distributionutility company serving approximately 91,00092,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 240,000. As a result of weak economic conditions, the annual increase in the number of retail customers and average energy use by retail customers is below the average levels experienced by UNS Electric in prior periods. From 2003 to 2007, the number of retail customers in250,000. UNS Electric’s service territory increased by an average of 3% per year, compared with no change in the average number ofannual retail customers during 2008 andcustomer growth rate was less than 1% growth in 2009 and 2010.from 2010 through 2012. We estimate that UNS Electric’s retail customer base will increase by less than 1%approximately 0.8% in 2011.2013. UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers. Peak demand for 20102012 was 471437 MW. POWER SUPPLY AND TRANSMISSION UNS Electric relies on a portfolio of long, intermediate, and short-term purchases to meet customer load requirements. The portfolio includes the output of UED’s Generating Resources UNS Electric owns and operates Black Mountain Generating Station (BMGS), a 90 MW BMGS, which has been purchased through a PPA with UED. The PPA, which expires in June 2013, is a tolling arrangement in whichgas-fired facility located near Kingman, Arizona. In July 2011, UNS Electric operatespurchased BMGS and assumes all risk of operation and maintenance costs, including fuel. Under the terms of the PPA, UNS Electric pays UED a capacity charge. The capacity charge and other costs associated with the PPA are recoverable through UNS Electric’s PPFAC.from UED. UNS Gas purchases and transports natural gas to BMGS for UNS Electric under long-term natural gas transportation and sales agreements. In UNS Electric’s 2010 Rate Order, the ACC approved the acquisition and inclusion of BMGS in UNS Electric’s rate base, subject to various conditions. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information.
Generating Resources
UNS Electric also owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. Valencia consists of four gas and diesel-fueled combustion turbine units and provides approximately 6862 MW of peaking resources. The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas. As noted above, UNS Electric also is in the process of acquiring the gas-fired BMGS from UED. SeeRates and Regulation, 2010 UNS Electric Rate Order, below for more information. Renewable Energy Resources UNS Electric has agreed to purchase the output of a combined wind farm and solar generating facility being builtlocated near Kingman. The above-market cost of energy purchased through the 20-year PPA will be recovered through the RES surcharge. For more information seeRates and Regulation, Renewable Energy Standard and Tariffbelow. Future Generating Resources UNS Electric invested $5 million in 2012 in company-owned solar PV capacity and expects to invest approximately $5 million annually from 2011 throughin 2013 and 2014 to build about 1.25 MW per year in company-owned solar PV capacity. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tarifffor more information. UNS Electric imports the power it purchases from UEDgenerated at BMGS into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has a network transmission service agreement for its primary transmission capacityagreements with WAPA for the Parker-Davis system that expires in May 2017. UNS Electric also has a long-term electric point-to-pointits transmission capacity agreement with WAPA for the Southwest Intertie system that expiresexpire in June 2011. 2016. UNS Electric is in the process of extendingupgrading its agreement with WAPA. K-18
UNS Electric plans to upgrade the existing 115 kV transmission line serving Santa Cruz County to 138 kV by the end of 2012 to improve service reliability. This upgrade is expected to be completed by October 2014 and is included in UNS Electric’s current capital expenditures forecast. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resourcesfor more information.
RATES AND REGULATION 2012 UNS Electric Rate Filing In December 2012, UNS Electric filed an application for a base rate increase with the ACC. SeeItem 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Filing, for more information. 2010 UNS Electric Rate Order On April 30, 2009, UNS Electric filed a rate case application with the ACC. In September 2010, the ACC issued an order authorizingauthorized a base rateBase Rate increase of $7.4 million, or 4%, effective in October 1, 2010. | | | | | | | | | | | | | Requested by | | | | | Test year – December 31, 2008 | | UNS Electric | | 2010 ACC Order | | | Original cost rate base | | $176 million | | $169 million | | Revenue deficiency | | $13.5 million | | $7.4 million | | Total rate increase (over test year revenues) | | 7% | | | 4% | | | Cost of debt | | 7.05% | | | 7.05% | | | Cost of equity | | 11.40% | | | 9.75% | | | Actual capital structure | | 46% equity / 54% debt | | 46% equity / 54% debt | | Weighted average cost of capital | | 9.04% | | | 8.28% | |
The ACC also approved the acquisition and inclusion of BMGS in UNS Electric’s rate base, subject to FERC approval and other conditions. Upon its purchase, BMGS will be included in UNS Electric’s rate base through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to non-fuel base rates. UNS Electric currently purchases all the output of BMGS under a contract with UED. UNS Electric expects to file an application with FERC in early 2011 requesting approval to purchase BMGS. If UNS Electric receives FERC approval and meets the other conditions set forth in the 2010 UNS Electric Rate Order we expect the acquisitionapproved UNS Electric’s purchase of BMGS to be completed and included in UNS Electric’s rate base during 2011.
from UED.The 2010 UNS Electric Rate Order also approved a plan for UNS Electric to invest $5 million each year from 2011 through 2014 in solar projects that would be owned by UNS Electric. In compliance with the 2010 Rate Order, UNS Electric filed a rate case application in December 2012. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff2012 UNS Electric Rate Filing,, for more information. Purchased Power and Fuel Adjustment Clause The PPFAC allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward component and a true-up component. The forward component is updated on June 1 of each year. The forward component is based on the forecasted fuel, transmission, and purchased power costs for the 12-month period from June 1 of the current year to May 31 of the following year, less the base cost of fuel, transmission, and purchased power costs embedded in base rates.Base Rates. The cap on the PPFAC forward component, over the 6.77 cents per kWh in base rates,Base Rates, is 1.845 cents per kWh. The true-up component will reconcile any over/under collected amounts from the preceding 12 month12-month period and will be credited to or recovered from customers in the subsequent year. At December 31, 2012, UNS Electric’s PPFAC bank balance was under-collected by $11 million on a billed-to-customer basis. Renewable Energy Standard and Tariff The ACC’s RES requires UNS Electric, TEP, and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC and theACC. The approved costcosts of carrying out those plans are recovered from retail customers through the RES surcharge. Any surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in UNS Electric’s financial statements as a regulatory asset or liability. K-19
InAs part of the 2010 UNS Electric spent $9 millionrate order, the ACC authorized UNS Electric to recover operating costs, depreciation, property taxes, and a return on its investment in company-owned solar projects through RES implementation and met the 2010 renewable energy target of 2.5%.funds until these costs are reflected in its Base Rates. Under these terms, UNS Electric expects to collect $8invest $5 million annually in surcharges from retail customers2013 and 2014 in 2011 to implement itssolar photovoltaic projects.In January 2013, the ACC approved UNS Electric’s 2013 RES plan and expects to meet the 2011 renewable energy target of 3%. For more information seePower Supply and Transmission, Renewable Energy Resources,above, andItem 7. Management’s Discussion and Analysis,implementation plan. UNS Electric Factors Affecting Resultswill collect approximately $7 million from customers during 2013, a portion of Operations, Renewable Energy Standardwhich is expected to provide recovery of operating costs and Tariff.
a return on investment to UNS Electric for company-owned solar projects.Energy Efficiency Standards and Decoupling In August 2010, the ACC approved newElectric EE Standards designed to require UNS Electric, TEP, and other affected electric utilities to implement cost effective DSM programs. For more information, seeTEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling, above. Line Extension Policy
As part UNS Electric’s programs, during 2011 and 2012, saved cumulative energy equal to approximately 2.5% of the 2008 its 2011 retail kWh sales.UNS Electric filed a general rate order,case in December 2012 which included a request for a partial decoupling mechanism. SeeItem. 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2012 UNS Electric Rate Case, Lost Fixed Cost Recovery Mechanism. In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC required UNS Electric to charge customers for the total cost of line extensions beginningwill issue a final order in March 2010. Such charges are accounted for by UNS Electric as contributions in aid of construction. Prior to this ruling by the ACC, a portion of the cost of line extensions was capitalized by UNS Electric and eligible for inclusion in rate base. In January 2011, based in part on strong community support for UNS Electric’s former line extension policy, the ACC reinstated UNS Electric’s line extension policy that was in effect prior to the 2008 rate order. The result of this change will be to reduce contributions in-aid of construction thereby increasing net capital spending by UNS Electric.
ENVIRONMENTAL MATTERS UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Electric believes that its facilities are in substantial compliance with all existing regulations and will be in compliance with expected environmental regulations. SeeItem. 1 —– Business, TEP, Environmental Matters, for more information. OTHER NON-REPORTABLE SEGMENTSMILLENNIUMMillennium
Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies. Millennium is in the processAs of exiting its remaining investments which may yield gains or losses. At December 31, 2010,2012, Millennium had assets of $22$7 million, including a $15 million note receivable; landcash and buildingscash equivalents of $2 million; deferred tax assets of $2 million; and $3 million in cash.$4 million. In total, Millennium’s assets represented less than 1% of UniSourceUNS Energy’s total consolidated assets. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, Millennium,Other Non-Reportable Business Segments,for more information. SES SES, a wholly ownedwholly-owned subsidiary of Millennium, provides commercial and residential electrical contracting and meter reading services in southern Arizona. Arizona, as well as other services at Springerville.Sabinas
In 2009, Millennium sold its 50% interest in Sabinas and recorded a $6 million pre-tax gain on the sale. Millennium received an upfront $5 million cash payment in January 2009. Other key terms of the transaction included a three-year, 6% interest-bearing, collateralized $15 million note.
OTHER
UED
UED developed and owns the 90 MW BMGS. SeeUNS Electric, Power Supply and Transmission, above for more information regarding BMGS.
K-20
EMPLOYEES (As of December 31, 2010)2012) TEP had 1,3841,392 employees, of which approximately 52%49% are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A new collective bargaining agreement between the IBEW and TEP was entered into in January 2013 and expires in January 2013. 2016.UNS Gas had 194186 employees, of which 83110 employees were represented by IBEW Local No. 1116 and five5 employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 20122015 and February 2014, respectively. UNS Electric had 155148 employees, of which 2730 employees were represented by the IBEW Local No. 387 and 9788 employees were represented by the IBEW Local No. 769. The existing agreementagreements with the IBEW Local No. 387 and No. 769 expire in February 2014 and June 2013, respectively. SES had 260253 employees, of which approximately 96% are represented by unions. Of the employees represented by unions, 233226 are represented by IBEW Local No. 1116 and 1716 by IBEW Local No. 570; these570. These agreements expire onin December 31, 2012,2014 and May 31, 2012,2013, respectively. EXECUTIVE OFFICERS OF THE REGISTRANTS Executive Officers — UniSource– UNS Energy and TEP The Executive Officers of UniSource Energy are the same as TEP. Executive Officers of UniSourceUNS Energy and TEP, who are elected annually by UniSourceUNS Energy’s Board of Directors and TEP’s Board of Directions, respectively,Directors, are as follows: | | | | | | | | | | | | | | | Executive | | Name | | Age | | Position(s) Held | | Officer Since | | Paul J. Bonavia | | 59 | | Chairman, President and Chief Executive Officer | | 2009 | | Michael J. DeConcini | | 46 | | Senior Vice President, Operations(1) | | 1999 | | Raymond S. Heyman | | 55 | | Senior Vice President and General Counsel | | 2005 | | Kevin P. Larson | | 54 | | Senior Vice President, Chief Financial Officer and Treasurer | | 2000 | | Philip J. Dion III | | 42 | | Vice President, Public Policy | | 2008 | | Kentton C. Grant | | 52 | | Vice President, Finance and Rates | | 2007 | | Arie Hoekstra | | 63 | | Vice President, Generation | | 2007 | | David G. Hutchens | | 44 | | Vice President, Energy Efficiency and Resource Planning | | 2007 | | Karen G. Kissinger | | 56 | | Vice President, Controller and Chief Compliance Officer | | 1998 | | Steven W. Lynn | | 64 | | Vice President and Chief Customer Officer | | 2003 | | Thomas A. McKenna | | 62 | | Vice President, Engineering | | 2007 | | Catherine E. Ries | | 51 | | Vice President, Human Resources | | 2007 | | Herlinda H. Kennedy | | 49 | | Corporate Secretary | | 2006 |
(1) Mr. DeConcini holds the positions of Senior Vice President of UniSource Energy and Chief Operating Officer of TEP.
| | | | | | | Name | | Age | | Position(s) Held | | Executive
Officer Since | | Paul J. Bonavia | | 61 | | Chairman and Chief Executive Officer | | 2009 | | David G. Hutchens | | 46 | | President | | 2007 | | Michael J. DeConcini | | 48 | | Senior Vice President, Operations | | 1999 | | Kevin P. Larson | | 56 | | Senior Vice President and Chief Financial Officer(1) | | 2000 | | Philip J. Dion III | | 44 | | Vice President, Public Policy | | 2008 | | Kentton C. Grant | | 54 | | Vice President, Finance and Rates(2) | | 2007 | | Todd C. Hixon | | 46 | | Vice President and General Counsel | | 2011 | | Arie Hoekstra | | 65 | | Vice President, Generation | | 2007 | | Karen G. Kissinger | | 58 | | Vice President, Controller and Chief Compliance Officer | | 1998 | | Mark Mansfield | | 57 | | Vice President, Generation | | 2012 | | Thomas A. McKenna | | 64 | | Vice President, Engineering | | 2007 | | Catherine E. Ries | | 53 | | Vice President, Human Resources | | 2007 | | Herlinda H. Kennedy | | 51 | | Corporate Secretary | | 2006 |
| (1) | Mr. Larson is also Treasurer at UNS Energy. |
| (2) | Mr. Grant is also Treasurer at TEP. |
| | | | | Paul J. Bonavia | | Mr. Bonavia has served as Chairman President and Chief Executive Officer of UniSourceUNS Energy and TEP since January 2009. He also served as President from January 2009 to December 2011. Prior to joining UniSourceUNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit. | | | | David G. Hutchens | | Mr. Hutchens has served as President of UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995. | | | | Michael J. DeConcini | | Mr. DeConcini has served as Senior Vice President, Operations of UniSourceUNS Energy since May 2010 and Senior Vice President and Chief Operating Officer of TEP sincefrom May 2009.2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution. | | | | Raymond S. Heyman
| | Mr. Heyman has served as Senior Vice President and General Counsel of UniSource Energy and TEP since September 2005. Prior to joining UniSource Energy and TEP, Mr. Heyman was a member of the Phoenix, Arizona law firm Roshka Heyman & DeWulf, PLC. | | | | Kevin P. Larson | | Mr. Larson has served as Senior Vice President and Chief Financial Officer of UniSourceUNS Energy and TEP since September 2005. Mr. Larson is also Treasurer of UniSourceUNS Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Treasurer in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer. |
K-21
| | | | | Philip J. Dion III | | Mr. Dion has served as Vice President of Public Policy of UniSourceUNS Energy and TEP since April 2010. Mr. Dion joined UniSourceUNS Energy in February 2008 as Vice President of Legal and Environmental Services. Prior to joining UniSourceUNS Energy, Mr. Dion was chief of staff and chief legal advisor to Commissioner Marc Spitzer of the FERC. Mr. Dion previously worked in various roles at the ACC, including as an administrative law judge and as an advisor to Mr. Spitzer, prior to his appointment to the FERC. | | | | Kentton C. Grant | | Mr. Grant has served as Vice President of Finance and Rates of UniSourceUNS Energy and TEP since January 2007. Mr. Grant also serves as Treasurer of TEP and UES.TEP. Mr. Grant joined TEP in 1995. | | | | Todd C. Hixon | | Mr. Hixon has served as Vice President and General Counsel of UNS Energy and TEP since May 2011. Mr. Hixon joined TEP’s legal department in 1998 and served in a variety of capacities, most recently serving as Associate General Counsel. | | | | Arie Hoekstra | | Mr. Hoekstra has served as Vice President of Generation of UniSourceUNS Energy and TEP since January 2007. Mr. Hoekstra joined TEP in 1979 and thereafter served in various positions at TEP’s generating stations in Tucson and Springerville. | | | | David G. Hutchens
| | Mr. Hutchens has served as Vice President of Energy Efficiency and Resource Planning of UniSource Energy and TEP since May 2009. Mr. Hutchens joined TEP in 1995. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UniSource Energy and TEP and Vice President of UNS Gas. | | | | Karen G. Kissinger | | Ms. Kissinger has served as Vice President, Controller and Principal Accounting Officer of UniSourceUNS Energy and TEP since January 1998 and has served as Chief Compliance Officer since 2003. Ms. Kissinger joined TEP as Vice President and Controller in January 1991. | | | | Steven W. LynnMark Mansfield
| | Mr. Lynn has served as Vice President and Chief Customer Officer of UniSource Energy and TEP since April 2010. Mr. Lynn joined UniSource Energy in 2000 and in January 2003, was electedMansfield is Vice President of Communications and Government Relations.Generation. He joined the company in 2008, most recently serving as Senior Director of Generation. Prior to joining TEP, Mr. Mansfield held various leadership positions at PacifiCorp Energy. | | | | Thomas A. McKenna | | Mr. McKenna has served as Vice President of Engineering of UniSourceUNS Energy and TEP since January 2007. Mr. McKenna has also served as Vice President of UNS Electric since January 2007 and in May 2009 was named Vice President of UNS Gas. Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998. | | | | Catherine E. Ries | | Ms. Ries has served as Vice President of Human Resources of UniSourceUNS Energy and TEP since June 2007. Prior to joining UniSourceUNS Energy, Ms. Ries worked for Clopay Building Products, a division of Griffon Corporation, from 2000 to 2007, and held the position of Vice President of Human Resources. | | | | Herlinda H. Kennedy | | Ms. Kennedy has served as Corporate Secretary of UniSourceUNS Energy and TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999. |
SEC REPORTS AVAILABLE ON UNISOURCEUNS ENERGY’S WEBSITE UniSourceUNS 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 practicablepractical after they electronically file them with, or furnish them to, the Securities and Exchange Commission (SEC). These reports are available free of charge through UniSourceUNS Energy’s website address:http://www.uns.com. A link from UniSourceUNS Energy’s website to these SEC reports is accessible as follows: At the UniSourceUNS Energy main page, select Investors from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page. UniSourceUNS Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UniSourceUNS Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, is also available on UniSourceUNS Energy’s website. K-22
UNS Energy and TEP are providing the address of UNS Energy’s website solely for the information of investors and do not intend the address to be an active link. Information contained at UniSourceUNS Energy’s website is not part of any report filed with the SEC by UniSourceUNS Energy or TEP. ITEM 1A. – RISK FACTORSThe business and financial results of UniSourceUNS Energy and TEP are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the SEC. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational. National and local economic conditions can have a significant impact on the results of operations, net income, and cash flows at TEP, UNS Gas, and UNS Electric. Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the company’s residential, commercial, and industrial customers. From 2003 to 2007, customer growth in TEP’s service territory averaged approximately 2% per year. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 1% per0.4% in each year infrom 2008 through 2010.2012 compared with average increases of approximately 2% in each year from 2003 to 2007. In 2010,2012, total retail kWh sales were 0.8%0.7% below 20092011 levels. TEP estimates that a 1% decreasechange in annual retail sales could reduceimpact pre-tax net income and pre-tax cash flows by approximately $6 million. Similar impacts were felt at UNS Gas and UNS Electric. Annual average increases in the number of retail customers at both companies remained below 1% in 2008 through 20102012 compared with average annual growth rates of 3% to 4% from 2003 to 2007. We estimate that a 1% decreasechange in annual retail sales at UNS Gas and UNS Electric could reduceimpact pre-tax net income and pre-tax cash flows by less thanapproximately $1 million. TEP’s base rates are frozen through December 31, 2012, which could limit our ability to cope with the impact of risks and uncertainties and negatively affect TEP’s results of operations, net income and cash flows.
Under the terms of the 2008 TEP rate order, TEP is prohibited from submitting an application for new base rates before June 30, 2012, and new rates cannot go into effect prior to January 1, 2013. If the cost of serving TEP’s customers rises more quickly than the revenues it collects from customers, TEP’s results of operations, net income and cash flows could be negatively impacted.
New technological developments and the implementation of new Energy Efficiency Standards maywill continue to have a significant impact on retail sales, which could negatively impact UniSourceUNS Energy’s results of operations, net income, and cash flows. Heightened awareness of energy costs has increased demand for products intended to reduce consumers’ use of electricity. TEP and UNS Electric also are promoting DSM programs designed to help customers reduce their energy use, and these efforts will increase significantly under new energy efficiency rules approved in 2010 by the ACC. Unless the ACC makes a specific provision for the recovery of usage-based revenues lost to these energy efficiency programs, the reduced retail sales that would result from the success of these efforts would negatively impact the results of operations, net income, and cash flows of TEP and UNS Electric. The revenues, results of operations, and cash flows of TEP, UNS Gas, and UNS Electric are seasonal, and are subject to weather conditions and customer usage patterns, which are beyond the companies’ control. TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during Tucson’s hot summer weather.the summer. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales peak in the winter during home heating season. Cool summers or warm winters may affectreduce customer usage at all three companies, adversely affecting operating revenues, cash flows, and net income by reducing sales. TEP estimates that a 1% decreaseimpact in annual retail sales could reducewould impact pre-tax net income and pre-tax cash flows by approximately $6 million. We estimate that a 1% decreasechange in annual retail sales at UNS Gas and UNS Electric could reducewould impact pre-tax net income and pre-tax cash flows by less thanapproximately $1 million. K-23
REGULATORY
TEP, UNS Gas, and UNS Electric are subject to regulation by the ACC, which sets the companies’ retail ratesRetail Rates and oversees many aspects of their business in ways that could negatively affect the companies’ results of operations, net income, and cash flows. The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years. The ACC is charged with setting retail electric and gas rates that provide utility companies with an opportunity to recover their costs of service and earn a reasonable rate of return. The decisions these elected officials make on such matters impact the net income and cash flows of TEP, UNS Gas, and UNS Electric. Changes in federal energy regulation may negatively affect the results of operations, net income, and cash flows of TEP, UNS Gas, and UNS Electric. TEP, UNS Gas, and UNS Electric are subject to the impact of comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industries and the ways in which these industries are regulated. UniSourceUNS Energy’s electric utility subsidiaries are subject to regulation by the FERC. The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale prices. ENVIRONMENTAL ENVIRONMENTAL
UniSourceUNS Energy’s utility subsidiaries are subject to numerous environmental laws and regulations that may increase their cost of operations or expose them to environmentally-related litigation and liabilities.Many of these regulations could have a significant impact on TEP due to its reliance on coal as its primary fuel for energy generation.
UniSource Energy’s utility subsidiaries are subject to numerousNumerous federal, state, and local environmental laws and regulations affectingaffect present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste, and management of CCRs. coal combustion residuals.These laws and regulations can contribute to higher capital, operating, and other costs, particularly with regard to enforcement efforts focused on existing power plants and new compliance plans with regardstandards related to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations mightmay result in litigation, and the imposition of fines, penalties, and penaltiesa requirement for costly equipment upgrades by regulatory authorities. We cannot provide assurance that existing environmental laws and regulations will not be revised or that new environmental laws and regulations will not be adopted or become applicable to us.our facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers.customers. TEP’s obligation to comply with the EPA’s BART determinations as a participant in the San Juan, Four Corners, and Navajo plants, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to meet their obligations and continue their participation in these plants. TEP cannot predict the ultimate outcome of these matters. TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has a minority interest and it may beis obligated to pay similar costs at the mines that supply these generating stations. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial. K-24
New federal regulations to limit greenhouse gas emissions could increase TEP’s cost of operations and result in a change in the composition of TEP’s coal-dominated generating fleet. Based on the finding by the EPA in December 2009 that emissions of greenhouse gases endanger public health and welfare, the agency is in the process of regulating greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, federal, and international levels to address global climate change that could also result in the regulation of carbon dioxide (COCO2) and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2010, 76%2012, 72% of TEP’s total energy resources came from its coal-fueled generating facilities. Reductions in CO2 emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. Any future legislation or regulation addressing climate change could produce a number of other results including costly modifications to, or reexamination of the economic viability of, our existing coal plants; changes in the overall fuel mix of our generating fleet; or additional costs to fund energy efficiency activities. The impact of legislation or regulation to address global climate change would depend on the specific terms of those measures and cannot be determined at this time. Volatility or disruptions in the financial markets may increase our financing costs, limit our access to the credit markets, and increase our pension funding obligations, which may adversely affect our liquidity and our ability to carry out our financial strategy. We rely on access to the bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. Market disruptions such as those experienced over the last threefour years in the United States and abroad may increase our cost of borrowing or adversely affect our ability to access sources of liquidity needed to finance our operations and satisfy our obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties we do business with, unprecedented volatility in the markets where our outstanding securities trade, and general economic downturns in our utility service territories. If we are unable to access credit at competitive rates, or if our borrowing costs dramatically increase, our ability to finance our operations, meet our short-term obligations, and execute our financial strategy could be adversely affected. Changing market conditions could negatively affect the market value of assets held in our pension and other postretirement pensionretiree plans and may increase the amount and accelerate the timing of required future funding contributions. UniSourceUNS Energy’s net income and cash flows can be adversely affected by rising interest rates. As of February 15, 2011,13, 2013, TEP had $365$215 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a fixed for floatingfixed-for-floating interest rate swap through September 2014. The interest rates are set weekly with maximum interest rates of 20% on $329$178 million of debt obligations and 10% on the remaining $36$37 million. The average weekly interest rate ranged from 0.17%0.06% to 0.39%0.26% in 2010.2012. A 1%100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $3$2 million. UniSourceUNS Energy, TEP, UNS Gas, and UNS Electric also are subject to risk resulting from changes in the interest rate on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on a spread over LIBORLondon Interbank Offer Rate (LIBOR) or an Alternate Base Rate. Each of these agreements is a committed facility and expires in November 2014. UED is also subject to risk from changes in the interest rate on its term loan maturing in March 2012. 2016.If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would negatively impact UniSource Energy, TEP, UNS GasEnergy’s, TEP’s, UNS Gas’, and UNS Electric’s results of operations, net income, and cash flows. K-25
TEP, UNS Gas, and UNS Electric may be required to post margin under their power and fuel supply agreements, which could negatively impact their liquidity. TEP, UNS Gas, and UNS Electric secure power and fuel supply resources to serve their respective retail customers. The agreements under which TEP, UNS Gas and UNS Electricwe contract for such resources include requirements to post credit enhancement in the form of cash or letters of credit (LOCs) under certain circumstances, including changes in market prices which affect contract values, or a change in creditworthiness of the respective companies. In order to post such credit enhancement, TEP, UNS Gas, and UNS Electric would have to use available cash, draw under their revolving credit agreements, or issue letters of creditLOCs under their revolving credit agreements. The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 15, 2011,13, 2013, TEP had $164$169 million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may use under their revolving credit facilityborrow is $70 million, so long as the combined amount drawn by both companies does not exceed $100 million.million (the size of their combined borrowing capacity under the revolving credit facility). As of February 15, 2011,13, 2013, UNS Gas had $70 million and UNS Electric had $70 million, and $57 million, respectively,available to borrow under their revolving credit facility. From time to time, TEP, UNS Gas, and UNS Electric use their respective revolving credit facilities to post collateral. If additional collateral is required, it may negatively impact TEP, UNS Gas, and/or UNS Electric’s ability to fund their capital requirements. As of December 31, 2010,2012, TEP UNS Gas and UNS Electric each had posted less than $1 million $3 million, and $13 million, respectively, with counterparties in the form of cash or letters of credit. UniSourceLOCs.UNS Energy and its subsidiaries have substantial debt which could adversely affect their business and results of operations. UniSourceUNS Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 2010,2012, the ratio of total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UniSourceUNS Energy and its subsidiaries was 69%63%. This substantial debt level: requires UniSourceUNS Energy and its subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on their debt, which could reduce the funds available for working capital, capital expenditures, acquisitions, and other general corporate purposes; and could limit UniSourceUNS Energy and its subsidiaries’ ability to borrow additional amounts for working capital, capital expenditures, acquisitions, dividends, debt service requirements, execution of its business strategy, or other purposes. The cost of purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power in 2015, could require significant outlays of cash in one year, which could be difficult to finance. TEP leases the following generation facilities under separate sale and leaseback arrangements that expire in 2015: | | | | | Leased Asset | | Expiration | | Purchase Option | Leased Asset | | Expiration | | Purchase Option | Springerville Unit 1 | | 2015 | | Fair market value purchase option of $159 million | Springerville Coal Handling Facilities | | 2015 | | Fixed price purchase option of $120 million |
TEP may renew the leases or purchase the assets when the leases expire in 2015. The renewal and purchase options for Springerville Unit 1 are generally for fair market value, aswith the fair market value purchase price having been determined atin December 2011 through an appraisal process to be $159 million. The owner participants of Springerville Unit 1 have disputed the appraisal price; however, TEP believes that time. the appraisal procedure was properly conducted in accordance with the lease agreements and that the results are final and binding. The Springerville Coal Handling Facilities can be purchased in 2015 for a fixed price of $120 million. TEP also leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending in 2017 and 2021. Upon expiration of the Springerville Coal Handling and Common Facilities Leases (whether at the end of the initial term or any renewal term), TEP has the obligation under agreements with the owners of Springerville Units 3 and 4 to purchase such facilities. Upon acquisition by TEP, the ownersowner of Springerville Unit 3 havehas the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities and a 17% interest in the Coal Handling Facilities. K-26
Regulatory rules and other restrictions could limit the ability of TEP, UNS Gas, and UNS Electric to make distributions to UniSourceUNS Energy. As a holding company, UniSourceUNS Energy is dependent on the earnings and distributions of funds from its subsidiaries to service its debt and pay dividends to shareholders. TEP, UNS Gas, and UNS Electric are restricted from lending or transferring fundsto affiliates or issuing securities without ACC approval; The Federal Power Act restrictsstates that an electric utilities’ ability to payutility’s dividends shall not be paid out of funds that are properly included in their capital account.accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe there is a reasonable basis for TEP to pay dividends from current year earnings. However, the FERC could attempt to stop TEP from paying further dividends or could seek to impose additional restrictions on the payment of dividends;earnings; and TEP, UNS Gas, and UNS Electric must be in compliance with their respective debt agreements to make dividend payments to UniSourceUNS Energy. Unanticipated financing needs or reductions to net income could adversely impact our ability to comply with financial covenants in the UniSourceUNS Energy, TEP, and TEPUES Credit Agreements. The UniSourceUNS Energy, TEP, and UES credit and reimbursement agreements include a maximum leverage ratio. The leverage ratios are calculated as the ratio of total indebtedness to total capital. The ability to comply with these covenants could be adversely impacted by unanticipated borrowing needs or unexpected charges to earnings or shareholder equity. In the event that we seek to renegotiate these provisions to provide additional flexibility, we may need to pay fees or increased interest rates on borrowings as a condition to any amendments or waivers. The operation of electric generating stations involves risks that could result in unplanned outages or reduced generating capability that could adversely affect TEP’s or UNS Electric’s results of operations, net income, and cash flows. The operation of electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel supply, and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of our business. If TEP’s or UNS Electric’s generating stations operate below expectations, TEP or UNS Electric could be adversely affected. The operation of electric transmission and distribution systems involves a risk of significant unplanned outages that could adversely affect TEP’s and UNS Electric’s businesses, results of operations, net income, and cash flows. The operation of electric transmission and distribution systems involves certain risks, including equipment failure and damage caused by storms, fires, or other hazards. Unplanned outages occur from time to time and are an inherent risk of our business. If TEP’s or UNS Electric’s transmission and distribution systems experience a significant failure, TEP or UNS Electric could be adversely affected affected.The nature of our gas operations presents inherent risks of loss that could adversely affect our results of operations. The operation of UNS Gas’ transmission and distribution systems involves certain risks, including gas leaks, fires, natural disasters, catastrophic accidents, explosions, pipeline ruptures, and other hazards and risks that may cause unforeseen interruptions, personal injury, or property damage. Any such incident could have an adverse effect on UNS Gas. TEP could be subject to higher costs and the possibility of significant penalties as a result of mandatory transmission standards. As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject to mandatory transmission standards developed and enforced by NERC and subject to the oversight of FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties. K-27
As operators of critical energy infrastructure, we may face a heightened risk of cyber attack, and our corporate and informational technology systems may be vulnerable to disability or failures as a result of unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. In addition, our utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. If, despite our security measures, a significant or widely publicized breach occurred, we could have our operations disrupted, property damaged, and customer information stolen; experience substantial loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission lines and distribution-related facilities, and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers. TEP and UNS Electric rely on federal, state, and local governmental agencies to secure right-of-way and siting permits to construct transmission lines.lines and distribution-related facilities. If adequate right-of-way and siting permits to build new transmission lines cannot be secured: TEP and UNS Electric may need to rely on more costly alternatives to provide energy to their customers; TEP and UNS Electric may not be able to maintain reliability in their service areas; or TEP and UNS Electric’s ability to provide electric service to new customers may be negatively impacted. | | | ITEM 1B. | | — UNRESOLVED STAFF COMMENTS |
ITEM 1B. – UNRESOLVED STAFF COMMENTSNone. TEP PROPERTIES TEP’s transmission facilities, located in Arizona and New Mexico, transmit the output from TEP’s remote electric generating stations at Four Corners, Navajo, San Juan, Springerville, and Luna to the Tucson area for use by TEP’s retail customers (seeItem 1. Business, TEP, Generating and Other Resources). The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 130140 companies to interchange generation capacity and transmission of energy. As of December 31, 2010,2012, TEP owned or participated in an overhead electric transmission and distribution system consisting of: 512564 circuit-miles of 500-kV lines;
1,0871,088 circuit-miles of 345-kV lines;
379405 circuit-miles of 138-kV lines;
478481 circuit-miles of 46-kV lines; and
2,6212,612 circuit-miles of lower voltage primary lines.
TEP’s underground electric distribution system includes 4,3674,410 cable-miles. TEP owns approximately 76% of the poles on which its lower voltage lines are located. Electric substation capacity consistedconsists of 102103 substations with a total installed transformer capacity of 13,216,80513,269,950 kilovolt amperes. Substantially all of the utility assets owned by TEP are subject to the lien of the 1992 Mortgage. Springerville Unit 2, which is owned by San Carlos, Resources Inc., a wholly-owned subsidiary of TEP, (San Carlos), is not subject to the lien. The electric generating stations (except as noted below), operatingadministrative headquarters, warehouse and service center are located on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located: on property owned by TEP; under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, easements, or other rights which are generally subject to termination; under or over private property as a result of easements obtained primarily from the record holder of title; or over American Indian reservations under grant of easement by the Secretary of Interior or lease by American Indian tribes. It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired. K-28
Springerville is located on property ownedheld by TEP under a long-term surface ownership agreement with the stateState 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.Nation. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired land rights, easements and leases for the plant, transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP also has acquired easements for transmission facilities related to San Juan, Four Corners, and Navajo across the Zuni, Navajo, and Tohono O’odhamO’dham American Indian Reservations. TEP, in conjunction with PNM and Phelps Dodge,Freeport McMoRan, holds an undivided ownership interest in the property on which Luna is located. TEP’s rights under these various easements and leases may be subject to defects such as: possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) and the American Indian tribes; possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without Congressional consent; or failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants. These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities. TEP, under separate sale and leaseback arrangements, leases the following generation facilities (which do not include land): Springerville Coal Handling Facilities; a 50% undivided interest in the Springerville Common Facilities; and Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities. See Note 6and 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 As of December 31, 2010,2012, UNS Gas’ transmission and distribution system consisted of approximately 3031 miles of steel transmission mains, 4,2114,229 miles of steel and plastic distribution piping, and 136,439137,705 customer service lines. As of December 31, 2010,2012, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 271274 circuit-miles of 69-kV transmission lines, and 3,5993,648 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 6562 MW Valencia plant, the 90 MW BMGS, as well as 3940 substations having a total installed capacity of 1,788,0501,504,000 kilovolt amperes. The gas and electric distribution and transmission facilities owned by UNS Gas and UNS Electric are located: on property owned by UNS Gas or UNS Electric; under or over streets, alleys, highways, and other places in the public domain, as well as national forests and state lands, under franchises, easements, or other rights which are generally subject to termination; or under or over private property as a result of easements obtained primarily from the record holder of title. 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.
K-29
ITEM 3. – LEGAL PROCEEDINGS
UED PROPERTIES
As of December 31, 2010, UED owned a 90-MW gas-fired generation facility in Mohave County, known as BMGS. BMGS is located on property that is owned by UNS Electric and currently leased to UED. BMGS is subject to a lien to secure UED’s obligations under its term loan facility.
| | | ITEM 3 | | — LEGAL PROCEEDINGS |
Right of Way Matters TEP was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were requesting, among other things, that the transmission lines on these lands be removed. In June 2009, TEP and the other defendants filed motions to dismiss the lawsuit on procedural grounds. In March 2010, the Courtcourt granted several of the defendants’ motions to dismiss and entered a final judgment dismissing the case in April 2010. The plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (BIA)BIA in May 2010, appealing the BIA’s decision to grant the rights of way that were the subject of the now-dismissed complaint. In June 2010, the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. The appeals are currently pending. TEP cannot predict the outcome of these appeals. Sierra Club San Juan Allegations
Springerville Unit 1 Appraisal Springerville Unit 1 is leased by TEP under leases which expire in 2015 and which provide TEP with an option to purchase the lease interests upon the lease expiration at fair market value. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure with three appraisers in accordance with the lease agreements to determine the fair market value purchase price. The lease agreements provide that the purchase price determined through the appraisal procedure will be final and binding upon the parties. The aggregate purchase price for the owner participants’ lease interests was determined to be $159 million. On April 2010, the Sierra Club26, 2012, TEP filed a citizens suit underpetition to confirm the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA)appraisal in the U.S.United States District Court for the District of New Mexico against PNM, as operator of San Juan; PNM’s parent, PNM Resources,Arizona naming the owner participants (Daimler Capital Services LLC, LDVFI TEP LLC, Alterna Springerville LLC, MWR Capital Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent, BHP Minerals InternationalPacific Harbor Capital Inc. (BHP). The Sierra Club alleges in the suit that certain activities at San Juan) and the San Juan mine associatedowner trustee and co-trustee (Wilmington Trust Company and William J. Wade) as respondents. The petition states that TEP filed the petition since neither the owner participants nor the owner trustee and co-trustee have acknowledged that the purchase price determined by the appraisal procedure in December 2011 is final and binding and that TEP seeks an order from the court confirming the appraisal as an arbitration award under the Federal Arbitration Act (FAA). On June 1, 2012, the owner participants filed a response in opposition to TEP’s petition. In their response, the owner participants allege that the appraisal procedure failed to yield a legitimate purchase price for the lease interests, stating, among other things, that not all of the three appraisers performed their appraisals in accordance with required standards. The owner participants requested that the court dismiss the action and deny TEP’s petition on the grounds that there is not a present controversy for the court to decide, since, among other things, TEP has not exercised the purchase option. The owner participants also dispute TEP’s position that the appraisal procedure should be treated as an arbitration award for purposes of judicial review. In January 2013, the court denied TEP’s petition on the grounds that the court is without jurisdiction under the FAA to confirm the appraisal. On February 12, 2013, TEP appealed the matter to the United States Court of Appeals for the Ninth Circuit. TEP believes that the appraisal procedure was properly conducted in accordance with the treatment, storage and disposal of coal and CCRs — primarily coal ash — are causing imminent and substantial harm to the environment, including ground and surface waters in the region,lease agreements and that placement of CCRs at the mine constitute “open dumping” in violation of RCRA. The RCRA claimsresults are asserted against PNM, PNMR, SJCCfinal and BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP. The suit seeksbinding. TEP intends to continue vigorously pursuing its legal remedies to confirm the following relief: an injunction requiring the parties to either cease placement of CCRs at the mine or undertake certain mitigation measures with respect to their placement; the imposition of civil penalties; and, attorney’s fees and costs. The parties agreed to and the court entered a stayresults of the action on August 27, 2010 to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM plans an aggressive defense of the RCRA claims in the suit. TEP owns 50% of San Juan Units 1 and 2, which represent approximately 20% of the total generation capacity of the entire San Juan Generating Station, and is liable for its share of any resulting liabilities. TEP cannot predict the outcome of this matter at this time.
SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, for litigation related to ACC orders and retail competition.
appraisal procedure.In addition, see legal proceedings described in Note 4. | | | ITEM 4. | | — REMOVED AND RESERVED |
ITEM 4. – MINE SAFETY DISCLOSURES K-30Not applicable.
PART II | | | ITEM 5. | | — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF COMMON EQUITY |
ITEM 5. – MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF COMMON EQUITYStock Trading UniSourceUNS Energy’s common stockCommon Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 15, 2011,13, 2013, the closing price was $36.24,$46.42 with 8,7897,881 shareholders of record. TEP’s common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange. Dividends UniSourceUNS Energy UNS Energy’s Board of Directors expects to continue to pay regular quarterly cash dividends on our common stock subject;Common Stock; however, such dividends are subject to the Board’s evaluation of our financial condition, earnings, cash flows, and dividend policy. UniSourceOn February 25, 2013, UNS Energy isdeclared a first quarter cash dividend of $0.435 per share of Common Stock. The first quarter dividend, totaling approximately $18 million, will be paid March 25, 2013 to shareholders of record at the sole shareholderclose of TEP’s common stock andbusiness March 13, 2013. The table below summarizes UNS Energy’s dividends paid in 2010 through 2012. | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | Quarterly Dividend Per Common Share | | $ | 0.43 | | | $ | 0.42 | | | $ | 0.39 | | Annual Dividend Per Common Share | | $ | 1.72 | | | $ | 1.68 | | | $ | 1.56 | | Common Stock Dividends Paid | | $ | 70 million | | | $ | 62 million | | | $ | 57 million | |
UNS Energy relies on dividends from its subsidiaries, primarily TEP, to declare and pay dividends. TEP TEP paid $30 million of dividends to UNS Energy in 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010. TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of December 31, 2012, TEP was in compliance with the terms of the TEP Credit Agreement. The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP Boardhas an accumulated deficit rather than positive retained earnings. Although the terms of Directors typically declaresthe Federal Power Act are unclear, we believe that there is a dividend atreasonable basis for TEP to pay dividends from current year earnings. UNS Gas UNS Gas paid dividends to UNS Energy of $20 million in 2012, and $10 million in both 2011 and 2010. UNS Gas’ ability to pay future dividends will depend on the endcash needs for capital expenditures and various other factors. The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no default or event of each year. default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Gas was in compliance with the terms of its note purchase agreement.UNS Electric UNS Electric paid dividends to UNS Energy of $10 million in 2012. UNS Electric did not pay any dividends to UNS Energy in 2011 or 2010. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors. The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2012, UNS Electric was in compliance with the terms of its note purchase agreement. Other Non-Reportable Segments In 2012, Millennium paid dividends of $14 million to UNS Energy. In 2011 and 2010, Millennium paid dividends of $3 million and $8 million to UNS Energy, respectively. UED did not pay any dividends to UNS Energy in 2012. In 2011 and 2010 UED paid dividends to UNS Energy of $39 million and $9 million, respectively. Of those dividends paid by UED, the portions representing a return of capital were $28 million in 2011 and $4 million in 2010. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSourceUNS Energy Consolidated, Liquidity and Capital Resources, Dividends on Common StockStock. Common Stock Dividends and Price Ranges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | | | Market Price per | | | | | | | Market Price per | | | | | | | | Share of Common | | | | | | | Share of Common | | | | | | | | Stock(1) | | | Dividends | | | Stock(1) | | | Dividends | | | Quarter: | | High | | | Low | | | Declared | | | High | | | Low | | | Declared | | | | | | | | | | | | | | | | | | | | | | | | | | | | | First | | $ | 33.54 | | | $ | 29.13 | | | $ | 0.39 | | | $ | 29.97 | | | $ | 22.76 | | | $ | 0.29 | | | Second | | | 34.42 | | | | 29.04 | | | | 0.39 | | | | 28.76 | | | | 24.78 | | | | 0.29 | | | Third | | | 33.75 | | | | 29.85 | | | | 0.39 | | | | 31.11 | | | | 25.96 | | | | 0.29 | | | Fourth | | | 36.92 | | | | 33.19 | | | | 0.39 | | | | 33.11 | | | | 28.04 | | | | 0.29 | | | | | | | | | | | | | | | | | | | | | | | Total | | | | | | | | | | $ | 1.56 | | | | | | | | | | | $ | 1.16 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | Quarter: | | Market Price per | | | | | | Market Price per | | | | | | | | Share of Common | | | Dividends | | | Share of Common | | | Dividends | | | | | Stock(1) | | | Declared | | | Stock(1) | | | Declared | | | | | High | | | Low | | | | | | High | | | Low | | | | | First | | $ | 38.66 | | | $ | 36.31 | | | $ | 0.43 | | | $ | 37.74 | | | $ | 34.84 | | | $ | 0.42 | | Second | | | 38.86 | | | | 35.66 | | | | 0.43 | | | | 38.71 | | | | 35.47 | | | | 0.42 | | Third | | | 42.71 | | | | 39.08 | | | | 0.43 | | | | 38.55 | | | | 34.36 | | | | 0.42 | | Fourth | | | 43.56 | | | | 39.02 | | | | 0.43 | | | | 39.25 | | | | 34.28 | | | | 0.42 | | | | | | | | | | | | | | | | | | | | | | | �� | | | | Total | | | | | | | | | | $ | 1.72 | | | | | | | | | | | $ | 1.68 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1) | | UniSourceUNS Energy’s common stockCommon Stock price as reported by the New York Stock Exchange. |
On February 25, 2011, UniSource Energy declared a cash dividend of $0.42 per share on its common stock. The dividend will be paid March 23, 2011 to shareholders of record at the close of business on March 11, 2011.
TEP’s common stock is wholly-owned by UniSource Energy and is not listed for trading on any stock exchange. TEP declared and paid cash dividends to UniSource Energy of $60 million in 2010, $60 million in 2009 and $3 million in 2008.
In March 2005, UniSourceUNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. Each $1,000In 2012, holders of approximately $147 million of the Convertible Senior Notes is convertibleoutstanding converted their interests into 28.100approximately 4.3 million shares of our Common StockStock. The remaining $3 million of outstanding Convertible Senior Notes were redeemed at any time, representing a conversion price of approximately $35.59 per share of our Common Stock, subject to adjustment in certain circumstances.par for cash. SeeItem 7. —7.- Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSourceUNS Energy Consolidated, Liquidity and Capital Resources, UniSource Energy Consolidated Cash Flows, Financing Activities.Convertible Senior Notes, below, for more information.Issuer Purchases of Common Equity UniSourceUNS Energy did not purchase any shares of its common stockCommon Stock during 2010, 2009,2012, 2011, or 2008. ITEM 6. – SELECTED CONSOLIDATED FINANCIAL DATA UNS Energy K-31
| | | | | | | | | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | | | - In Thousands - (Except per Share Data) | | Summary of Operations (1) | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | $ | 1,461,766 | | | $ | 1,478,702 | | | $ | 1,425,947 | | | $ | 1,396,606 | | | $ | 1,410,407 | | | | | | | | Net Income | | $ | 90,919 | | | $ | 109,975 | | | $ | 112,984 | | | $ | 105,901 | | | $ | 16,955 | | | | | | | | Basic Earnings per Share: | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 2.25 | | | $ | 2.98 | | | $ | 3.10 | | | $ | 2.95 | | | $ | 0.47 | | | | | | | | Diluted Earnings per Share: | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 2.20 | | | $ | 2.75 | | | $ | 2.86 | | | $ | 2.73 | | | $ | 0.53 | | | | | | | | Shares of Common Stock Outstanding: | | | | | | | | | | | | | | | | | | | | | Weighted Average | | | 40,362 | | | | 36,962 | | | | 36,415 | | | | 35,858 | | | | 35,632 | | End of Year | | | 41,344 | | | | 36,918 | | | | 36,542 | | | | 35,851 | | | | 35,458 | | | | | | | | Year-end Book Value per Share | | $ | 25.77 | | | $ | 24.07 | | | $ | 22.73 | | | $ | 21.18 | | | $ | 19.35 | | Cash Dividends Declared per Share | | $ | 1.72 | | | $ | 1.68 | | | $ | 1.56 | | | $ | 1.16 | | | $ | 0.96 | | | | | | | | | | | | | | | | | | | | | | | Financial Position | | | | | | | | | | | | | | | | | | | | | Total Utility Plant – Net | | $ | 3,300,363 | | | $ | 3,182,263 | | | $ | 2,961,498 | | | $ | 2,785,714 | | | $ | 2,617,693 | | Total Investments in Lease Debt and Equity | | $ | 45,457 | | | $ | 65,829 | | | $ | 103,844 | | | $ | 132,168 | | | $ | 126,672 | | Other Investments and Other Property | | $ | 36,537 | | | $ | 34,205 | | | $ | 61,676 | | | $ | 60,239 | | | $ | 64,096 | | Total Assets | | $ | 4,140,429 | | | $ | 3,989,279 | | | $ | 3,796,246 | | | $ | 3,615,211 | | | $ | 3,510,608 | | | | | | | | Long-Term Debt | | $ | 1,498,442 | | | $ | 1,517,373 | | | $ | 1,352,977 | | | $ | 1,307,795 | | | $ | 1,313,615 | | Non-Current Capital Lease Obligations | | | 262,138 | | | | 352,720 | | | | 429,074 | | | | 488,349 | | | | 513,517 | | Common Stock Equity | | | 1,065,465 | | | | 888,474 | | | | 830,756 | | | | 759,329 | | | | 686,090 | | | | | | | | | | | | | | | | | | | | | | | Total Capitalization | | $ | 2,826,045 | | | $ | 2,758,567 | | | $ | 2,612,807 | | | $ | 2,555,473 | | | $ | 2,513,222 | | | | | | | | | | | | | | | | | | | | | | | Selected Cash Flow Data | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Operating Activities | | $ | 348,109 | | | $ | 337,320 | | | $ | 346,920 | | | $ | 347,310 | | | $ | 273,767 | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | $ | (307,277 | ) | | $ | (374,122 | ) | | $ | (330,629 | ) | | $ | (294,020 | ) | | $ | (354,080 | ) | Other Investing Cash Flows(2) | | | 44,378 | | | | 47,034 | | | | 25,569 | | | | (2,624 | ) | | | (95,493 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Investing Activities | | $ | (262,899 | ) | | $ | (327,088 | ) | | $ | (305,060 | ) | | $ | (296,644 | ) | | $ | (449,573 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Financing Activities | | $ | (37,682 | ) | | $ | (1,441 | ) | | $ | (51,183 | ) | | $ | (28,916 | ) | | $ | 140,605 | | | | | | | | | | | | | | | | | | | | | | | Ratio of Earnings to Fixed Charges(3) | | | 2.32 | | | | 2.46 | | | | 2.64 | | | | 2.48 | | | | 1.28 | | | | | | | | | | | | | | | | | | | | | | |
TEP | | | | | | | | | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | | | -Thousands of Dollars- | | Summary of Operations | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | $ | 1,161,660 | | | $ | 1,156,386 | | | $ | 1,125,267 | | | $ | 1,099,338 | | | $ | 1,092,148 | | Net Income | | $ | 65,470 | | | $ | 85,334 | | | $ | 108,260 | | | $ | 90,688 | | | $ | 7,206 | | | | | | | | | | | | | | | | | | | | | | | Financial Position | | | | | | | | | | | | | | | | | | | | | Total Utility Plant – Net | | $ | 2,750,421 | | | $ | 2,650,652 | | | $ | 2,410,077 | | | $ | 2,261,325 | | | $ | 2,120,619 | | Total Investments in Lease Debt and Equity | | | 45,457 | | | | 65,829 | | | | 103,844 | | | | 132,168 | | | | 126,672 | | Other Investments and Other Property | | | 35,091 | | | | 32,313 | | | | 43,588 | | | | 31,813 | | | | 31,291 | | Total Assets | | $ | 3,461,046 | | | $ | 3,277,661 | | | $ | 3,078,411 | | | $ | 2,924,108 | | | $ | 2,852,195 | | | | | | | | Long-Term Debt | | $ | 1,223,442 | | | $ | 1,080,373 | | | $ | 1,003,615 | | | $ | 903,615 | | | $ | 903,615 | | Non-Current Capital Lease Obligations | | | 262,138 | | | | 352,720 | | | | 429,074 | | | | 488,311 | | | | 513,370 | | Common Stock Equity | | | 860,927 | | | | 824,943 | | | | 709,884 | | | | 650,591 | | | | 589,613 | | | | | | | | | | | | | | | | | | | | | | | Total Capitalization | | $ | 2,346,507 | | | $ | 2,258,036 | | | $ | 2,142,573 | | | $ | 2,042,517 | | | $ | 2,006,598 | | | | | | | | | | | | | | | | | | | | | | | Selected Cash Flow Data | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Operating Activities | | $ | 267,919 | | | $ | 268,294 | | | $ | 302,483 | | | $ | 268,064 | | | $ | 265,756 | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | $ | (252,782 | ) | | $ | (351,890 | ) | | $ | (277,309 | ) | | $ | (240,079 | ) | | $ | (291,990 | ) | Other Investing Cash Flows(2) | | | 24,901 | | | | 39,879 | | | | 24,273 | | | | (9,522 | ) | | | (95,814 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Investing Activities | | $ | (227,881 | ) | | $ | (312,011 | ) | | $ | (253,036 | ) | | $ | (249,601 | ) | | $ | (387,804 | ) | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Financing Activities | | $ | 11,987 | | | $ | 51,452 | | | $ | (51,882 | ) | | $ | (29,320 | ) | | $ | 128,713 | | | | | | | | | | | | | | | | | | | | | | | Ratio of Earnings to Fixed Charges(3) | | | 2.12 | | | | 2.42 | | | | 2.76 | | | | 2.58 | | | | 1.18 | | | | | | | | | | | | | | | | | | | | | | |
| (1) | | | ITEM 6. | | — SELECTED CONSOLIDATED FINANCIAL DATASee Note 1 for revisions to prior period financial statements. |
UniSource Energy
| | | | | | | | | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | | | - In Thousands - | | | | | (except per share data) | | Summary of Operations | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | $ | 1,453,677 | | | $ | 1,396,701 | | | $ | 1,410,066 | | | $ | 1,381,373 | | | $ | 1,308,141 | | | Income Before Discontinued Operations | | $ | 111,477 | | | $ | 104,258 | | | $ | 14,021 | | | $ | 58,373 | | | $ | 69,243 | | Net Income(1) | | $ | 111,477 | | | $ | 104,258 | | | $ | 14,021 | | | $ | 58,373 | | | $ | 67,447 | | | | | | | | | | | | | | | | | | | | | | | | | Basic Earnings per Share: | | | | | | | | | | | | | | | | | | | | | | Before Discontinued Operations | | $ | 3.06 | | | $ | 2.91 | | | $ | 0.39 | | | $ | 1.64 | | | $ | 1.96 | | | Net Income | | $ | 3.06 | | | $ | 2.91 | | | $ | 0.39 | | | $ | 1.64 | | | $ | 1.91 | | | | | | | | | | | | | | | | | | | | | | | | | Diluted Earnings per Share: | | | | | | | | | | | | | | | | | | | | | | Before Discontinued Operations | | $ | 2.82 | | | $ | 2.69 | | | $ | 0.39 | | | $ | 1.57 | | | $ | 1.85 | | | Net Income | | $ | 2.82 | | | $ | 2.69 | | | $ | 0.39 | | | $ | 1.57 | | | $ | 1.80 | | | | | | | | | | | | | | | | | | | | | | | | | Shares of Common Stock Outstanding | | | | | | | | | | | | | | | | | | | | | | Average | | | 36,415 | | | | 35,858 | | | | 35,632 | | | | 35,486 | | | | 35,264 | | | End of Year | | | 36,542 | | | | 35,851 | | | | 35,458 | | | | 35,315 | | | | 35,190 | | | | | | | | | | | | | | | | | | | | | | | | | Year-end Book Value per Share | | $ | 22.46 | | | $ | 20.94 | | | $ | 19.16 | | | $ | 19.54 | | | $ | 18.59 | | | Cash Dividends Declared per Share | | $ | 1.56 | | | $ | 1.16 | | | $ | 0.96 | | | $ | 0.90 | | | $ | 0.84 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Financial Position | | | | | | | | | | | | | | | | | | | | | | Total Utility Plant — Net | | $ | 2,961,498 | | | $ | 2,785,714 | | | $ | 2,617,693 | | | $ | 2,407,295 | | | $ | 2,259,620 | | | Investments in Lease Debt and Equity | | | 105,277 | | | | 132,168 | | | | 126,672 | | | | 152,544 | | | | 181,222 | | | Other Investments and Other Property | | | 61,676 | | | | 60,239 | | | | 64,096 | | | | 70,677 | | | | 66,194 | | | Total Assets | | $ | 3,779,323 | | | $ | 3,601,242 | | | $ | 3,496,847 | | | $ | 3,185,716 | | | $ | 3,187,409 | | | | | | | | | | | | | | | | | | | | | | | | | Long-Term Debt | | $ | 1,352,977 | | | $ | 1,307,795 | | | $ | 1,313,615 | | | $ | 993,870 | | | $ | 1,171,170 | | | Non-Current Capital Lease Obligations | | | 429,074 | | | | 488,349 | | | | 513,517 | | | | 530,973 | | | | 588,771 | | | Common Stock Equity | | | 820,786 | | | | 750,865 | | | | 679,274 | | | | 690,075 | | | | 654,149 | | | | | | | | | | | | | | | | | | | | Total Capitalization | | $ | 2,602,837 | | | $ | 2,547,009 | | | $ | 2,506,406 | | | $ | 2,214,918 | | | $ | 2,414,090 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Selected Cash Flow Data | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Operating Activities | | $ | 342,359 | | | $ | 343,197 | | | $ | 273,767 | | | $ | 320,642 | | | $ | 280,522 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | $ | (265,141 | ) | | $ | (282,991 | ) | | $ | (354,080 | ) | | $ | (243,242 | ) | | $ | (236,124 | ) | Other Investing Cash Flows(2) | | | (35,358 | ) | | | (9,540 | ) | | | (95,493 | ) | | | 27,961 | | | | (7,820 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Investing Activities | | $ | (300,499 | ) | | $ | (292,531 | ) | | $ | (449,573 | ) | | $ | (215,281 | ) | | $ | (243,944 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Financing Activities | | $ | (51,183 | ) | | $ | (28,916 | ) | | $ | 140,605 | | | $ | (119,229 | ) | | $ | (77,016 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Ratio of Earnings to Fixed Charges(3) | | | 2.64 | | | | 2.47 | | | | 1.24 | | | | 1.68 | | | | 1.73 | | | | | | | | | | | | | | | | | | |
| | | (1) | | Net Income includes an after-tax loss for discontinued operations of $2 million in 2006. | | | (2) | | Other Investing Cash Flowsin 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds. |
| | (3) | | For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount, interest on operating lease payments, and expense on indebtedness. | | SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations. K-32
ITEM 7. – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
TEP
| | | | | | | | | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | | | -Thousands of Dollars- | | | | | | | | | | | | | | | | | | | | | | | | Summary of Operations | | | | | | | | | | | | | | | | | | | | | | Operating Revenues | | $ | 1,124,979 | | | $ | 1,098,987 | | | $ | 1,091,809 | | | $ | 1,070,503 | | | $ | 988,994 | | | Net Income | | $ | 106,978 | | | $ | 89,248 | | | $ | 4,363 | | | $ | 53,456 | | | $ | 66,745 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Financial Position | | | | | | | | | | | | | | | | | | | | | | Total Utility Plant — Net | | $ | 2,410,077 | | | $ | 2,261,325 | | | $ | 2,120,619 | | | $ | 1,957,506 | | | $ | 1,887,387 | | | Investments in Lease Debt and Equity | | | 105,277 | | | | 132,168 | | | | 126,672 | | | | 152,544 | | | | 181,222 | | | Other Investments and Other Property | | | 43,588 | | | | 31,813 | | | | 31,291 | | | | 35,460 | | | | 30,161 | | | Total Assets | | $ | 3,066,108 | | | $ | 2,914,299 | | | $ | 2,841,771 | | | $ | 2,573,036 | | | $ | 2,623,063 | | | | | | | | | | | | | | | | | | | | | | | | | Long-Term Debt | | $ | 1,003,615 | | | $ | 903,615 | | | $ | 903,615 | | | $ | 682,870 | | | $ | 821,170 | | | Non-Current Capital Lease Obligations | | | 429,074 | | | | 488,311 | | | | 513,370 | | | | 530,714 | | | | 588,424 | | | Common Stock Equity | | | 701,155 | | | | 643,144 | | | | 583,606 | | | | 577,349 | | | | 554,714 | | | | | | | | | | | | | | | | | | | | Total Capitalization | | $ | 2,133,844 | | | $ | 2,035,070 | | | $ | 2,000,591 | | | $ | 1,790,933 | | | $ | 1,964,308 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Selected Cash Flow Data | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Operating Activities | | $ | 297,755 | | | $ | 264,548 | | | $ | 265,756 | | | $ | 262,714 | | | $ | 225,752 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | $ | (215,697 | ) | | $ | (231,969 | ) | | $ | (291,990 | ) | | $ | (161,141 | ) | | $ | (154,704 | ) | Other Investing Cash Flows(1) | | | (32,611 | ) | | | (14,116 | ) | | | (95,814 | ) | | | 25,414 | | | | (25,786 | ) | | | | | | | | | | | | | | | | | | | Net Cash Flows From Investing Activities | | $ | (248,308 | ) | | $ | (246,085 | ) | | $ | (387,804 | ) | | $ | (135,727 | ) | | $ | (180,490 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Cash Flows From Financing Activities | | $ | (51,882 | ) | | $ | (29,320 | ) | | $ | 128,713 | | | $ | (120,088 | ) | | $ | (78,984 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Ratio of Earnings to Fixed Charges(2) | | | 2.76 | | | | 2.58 | | | | 1.13 | | | | 1.75 | | | | 1.84 | | | | | | | | | | | | | | | | | | |
| | | (1) | | Other Investing Cash Flowsin 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds. | | (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. | | SeeItem 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
K-33
| | | 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 UniSourceUNS Energy and its fourthree primary business segments and includes the following: operating results during 20102012 compared with 2009,2011, and 20092011 compared with 2008;2010; factors which affect our results and outlook; liquidity, capital needs, capital resources, and contractual obligations; critical accounting policies. UniSourceUNS Energy is a utility services holding company with no significant operations of its own. Operations are conducted byengaged, through its subsidiaries, eachin the electric generation and energy delivery business. Each of whichUNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UniSourceUNS Energy owns the outstanding common stock100% of TEP,Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED). TEP is a regulated public utility and Millennium Energy Holdings, Inc. (Millennium). UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of December 31, 2012. TEP angenerates, transmits and distributes electricity to approximately 406,000 retail electric utility, provides electric servicecustomers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the Tucson metropolitan area. western U.S. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).UES through its two operating subsidiaries,holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides. UNS Gas is a regulated gas distribution company with approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and electric service to 30 communitiesNavajo counties in northern andArizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated vertically integrated public utility with approximately 92,000 retail customers in Mohave and Santa Cruz counties.UED developed and owns the Black Mountain Generating Station (BMGS), a gas turbine project in northwestern Arizona that providesArizona. The facility includes two natural gas-fired combustion turbines. Prior to July 2011, UNS Electric received energy to UNS Electricfrom BMGS through a power sales agreement. Millennium has existingagreement with UED. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no impact on UNS Energy’s consolidated financial statements.Millennium’s investments in unregulated businesses that representedrepresent less than 1% of UniSourceUNS Energy’s total assets as of December 31, 2010; no new investments are planned in Millennium. Southwest Energy Solutions (SES), a subsidiary2012. Our business is comprised of Millennium, provides supplemental labor and meter reading services tothree reporting segments – TEP, UNS Gas, and UNS Electric. References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
UNISOURCEUNS ENERGY CONSOLIDATED
OUTLOOK AND STRATEGIES Our financial prospects and outlook for the next few years will beare affected by many factors including: the outcome of TEP’s 2008 Rate Order which freezes base rates through 2012;pending rate proceeding before the weakACC; national, regional, and regionallocal economic conditions; volatility in the financial markets; the increasing number of environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following: Focusing on our core utility businesses including:through operational excellence;excellence, investing in utility rate base;base, emphasizing customer satisfaction;satisfaction, and maintaining a strong community presence; andpresence. Strengthening the underlying financial condition of our utility subsidiaries by achieving constructive regulatory outcomes. Expanding TEPoutcomes, evaluating our capital structure, improving our credit ratings, and UNS Electric’s portfolio of renewable energy sources and programs to meet Arizona’s Renewable Energy Standards while creating ownership opportunities for renewable energy projects that benefit customers, shareholders and the communities we serve.
Developing strategic responses to energy efficiency requirements that protect the financial stability ofpromoting economic development in our utility businesses and provide benefits to our customers.service territories.
Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP’s existing mix of generation resources and defining steps to achieve environmental objectives that provide an appropriate return on investment and are consistent with earnings growth. K-34Developing a long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.
Expanding TEP’s and UNS Electric’s portfolio of renewable energy resources and programs to meet Arizona’s Renewable Energy Standard (RES) while creating ownership opportunities for renewable energy projects that benefit customers, shareholders, and the communities we serve.Developing strategic responses to Arizona’s Energy Efficiency Standards that protect the financial stability of our utility businesses and provide benefits to our customers. RESULTS OF OPERATIONS Contribution by Business Segment We conduct our business through fourthree primary business segments —– TEP, UNS Gas, and UNS Electric and Millennium.Electric. The table below shows the contributions to our consolidated after-tax earnings by these business segments. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | TEP | | $ | 107 | | | $ | 89 | | | $ | 4 | | | UNS Gas | | | 9 | | | | 7 | | | | 9 | | | UNS Electric | | | 10 | | | | 6 | | | | 4 | | | Millennium | | | (13 | ) | | | 2 | | | | — | | Other Non-Reportable Segments(1) | | | (2 | ) | | | — | | | | (3 | ) | | | | | | | | | | | | | Consolidated Net Income | | $ | 111 | | | $ | 104 | | | $ | 14 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | TEP | | $ | 65 | | | $ | 85 | | | $ | 108 | | UNS Gas | | | 9 | | | | 10 | | | | 9 | | UNS Electric | | | 17 | | | | 18 | | | | 15 | | Other Non-Reportable Segments and Adjustments(1) | | | — | | | | (3 | ) | | | (19 | ) | | | | | | | | | | | | | | Consolidated Net Income | | $ | 91 | | | $ | 110 | | | $ | 113 | | | | | | | | | | | | | | |
| | | | (1) | | Includes: UniSourceUNS Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on UniSource Energy Convertible Senior Notesexpenses, Millennium, and on the Unisource Credit Agreement; and UED. |
Revision for Prior Period Financial Statements In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012, as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011, and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 1. Executive Overview 20102012 Compared with 20092011
UniSource Energy’s net income in 2010 was $111 million compared with $104 million in 2009. The primary factors that contributed to the increase are described below by business segment.
TEP reported net income of $107$65 million in 20102012 compared with net income of $89$85 million in 2009.2011. The increasedecrease in net income was due primarily to: a $17 million decrease in retail kWh sales and margin revenues due in part to fewer Cooling Degree Days during the summer months compared with 2011, as well as the effects of the ACC’s energy efficiency and distributed generation requirements; a decrease in long-term wholesale margin revenues related to a change in the price of energy sold under TEP’s largest wholesale sales contract; higher depreciation and amortization expense resulting from a changedue to an increase in depreciation rates for TEP’s transmission assets, the purchase of Sundt Unit 4plant-in-service; and a declinepartial write-off of transmission-related assets. These factors were partially offset by a decrease in amortization on capital lease obligations. The decrease excludes adjustments made to depreciation and amortizationTEP’s Base O&M, resulting primarily from fewer planned generating plant outages. Net income in 2009 related to an investment in Springerville Unit 1 lease equity; operating benefits2011 included the recognition of $11 milliona gain related to the startsettlement of commercial operation of Springerville Unit 4 in December 2009;
a $3 million decrease in base operating and maintenance expense (Base O&M) resulting from a decline in planned power plant maintenance outages, cost-containment efforts and lower pension and post retirement medical expense. Base O&M excludes third-party expense reimbursements and expenses related to customer-funded renewable energy and demand-side management programs; partially offset by a $5 million decrease in TEP’s retail margin revenues resulting from a 0.8% decrease in retail kWh sales. TEP’s retail kWh sales were negatively impacted by weak economic conditions and a decline in cooling degree days compareddispute with 2009.
El Paso Electric. SeeTucson Electric Power, Company, Results of Operations,below, for more information; information.UNS Gas and UNS Electric UNS Gas reported net income of $9 million in 2012 compared with net income of $10 million in 2011. SeeUNS Gas, Results of Operations,below, for more information. UNS Electric reported net income of $17 million in 2012 compared with net income of $18 million in 2011. SeeUNS Electric, Results of Operations,below, for more information. Other Non-Reportable Segments Millennium’s financial results are included in UNS Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in both 2012 and 2011. SeeOther Non-Reportable Segments, Results of Operations,below, for more information. 2011 Compared with 2010 TEP TEP reported net income of $85 million in 2011 compared with $108 million in 2010. The decrease in net income was due primarily to: a decline in long-term wholesale margin revenues due to a change in the price of energy sold under TEP’s largest wholesale sales contract; a decrease in wholesale transmission revenues due in part to a temporary increase in wholesale transmission revenues in 2010; an increase in Base O&M due in part to an increase in planned generating plant outages; higher depreciation expense related to an increase in plant-in-service; and an increase in interest expense. Those factors were partially offset by the recognition of a gain in 2011 related to the settlement of a dispute with El Paso Electric. SeeTucson Electric Power, Results of Operations,below, for more information. UNS Gas and UNS Electric UNS Gas reported combined net income of $19$10 million in 20102011 compared with $13net income of $9 million in 2009.2010. SeeUNS Gas, Results of Operations,below, for more information. UNS Electric reported net income of $18 million in 2011 compared with net income of $15 million in 2010. The increase wasis due primarily to: | • | | a $4 million increase in net income at UNS Electric resulting from an increase in demand from a mining customer, the addition of a new industrial customer, an increase in base retail rates that took effect in October 2010, and a pre-tax gain of $3 million related to the settlement of a dispute regarding wholesale energy transactions; and | | | • | | a $2 million increase in net income at UNS Gas resulting from increased sales due to colder winter weatherin part to a Base Rate increase that took effect in October 2010. SeeUNS Electric, Results of Operations,below, for more information.Other Non-Reportable Segments Millennium’s financial results are included in UNS Energy’s Other Non-Reportable Segments. Millennium reported net income of $2 million in 2011 compared with 2009 and an increase in base retail rates that took effect in April 2010. |
K-35
Millennium
Millennium recorded a net loss of $13 million in 2010. Millennium’s results in the 2010 compared with net income of $2 million in 2009. The net loss in 2010 resulted from several factors, includingreflect losses related to the write-off of deferred tax assetstaxes and impairment losses on certain investments. Millennium’s results in 2009 included a $6 million pre-tax gain on the salelosses. SeeOther Non-Reportable Segments, Results of an investment.
2009 Compared with 2008
UniSource Energy’s net income in 2009 was $104 million compared with net income of $14 million in 2008. The primary factors that contributed to the increase are described Operations,below, by business segment.
TEP
TEP reported net income of $89 million in 2009 compared with net income of $4 million in 2008. The increase was due primarily to:
a 6% base rate increase at TEP that took effect December 1, 2009. The base rate increase, as well as hot summer weather, contributed to a $40 million increase in retail revenues during 2009. The increase excludes revenues collected from customers for renewable energy and energy efficiency programs;
a $31 million decrease in total fuel and purchased energy expense (net of short-term wholesale revenues) due to lower wholesale prices; and
$50 million of regulatory expenses, revenue deferrals and accounting adjustments in 2008 that did not recur in 2009.
Millennium
Millennium recorded net income of $2 million in 2009 and recorded no net income or loss in 2008. Millennium’s results in 2009 included a $6 million pre-tax gain on the sale of an investment.
The table below summarizes the items included in UniSourceUNS Energy’s O&MOperations and Maintenance (O&M) expense. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | TEP Base O&M (Non-GAAP) (1) | | $ | 228 | | | $ | 231 | | | $ | 220 | | UNS Gas Base O&M (Non-GAAP) (1) | | | 25 | | | | 25 | | | | 25 | | UNS Electric Base O&M (Non-GAAP) (1) | | | 21 | | | | 21 | | | | 21 | | Consolidating Adjustments and Other(2) | | | (9 | ) | | | (7 | ) | | | (8 | ) | | | | | | | | | | | | | UniSource Energy Base O&M (Non-GAAP) | | | 265 | | | | 270 | | | | 258 | | | Reimbursed Expenses Related to Springerville Units 3 and 4 | | | 65 | | | | 41 | | | | 35 | | Gain on the Sale of SO2 Emissions Allowances | | | — | | | | — | | | | (1 | ) | Expenses Related to Customer-funded Renewable Energy and Demand-side Management Programs(3) | | | 40 | | | | 23 | | | | 5 | | | Reinstatement of Regulatory Accounting | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | UniSource Energy Other O&M (GAAP) | | $ | 370 | | | $ | 334 | | | $ | 296 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | UNS Energy Base O&M (non-GAAP) (1) | | $ | 266 | | | $ | 271 | | | $ | 265 | | Reimbursed Expenses Related to Springerville Units 3 & 4 | | | 72 | | | | 63 | | | | 65 | | Expenses Related to Customer-Funded Renewable Energy and Demand Side Management Programs | | | 46 | | | | 45 | | | | 40 | | | | | | | | | | | | | | | Total UNS Energy O&M (GAAP) (2) | | $ | 384 | | | $ | 379 | | | $ | 370 | | | | | | | | | | | | | | |
| | | | (1) | | Base O&M, a Non-GAAPnon-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. TEP believes thatgenerally accepted accounting principles (GAAP). We believe Base O&M which is Other O&M less reimbursed expenses, gains on the sale of SO2 Allowances and expenses related to customer-funded renewable energy and demand-side management programs, provides useful information to investors.investors because it represents the fundamental level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties. |
| | (2) | | Includes Millennium, UED, and parent companyUNS Energy stand-alone O&M, and inter-company eliminations | | (3) | | Represents expenses related to customer-funded renewable energy programs; the offsetting funds collected from customers are recorded in retail revenue.eliminations. |
K-36
LIQUIDITY AND CAPITAL RESOURCES TheDividends from UNS Energy’s subsidiaries represent the parent company’s primary source of liquidity for UniSource Energy, the parent company, is dividends from its subsidiaries, primarily TEP. Also, under UniSourceliquidity. Under UNS Energy’s tax sharing agreement, subsidiaries make income tax payments to UniSourceUNS Energy, which makes payments on behalf of the consolidated group. group to taxing authorities. SeeIncome Tax Position,below, for more information. The table below provides a summary of the liquidity position of UniSourceUNS Energy on a stand-alone basis and each of its segments. | | | | | | | | | | | | | | | | | | | | | Borrowings | | | Amount Available | | | Balances As of | | Cash and Cash | | | under Revolving | | | under Revolving | | | February 15, 2011 | | Equivalents | | | Credit Facility(3) | | | Credit Facility | | | | | -Millions of Dollars- | | | UniSource Energy stand-alone | | $ | 1 | | | $ | 31 | | | $ | 94 | | | TEP | | | 36 | | | | 36 | | | | 164 | | | UNS Gas | | | 39 | | | | — | | | | 70 | (1) | | UNS Electric | | | 16 | | | | 13 | | | | 57 | (1) | | Millennium | | | 3 | | | | N/A | | | | N/A | | Other(2) | | | 3 | | | | N/A | | | | N/A | | | | | | | | | | | | | | Total | | $ | 98 | | | | | | | | | | | | | | | | | | | | | | |
segments: | | | | | | | | | | | | | | Balances as of February 13, 2013 | | Cash and Cash
Equivalents | | | Borrowings under
Revolving Credit
Facility(1) | | | Amount Available
under Revolving
Credit Facility | | | | | -Millions of Dollars- | | UNS Energy Stand-Alone | | $ | 1 | | | $ | 45 | | | $ | 80 | | TEP | | | 44 | | | | 31 | | | | 169 | | UNS Gas | | | 43 | | | | — | | | | 70 | 2) | UNS Electric | | | 9 | | | | — | | | | 70 | (2) | Other | | | 4 | (3) | | | N/A | | | | N/A | | | | | | | | | | | | | | | Total | | $ | 101 | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1) | Includes Letters of Credit (LOCs) issued under revolving credit facilities. |
| (2) | Currently, eitherEither UNS Gas or UNS Electric may borrow up to a maximum of $70 million, butmillion; the total combined amount borrowed by both companies cannot exceed $100 million. |
| (2)(3) | | Includes cash and cash equivalents at Millennium and UED. | | (3) | | Includes LOCs issued under Revolving Credit Facilities |
UniSourceUNS Energy’s short-term investment policy governs the investment of excess cash balances by UniSource Energybalances. We regularly review and its subsidiaries. We reviewupdate this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio.conditions. As of December 31, 2010, UniSource2012, UNS Energy’s short-term investments includeincluded highly-rated and liquid money market funds and certificates of deposit and commercial paper.deposit. These short-term investments are classified as Cash and Cash Equivalents on the Balance Sheet. Access to Revolving Credit Facilities UniSource Energy, TEP, UNS Gas and UNS Electric are each partyWe have access to aworking capital through revolving credit agreementagreements with a group of lenders that is available for working capital purposes.lenders. Each of these agreements is a committed facility andthat expires in November 2014.2016. The TEP and UNS Gas/UNS Electric Credit Agreements may be used for revolving borrowings as well as to issue letters of credit.LOCs. TEP, UNS Gas, and UNS Electric each issue letters of creditLOCs from time to time to provide credit enhancement to counterparties for their power or gasenergy procurement and hedging activities. The UniSource EnergyUNS Credit Agreement also may be used to issue letters of creditLOCs for general corporate purposes. UniSource Energy and its subsidiariesWe believe theythat we have sufficient liquidity under theirour revolving credit facilities to meet their short-term working capital needs and to provide credit enhancementsupport, as may be requirednecessary, under their respective energy procurement and hedging agreements. SeeItem 7A.Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below. Liquidity Outlook
In November 2010, UniSource Energy, TEP, UNS Gas and UNS Electric each refinanced their respective Credit Agreements that were due to expire in 2011. The expiration dates were extended to November 2014. UNS Gas has $50 million of unsecured notes that mature in August 2011.
K-37
UniSourceUNS Energy Consolidated Cash Flows
| | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Cash provided by (used in): | | | | | | | | | | | | | | Operating Activities | | $ | 342 | | | $ | 343 | | | $ | 274 | | | Investing Activities | | | (300 | ) | | | (293 | ) | | | (450 | ) | | Financing Activities | | | (51 | ) | | | (29 | ) | | | 141 | |
UniSource | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Operating Activities | | $ | 348 | | | $ | 337 | | | $ | 347 | | Investing Activities | | | (263 | ) | | | (327 | ) | | | (305 | ) | Financing Activities | | | (38 | ) | | | (1 | ) | | | (51 | ) |
UNS Energy’s consolidatedoperating cash flows are providedgenerated primarily fromby the retail and wholesale energy sales at TEP, UNS Gas, and UNS Electric, net of the related payments for fuel and purchased power.energy. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peakingsummer-peaking load. As a result of the varied seasonal cash flow, UniSourceUNS Energy, TEP, UNS Gas, and UNS Electric use their revolving credit facilities as needed to fund their business activities. Cash used for investing activities is primarily a result of capitalduring periods when sales are seasonally lower.Capital expenditures at TEP, UNS Gas, and UNS Electric. Electric represent the primary use of cash for investing activities. Cash used for investing and financing activities can fluctuate year-to-year depending on:on capital expenditures, repayments and borrowings under revolving credit facilities;facilities, debt issuances or retirements;retirements, capital lease payments by TEP;TEP, and dividends paid by UniSourceUNS Energy to its shareholders. In 2010,2012, net cash flows from operating activities were $1 million lower than 2009 primarily due to: a $14 million increase in income taxes paid due to higher pre-tax income;
a $20 million decrease in income tax refunds;
a $4 million increase in total interest paid; and
a $13 million decline in cash deposits received from power and gas trading counterparties; partially offset by
approximately $11 million ofhigher than they were in 2011. The following items impacted the year-over-year change in operating benefits due primarily to the start-up of Springerville Unit 4; and
a $41 millioncash flows: an increase in cash receipts from total electric and gas sales, net of fuel and purchased energy costs, due in part to lower purchased power costs at TEP and UNS Electric, and the collection of under-recovered fuel and purchased energy costs at TEP and UNS Gas; and a decrease in capital lease interest paid due to lower capital lease obligation balances.These increases in cash were partially relatedoffset by: a decrease in income tax refunds received due to overestimated payments made in 2010 and refunded in 2011; lower interest received due to lower balances in investments in lease debt; and an increase in property tax payments due to higher collections to fund renewable energyrates and energy efficiency programs. property values.Investing Activities Net cash flows used for investing activities was $7decreased by $64 million higher in 20102012. Capital expenditures during 2012 were $307 million compared with 2009. Investing activities$374 million in 2010 included:
the purchase of Sundt Unit 4 by TEP for $51 million;
an $18 million decline in2011. TEP’s capital expenditures resulting primarily from the effect of weakened economic conditions on customer growth;
a $13 million increase in the return of investment in Springerville Unit 1 lease debt; and
the purchase of renewable energy credits of $7 million by TEP and UNS Electric which is recovered through the RES surcharge.
Investing activities in 2009 included:
the use of $31 million by TEP for an investment in Springerville Unit 1 lease debt; and
the receipt of $82011 included $85 million related to the saleconstruction of an investment by Millennium.
a new administrative headquarters. K-38
Capital Expenditures Forecast | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Actual | | | | | | | | | | | Estimated | | | | | | | | | Business Segment | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | | | -Millions of Dollars- | | | TEP | | $ | 267 | | | $ | 306 | | | $ | 273 | | | $ | 372 | | | $ | 322 | | | $ | 286 | | | UNS Gas | | | 10 | | | | 12 | | | | 11 | | | | 14 | | | | 16 | | | | 22 | | | UNS Electric (1) | | | 22 | | | | 37 | | | | 51 | | | | 25 | | | | 30 | | | | 32 | | | Other Capital Expenditures | | | 17 | | | | 36 | | | | 1 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | $ | 316 | | | $ | 391 | | | $ | 336 | | | $ | 411 | | | $ | 368 | | | $ | 340 | | | | | | | | | | | | | | | | | | | | | |
| | | (1) | | UNS Electric is expected to purchase BMGS from UED for approximately $62 million during 2011. Since this is an inter-company transaction, it is not included in the chart, as it is eliminated from UniSource Energy consolidated capital expenditures. SeeUNS Electric,Factors Affecting Results of Operations, Rates, 2010 UNS Electric Rate Order,below, for more information. |
TEP’s capital expenditures in 2010 include $52 million for the purchase of Sundt Unit 4. | | | | | | | | | | | | | | | | | | | | | | | | | | | | Actual | | | Estimated | | | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | | | -Millions of Dollars- | | TEP | | $ | 253 | | | $ | 323 | | | $ | 296 | | | $ | 331 | | | $ | 287 | | | $ | 278 | | UNS Gas | | | 16 | | | | 12 | | | | 14 | | | | 14 | | | | 15 | | | | 17 | | UNS Electric | | | 38 | | | | 58 | | | | 29 | | | | 34 | | | | 31 | | | | 38 | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy Consolidated | | $ | 307 | | | $ | 393 | | | $ | 339 | | | $ | 379 | | | $ | 333 | | | $ | 333 | | | | | | | | | | | | | | | | | | | | | | | | | | |
TEP’s estimated capital expenditures in 2015 exclude the potential purchase of interests in Springerville Unit 1 for $159 million and the potential purchase of interests in the Springerville Coal Handling Facilities for $120 million upon the expiration of their respective leases in January 2015. OtherTEP’s estimated capital expenditures reflect UniSource Energy’s standaloneinclude approximately $25 million for TEP’s share of potential environmental expenditures related to the installation of SNCR at San Juan Unit 1. TEP estimates its share of capital expenditures including the purchasewould be approximately $200 million if SCR technology were to be installed at San Juan Units 1 and 2 instead of land and construction costsSNCR at San Juan Unit 1. SeeItem. 1 Business, TEP, Environmental Matters, Regional Haze Rules, San Juan, for a new corporate headquarters. more information.These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations and other factors. For more information regarding TEP’s capital expenditures, seeTucson Electric Power Company, Liquidity and Capital Resources, Investing Activities, Capital Expenditures,below. Net cash proceedsflows used for financing activities were $22$36 million higher in 2010 than they were2012 compared with 2011 due to a decrease in 2009 due to: $30 millionborrowings (net of netrepayments) under revolving credit facility repayments in 2010 compared with net proceeds of $5 million in 2009;
a $32 millionfacilities, an increase in scheduled payments ofon capital lease obligations;
$30 million of short-term debt proceeds in 2009 compared with none in 2010;obligations, and
a $15 million an increase in Common Stock dividends paid due to common shareholders;an increased number of shares outstanding from the conversion of the Convertible Senior Notes. These cash outflows were partially offset by
an $82 million increase in proceeds from the issuance of long-term debt net of repayments(net of long-term debt. debt repayments and issuance/retirement costs) at TEP.Capital Contributions UNS Energy made no capital contributions to its subsidiaries in 2012. In the first quarter of 2010, UED paid a $9 million dividend to UniSource Energy, of which $4 million represented a return of capital distribution. In March 2010, UniSourceJuly 2011, UNS Energy contributed $15$20 million in capital to UNS Electric to help fund its purchase of BMGS from UED. In December 2011, UNS Energy contributed $30 million in capital to TEP to help fund the purchase of Sundt Unit 4. TEP’s headquarters building.In 2009,2010, UED paid UNS Energy a $30$9 million dividend, to UniSource Energyof which also$4 million represented a return of capital distribution. UniSourceUNS Energy used the proceeds to contribute $30contributed $15 million ofin capital to TEP in 2010 to help fund the purchase lease debt related to Springervilleof Sundt Unit 1. 4.SeeOther Non-Reportable Business Segments, UEDandTucson Electric Power Company, Liquidity and Capital Resources, below, for more information. UniSourceUNS Credit Agreement In November 2010, UniSource Energy amended and restated its existing credit agreement (UniSource Credit Agreement). The UniSourceUNS Credit Agreement, had previously included a $30 million term loan facility and a $70 million revolving credit facility. As amended, the UniSource Credit Agreementwhich expires in November 2016, consists of a $125 million revolving credit and revolving letterLOC facility. As of credit facility. The UniSource Credit Agreement will expire in November 2014. At December 31, 2010,2012, there was $27$45 million outstanding at a weighted average interest rate of 3.26%1.96%. K-39
The UniSourceUNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UniSourceUNS Credit Agreement also requires UniSourceUNS Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSourceUNS Energy standalone basis and not tostand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UniSourceUNS Credit Agreement, UniSourceUNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED. As of December 31, 2010,2012, we were in compliance with the terms of the UniSourceUNS Credit Agreement. UniSourceUNS Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR and other benchmark interest rates increase, UniSourceUNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility.facility if the London Interbank Offered Rate (LIBOR) and other benchmark interest rates increase. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below. UniSourceIn March 2005, UNS Energy hasissued $150 million of 4.50% Convertible Senior Notes due in 2035. Each $1,000Between December 2011 and May 2012, UNS Energy issued a series of separate notices of partial redemption of the Convertible Senior Notes isby calling all $150 million outstanding. Holders of the called Convertible Senior Notes had the option of converting their interests to Common Stock or receiving the redemption price of par plus accrued interest for the Convertible Senior Notes. The notes were convertible into 28.100 shares of UniSource Energy Common Stock at any time, representing a conversion pricerate applicable at the time of each notice. During the first half of 2012, holders of approximately $35.59 per share of our Common Stock, subject to adjustments. The closing price of UniSource Energy’s Common Stock was $36.24 on February 15, 2011. Beginning on March 5, 2010, UniSource Energy has the option to redeem the notes, in whole or in part, for cash, at a price equal to 100%$147 million of the principal amount plus accrued and unpaid interest. HoldersConvertible Senior Notes outstanding converted their interests into approximately 4.3 million shares 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.Common Stock. The repurchase price will be 100% of the principal amount of the notes plus accrued and unpaid interest.
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 at December 31, 2010 were:
UES’ guarantee of senior unsecured notes issued by UNS Gas ($100 million) and UNS Electric ($100 million);
UES’ guarantee of the $100 million UNS Gas/UNS Electric Revolver;
UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas; and
UniSource Energy’s guarantee of the $30remaining $3 million of outstanding loans under the UED Credit Agreement.
To the extent liabilities exist under these contracts, such liabilities are included in the consolidated balance sheets.
In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4. TEP has indemnified the seller of Sundt Unit 4 from any sales, use, transfer or similar taxes or fees due relating to the purchase. The terms of the indemnification do not include a limit on potential future payments; however, TEP believes that the parties to the agreement have abided by all tax laws, and TEP does not have any additional tax obligations. TEP has not made any payments under the terms of this indemnification to date.
Convertible Senior Notes were redeemed for cash.Contractual Obligations The following chart displays UniSourceUNS Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2010. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy’s Contractual Obligations - Millions of Dollars - | | Payment Due in Years Ending December 31, | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018
and after | | | Other | | | Total | | Long-Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal(1) | | $ | — | | | $ | 37 | | | $ | 130 | | | $ | 223 | | | $ | — | | | $ | 1,109 | | | $ | — | | | $ | 1,499 | | Interest(2) | | | 68 | | | | 68 | | | | 67 | | | | 61 | | | | 58 | | | | 538 | | | | — | | | | 860 | | Capital Lease Obligations(3) | | | 121 | | | | 194 | | | | 23 | | | | 17 | | | | 18 | | | | 42 | | | | — | | | | 415 | | Operating Leases | | | 2 | | | | 2 | | | | 2 | | | | 1 | | | | 1 | | | | 10 | | | | — | | | | 18 | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel(4) | | | 91 | | | | 78 | | | | 58 | | | | 53 | | | | 43 | | | | 77 | | | | — | | | | 400 | | Purchased Power(5) | | | 105 | | | | 91 | | | | 43 | | | | 34 | | | | 33 | | | | 466 | | | | — | | | | 772 | | Transmission | | | 7 | | | | 5 | | | | 5 | | | | 4 | | | | 3 | | | | 22 | | | | — | | | | 46 | | RES Performance-Based Incentives(6) | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 42 | | | | — | | | | 62 | | | | | | | | | | | Solar Equipment(7) | | | 12 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 12 | | Solar Project(8) | | | 4 | | | | 4 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 8 | | Service Agreement | | | 2 | | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4 | | Other Long-Term Liabilities(9): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension & Other Post Retirement Obligations(10) | | | 31 | | | | 6 | | | | 6 | | | | 6 | | | | 6 | | | | 33 | | | | — | | | | 88 | | Acquisition of Springerville Coal Handling and Common Facilities(11) | | | — | | | | — | | | | 120 | | | | — | | | | 38 | | | | 68 | | | | — | | | | 226 | | | | | | | | | | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 30 | | | | 30 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 447 | | | $ | 491 | | | $ | 458 | | | $ | 403 | | | $ | 204 | | | $ | 2,407 | | | $ | 30 | | | $ | 4,440 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
K-40
UniSource Energy’s Contractual Obligations
- - Millions of Dollars -
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Payment Due in Years | | | | | | | | | | | | | | | | | | | | | | 2016 | | | | | | | | | Ending December 31, | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | and after | | | Other | | | Total | | | Long Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal(1) | | $ | 57 | | | $ | 23 | | | $ | — | | | $ | 392 | | | $ | 100 | | | $ | 838 | | | $ | — | | | $ | 1,410 | | Interest(2) | | | 67 | | | | 64 | | | | 66 | | | | 64 | | | | 54 | | | | 692 | | | | — | | | | 1,007 | | Capital Lease Obligations(3) | | | 107 | | | | 118 | | | | 122 | | | | 195 | | | | 24 | | | | 79 | | | | — | | | | 645 | | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel(4) | | | 77 | | | | 52 | | | | 41 | | | | 39 | | | | 38 | | | | 123 | | | | — | | | | 370 | | | Purchased Power | | | 73 | | | | 48 | | | | 43 | | | | 4 | | | | — | | | | — | | | | — | | | | 168 | | | Transmission | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 10 | | | | — | | | | 30 | | | Coal Transportation Agreement | | | 1 | | | | 1 | | | | 1 | | | | 1 | | | | — | | | | — | | | | | | | | 4 | | Other Long-Term Liabilities(5): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension & Other Post Retirement Obligations(6) | | | 29 | | | | 5 | | | | 6 | | | | 6 | | | | 6 | | | | 36 | | | | — | | | | 88 | | Acquisition of Springerville Coal Handling and Common Facilities(7) | | | — | | | | — | | | | — | | | | — | | | | 120 | | | | 106 | | | | — | | | | 226 | | | Building Commitments | | | 32 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 32 | | | Solar Installation Commitments | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 40 | | | | 40 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 448 | | | $ | 315 | | | $ | 283 | | | $ | 705 | | | $ | 346 | | | $ | 1,884 | | | $ | 40 | | | $ | 4,021 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1) | | TEP’s variable rate IDBsindustrial development revenue or pollution control revenue bonds (IDBs) are secured by letters of creditLOCs issued pursuant to TEP’sthe TEP Credit Agreement, which expires in 2016, and the 2010 TEP Reimbursement Agreement, which expireexpires in 2014. Although the $215 million of variable rate IDBs mature between 2018 and 2032, the above maturity reflects a redemption or repurchase of such bonds in 2014 as though the letters of creditLOCs terminate without replacement upon expiration of the TEP Credit Agreement in 2016 (that supports $178 million of IDBs) and the 2010 TEP Reimbursement Agreement.Agreement in 2014 (that supports $37 million of IDBs). |
| | (2) | | Excludes interest on revolving credit facilities. |
| | (3) | | Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP are reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including a total of $14 million annually related to the Springerville Common and Springerville Coal Handling Facilities Leases. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement. |
| | (4) | | Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the Navajo, San Juan and Four Corners generating stations as the timing of payment has not been determined. See Note 4.4. |
| | (5) | Purchased Power includes TEP’s six long-term Purchase Power Agreements (PPAs) and UNS Electric’s two long-term PPAs with renewable energy generation producers to meet compliance under the RES tariff. The facilities achieved commercial operation in 2011 and 2012. TEP and UNS Electric are obligated to purchase 100% of the output from these facilities. The table above includes estimated future payments based on expected power deliveries under these contracts through 2032. TEP and UNS Electric have entered into additional long-term renewable PPAs to comply with the RES; however, TEP’s and UNS Electric’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational. |
| (6) | TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance Based Incentives (PBIs) and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2. |
| (7) | TEP committed to purchase 9 MW of photovoltaic equipment through December 2013. The ACC approved this purchase under TEP’s RES Implementation Plan. |
| (8) | In December 2012, UNS Electric entered into an agreement for the construction of a 7.182 MW solar photovoltaic power plant that will be constructed in two phases. The first phase will result in a 4.2 MW plant that UNS Electric expects to be operational in June of 2013. The balance of the project will be completed in 2014. UNS Electric invested $5 million in this project in 2012. The contract requires additional investments of $4 million in each of 2013 and 2014. This is an approved project under UNS Electric’s RES implementation plan. See Note 2. |
| (9) | Excludes asset retirement obligations expected to occur through 2066. |
| (6)(10) | | These obligations represent TEPTEP’s and UES’ expected contributions to pension plans in 2011,2013, TEP’s expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP) and TEP’s expected postretirementretiree 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 20112013 for their funded pension plans due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts. TEP previously funded the postretirementretiree benefit plan on a pay-as-you-go basis. In 2009, TEP established a VEBAVoluntary Employee Beneficiary Association (VEBA) Trust to partially fund expected future benefits for union employees. Benefit payments are not expected to be madeDisbursements from the VEBA Trust for several years.began in 2012. The 20112013 obligation includes expected VEBA contributions. VEBA contributions for periods beyond 20112013 cannot be determined at this time. |
| (7)(11) | | TEP has agreed with the owners of Springerville Units 3 and 4 that, prior to expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will either renew such leases or exercise its fixed price purchase option under such leases and acquire the leased facilities. TEP has the option of purchasing the facilities at the end of the initial lease term or after one or more renewal periods through 2025 for the Springerville Common Facilities and through 2035 for the Springerville Coal Handling Facilities. The table above reflects the purchase as if TEP exercised the fixed price purchase option at the end of the initial lease term. Upon such acquisitions by TEP, the owners of Springerville Unit 3 have the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 17% interest in the Springerville Coal Handling Facilities and a 14% interest in the Springerville Common Facilities. |
K-41
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 arrangements contains acceleration clauses or other consequences triggered by changes in our stock price. Dividends on Common Stock On February 25, 2011, UniSource2013, UNS Energy declared a first quarter cash dividend of $0.42$0.435 per share on its common stock.of Common Stock. The first quarter dividend, totaling approximately $15$18 million, will be paid March 23, 201125, 2013 to shareholders of record at the close of business March 11, 2011.13, 2013. The table below summarizes UniSourceUNS Energy’s dividends paid in 20082010 through 2010. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | Quarterly Dividend Per Common Share | | $ | 0.39 | | | $ | 0.29 | | | $ | 0.24 | | | Annual Dividend Per Common Share | | $ | 1.56 | | | $ | 1.16 | | | $ | 0.96 | | | Total Dividends Paid | | $ | 57 million | | | $ | 41 million | | | $ | 34 million | |
2012. | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | Quarterly Dividend Per Common Share | | $ | 0.43 | | | $ | 0.42 | | | $ | 0.39 | | Annual Dividend Per Common Share | | $ | 1.72 | | | $ | 1.68 | | | $ | 1.56 | | Common Stock Dividends Paid | | $ | 70 million | | | $ | 62 million | | | $ | 57 million | |
Income Taxes At December 31, 2010, UniSource Energy had federal AMT credit carryforwards of $34 million, including $16 million for TEP, which do not expire. UniSource Energy has a capital loss carryforward of $8 million that expires on December 31, 2015. This capital loss carryforward results in a $3 million deferred tax asset, against which a $3 million valuation allowance has been recorded. In addition, a valuation allowance of $5 million has been provided at UniSource Energy against deferred tax assets stemming from the difference between the book and tax basis of certain Millennium investments. We believe it is likely that the reversal of these basis differences will result in capital losses that cannot be currently realized. These two issues constitute the $8 million valuation allowance described in Note 8.
Tax PositionThe 2010 Federal Tax Relief Act includes provisions that make qualified property placed into service between September 8, 2010 and January 1, 2012 eligible for 100% bonus depreciation for tax purposes andpurposes. The same law makes qualified property placed in service during 2012 is eligible for 50% bonus depreciation for tax purposes. The American Taxpayer Relief Act of 2012 extended 50% bonus depreciation for tax purposes on qualified property placed in service during 2013. This is an acceleration of tax benefits UniSourceUNS Energy otherwise would have received over 20 years. As a result of these provisions, UniSourceUNS Energy maydid not pay any federal income taxes infor tax years 2011 or 2012. and 2012, and does not expect to pay any federal income taxes through 2015. See Note 8 for additional information.
TUCSON ELECTRIC POWER COMPANY RESULTS OF OPERATIONS TheExecutive Summary TEP’s financial condition and results of operations of TEP are the principal factors affecting the financial condition and results of operations of UniSourceUNS Energy. The following discussion relates to TEP’s utility operations, unless otherwise noted. 20102012 Compared with 2009 2011TEP recorded net income of $107$65 million in 20102012 compared with net income of $89$85 million in 2009.2011. The following factors contributed to the changedecrease in TEP’s net income: | • | | $11 million of pre-tax benefits recognized by TEP related primarily to Springerville Unit 4 for operating fees and contributions toward common facility costs received from the owner of Springerville Unit 4. Commercial operation of the unit began in December 2009. SeeFactors Affecting Results of Operations, Springerville Units 3 and 4, below for more information; |
K-42
| • | | a $10 million decrease in depreciation expense due to lower depreciation rates on TEP’s transmission assets and a lengthened depreciation period for leasehold improvements at Sundt Unit 4, partially offset by depreciation related to an increase in plant-in-service. The decrease excludes a $7 million adjustment that increased depreciation expense in the second quarter of 2009, related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity. SeeFactors Affecting Results of Operations, Depreciation,below for more information; |
| • | | A $3 million decrease in base O&M expense, which excludes costs directly offset by customer surcharges for renewable energy and demand side management programs and third party reimbursements. The decrease resulted from a decline in pension and postretirement medical expense and lower power plant maintenance expense. SeeOperating Expenses, O&M,below for more information; | | | • | | a $7 million decrease in amortization expense due to a decline in the balance of capital lease obligations. The decrease excludes a $3 million adjustment made in the second quarter of 2009 that decreased amortization expense. The adjustment was related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity; |
a $5 million decrease in interest expense on capital lease obligations, excluding an adjustment made in 2009 related to an investment in Springerville Unit 1 lease equity. As TEP pays down its capital lease obligations over time, the resulting interest expense also declines. The decrease in capital lease interest expense was offset by a $5 million decline in interest income during 2010. TEP’s investment in lease debt balance,retail margin revenues resulting from lower retail kWh sales due to milder summer weather than 2011, as well as the effects of the ACC’s energy efficiency and resulting interest income, also declines over time as TEP pays down its capital lease obligations;distributed generation requirements;
a $3an $8 million increasedecline in long-term wholesale margin revenues dueresulting primarily to an increasefrom a change in sales volumes to onethe pricing of TEP’s long-termenergy sold under the SRP wholesale customers; andcontract effective June 1, 2011;
a $2 million increase in wholesale transmission revenues as TEP temporarily provided transmission capacity for Springerville Unit 4 during the first quarter of 2010. | | | These factors were partially offset by: |
an $8$3 million decrease in total otherpre-tax income due in part to interest related to an income tax refund received in 2009 and a decline in gains recognized on company owned life insurance. The decrease excludes a $3 million adjustment that increased other income in the second quarter of 2009, related to a change in accounting for TEP’s investment inunplanned outage at Springerville Unit 1 lease equity;3;
a $6$7 million increase in interest expense on long-term debt due primarily to the conversion of $130 million of debt from a variable rate to a fixed rate. Although the fixed interest rate is higher than the variable interest rate that was in effect at the time of the conversion, the fixed rate conversion reduced TEP’s future interest rate risk and provided other benefits; and a $5 million decrease in total retail margin revenues. Weather, the implementation of energy efficiency measures and weak economic conditions contributed to a 0.8% decrease in kWh sales compared with 2009. Cooling Degree Days during 2010 were 3.5% below last year.
In June 2009, TEP adjusted its accounting for a 2006 investment in 14% of Springerville Unit 1 lease equity. As a result, TEP recorded a net increase to the income statement of $0.6 million, before tax. The adjustmentpre-tax gain recorded in June 2009 for the period from July 2006 through June 2009 included additional depreciation expense of $7 million; a reduction in amortization expense of $3 million; a reduction of interest expense on capital leases of $2 million; and $3 million of equity in earnings, which is included in Other Income on the income statement.
2009 Compared with 2008
TEP recorded net income of $89 million in 2009 compared with net income of $4 million in 2008. The following factors contributed to the change in TEP’s net income:
a $62 million increase in retail revenues due primarily to: the 6% base rate increase that took effect in December 2008; a new rate structure that charges higher rates for higher levels of energy usage; a $22 million increase in revenues collected from customers for renewable energy and energy efficiency programs; and hot summer weather during the third quarter of 2009;
K-43
a provision for rate refunds of $58 million recorded in 2008;
a $31 million decrease in total fuel and purchased energy expense, net of short-term wholesale revenues, due to lower generating output; a decline in the market price of wholesale power and natural gas; and a $24 million gain recorded to fuel expense in 20082011 related to the reinstatementsettlement of regulatory accounting;a dispute with El Paso Electric;
| • | | an $11 million decrease in total interest expense resulting primarily from lower interest rates on variable rate debt and lower interest expense related to capital lease obligations; and | | | • | | a $10 million increase in total other income due to interest income related to an income tax refund; income related to an adjustment in the accounting for an investment in lease equity; and income related to an increase in the value of a company owned life insurance policy. |
These factors were partially offset by:
a $27 million increase in depreciation and amortization expense due to: additions to plantas a result of an increase in service; new depreciation rates for generation assets;utility plant-in-service; and amortization of regulatory assets resulting from the 2008 TEP Rate Order;
a $24$5 million decrease in pre-tax income as a result of the amortizationwrite-off of a portion of the planned Tucson to Nogales transmission line; partially offset by a $4 million decrease in Base O&M primarily due to lower planned generating plant maintenance expense at San Juan. 2011 Compared with 2010 TEP recorded net income of $85 million in 2011 compared with $108 million in 2010. The following factors contributed to the decrease in TEP’s TRA.net income: a $15 million decline in long-term wholesale margin revenues resulting primarily from a change in the pricing of energy sold under the SRP wholesale contract effective June 1, 2011; a $5 million decrease in wholesale transmission revenues. In May 2008, the TRA was fully amortized;first quarter of 2010, transmission revenues benefitted from the temporary sale of transmission capacity to SRP; an $11a $10 million increase in Base O&M expense, which excludes costs directly offset by customer surcharges for renewable energy and demand side management programs and third party reimbursements. The increase resulted primarily from higher pension-related expenses anddue to TEP’s share of planned generating plant maintenance expense;expense at San Juan; and
a $9 million decrease in long-term wholesale revenues due primarily to lower kWh sales to Salt River Project (SRP) and Navajo Tribal Utility Authority (NTUA); and a $6$5 million increase in taxes other than income taxes. Thedepreciation expense as a result of an increase was due primarily to in utility plant-in-service;
partially offset by a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric; and a $3 million loss recorded in 2008 upon the reinstatement of regulatory accounting. In 2009 and 2008, the pre-tax benefit recognized by TEP2010 related to Springerville Units 3 and 4 for operating fees and contributions toward common facility costs was $12 million in each period.the settlement of disputed wholesale power transactions.
Utility Sales and Revenues Customer growth, weather, economic conditions, energy efficiency, distributed generation, and other consumption factors affect retail sales of electricity. Electric wholesale revenues are affected by prices in the wholesale energy market, the availability of TEP’s generating resources, and the level of wholesale forward contract activity. K-44
The table below provides trend information on retail sales by major customer class over the last three years as well as weather data for TEP’s service territory. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2010 vs. | | | | | | | 2009 vs. | | | | | | | | | | | | | 2009 | | | | | | | 2008 | | | Energy Sales, kWh (in millions) | | 2010 | | | 2009 | | | % Change* | | | 2008 | | | % Change* | | Electric Retail Sales: | | | | | | | | | | | | | | | | | | | | | | Residential | | | 3,870 | | | | 3,906 | | | | (0.9 | %) | | | 3,852 | | | | 1.4 | % | | Commercial | | | 1,963 | | | | 1,988 | | | | (1.3 | %) | | | 2,034 | | | | (2.3 | %) | | Industrial | | | 2,139 | | | | 2,161 | | | | (1.0 | %) | | | 2,264 | | | | (4.5 | %) | | Mining | | | 1,079 | | | | 1,065 | | | | 1.4 | % | | | 1,096 | | | | (2.8 | %) | | Public Authorities | | | 241 | | | | 251 | | | | (4.1 | %) | | | 256 | | | | (1.9 | %) | | | | | | | | | | | | | | | | | | Total Electric Retail Sales | | | 9,292 | | | | 9,371 | | | | (0.8 | %) | | | 9,502 | | | | (1.4 | %) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Revenues (in millions): | | | | | | | | | | | | | | | | | | | | | | Residential | | $ | 372 | | | $ | 378 | | | | (1.5 | %) | | $ | 351 | | | | 7.6 | % | | Commercial | | | 217 | | | | 220 | | | | (1.2 | %) | | | 212 | | | | 3.8 | % | | Industrial | | | 160 | | | | 164 | | | | (2.3 | %) | | | 165 | | | | (0.7 | %) | | Mining | | | 62 | | | | 61 | | | | 1.8 | % | | | 55 | | | | 9.7 | % | | Public Authorities | | | 19 | | | | 20 | | | | (3.7 | %) | | | 19 | | | | 3.8 | % | | | | | | | | | | | | | | | | | | Revenues excluding RES & DSM | | $ | 830 | | | $ | 843 | | | | (1.4 | %) | | $ | 802 | | | | 5.0 | % | RES and DSM Revenues | | | 38 | | | | 25 | | | NM | | | | 3 | | | NM | | Provision for Rate Refunds | | | — | | | | — | | | NM | | | | (58 | ) | | NM | | | | | | | | | | | | | | | | | | | Net Electric Retail Sales | | $ | 868 | | | $ | 868 | | | | 0.1 | % | | $ | 747 | | | | 16.2 | % | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2010 vs. | | | | | | | 2009 vs. | | | | | | | | | | | | | 2009 | | | | | | | 2008 | | | Weather Data: | | 2010 | | | 2009 | | | % Change* | | | 2008 | | | % Change* | | Cooling Degree Days | | | | | | | | | | | | | | | | | | | | | | Actual | | | 1,543 | | | | 1,599 | | | | (3.5 | %) | | | 1,336 | | | | 19.7 | % | | 10-Year Average | | | 1,468 | | | | 1,469 | | | NM | | | | 1,431 | | | NM | | | | | | | | | | | | | | | | | | | | | | | | Heating Degree Days | | | | | | | | | | | | | | | | | | | | | | Actual | | | 1,469 | | | | 1,287 | | | | 14.1 | % | | | 1,367 | | | | (5.9 | %) | | 10-Year Average | | | 1,430 | | | | 1,434 | | | NM | | | | 1,444 | | | NM | |
| | | | | | | | | | | Energy Sales, kWh (in millions) | | 2012 | | 2011 | | 2012 vs. 2011 % Change* | | 2010 | | 2011 vs. 2010 % Change* | Electric Retail Sales: | | | | | | | | | | | Residential | | 3,821 | | 3,888 | | (1.7%) | | 3,870 | | 0.5% | Commercial | | 1,974 | | 1,973 | | 0.1% | | 1,963 | | 0.5% | Industrial | | 2,132 | | 2,145 | | (0.6%) | | 2,139 | | 0.3% | Mining | | 1,093 | | 1,083 | | 0.9% | | 1,079 | | 0.3% | Public Authorities | | 245 | | 243 | | 0.9% | | 241 | | 1.1% | | | | | | | | | | | | Total Electric Retail Sales | | 9,265 | | 9,332 | | (0.7%) | | 9,292 | | 0.4% | | | | | | | | | | | | Retail Margin Revenues (in millions): | | | | | | | | | | | Residential | | $248 | | $252 | | (1.4%) | | $252 | | 0.2% | Commercial | | 160 | | 160 | | 0.1% | | 159 | | 0.6% | Industrial | | 93 | | 95 | | (2.5%) | | 97 | | (2.1%) | Mining | | 30 | | 32 | | (3.8%) | | 31 | | 1.9% | Public Authorities | | 13 | | 12 | | 2.4% | | 12 | | 0.8% | | | | | | | | | | | | Total Retail Margin Revenues (Non-GAAP) (1) | | $544 | | $551 | | (1.2%) | | $551 | | 0.0% | PPFAC Revenues | | 327 | | 307 | | 6.5% | | 279 | | 9.6% | RES and DSM Revenues | | 45 | | 46 | | (2.6%) | | 38 | | 23.3% | | | | | | | | | | | | Total Retail Revenues (GAAP) | | $916 | | $904 | | 1.3% | | $868 | | 4.1% | | | | | | | | | | | | Avg. Retail Margin Revenue (cents / kWh): | | | | | | | | | | | Residential | | 6.50 | | 6.48 | | 0.3% | | 6.50 | | (0.3%) | Commercial | | 8.12 | | 8.11 | | 0.1% | | 8.10 | | 0.1% | Industrial | | 4.33 | | 4.42 | | (2.0%) | | 4.53 | | (2.4%) | Mining | | 2.78 | | 2.92 | | (4.8%) | | 2.87 | | 1.7% | Public Authorities | | 5.13 | | 5.05 | | 1.6% | | 5.07 | | (0.4%) | | | | | | | | | | | | Avg. Retail Margin Revenue / kWh | | 5.87 | | 5.90 | | (0.5%) | | 5.93 | | (0.5%) | Avg. PPFAC Revenue / kWh | | 3.52 | | 3.29 | | 7.0% | | 3.01 | | 9.3% | Avg. RES & DSM Revenue / kWh | | 0.49 | | 0.50 | | (2.0%) | | 0.41 | | 22.0% | | | | | | | | | | | | Total Avg. Retail Revenue / kWh | | 9.88 | | 9.69 | | 2.0% | | 9.35 | | 3.7% | | | | | | | | | | | | Cooling Degree Days | | | | | | | | | | | Actual | | 1,556 | | 1,528 | | 1.8% | | 1,543 | | (1.0%) | 10-Year Average | | 1,484 | | 1,473 | | NM | | 1,468 | | NM | | | | | | | Heating Degree Days | | | | | | | | | | | Actual | | 1,201 | | 1,597 | | (24.8%) | | 1,469 | | 8.7% | 10-Year Average | | 1,394 | | 1,417 | | NM | | 1,430 | | NM | | | | | | | | | | | |
| | | | * | | Percent change calculated on un-rounded data; may not correspond to data shown in table. |
K-45
Retail Margin Revenues
The table below provides a summary of the margin revenues (retail revenues excluding base fuel, PPFAC and RES and DSM charges) on TEP’s retail sales for 2010 and 2009. Comparable data is not available for 2008 because TEP’s new rate structure took effect in December 2008.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | 2010 | | | 2009 | | | Amount | | | Percent* | | Retail Margin Revenues (in millions): | | | | | | | | | | | | | | | | | | Residential | | $ | 252 | | | $ | 254 | | | $ | (2 | ) | | | (0.9 | %) | | Commercial | | | 159 | | | | 160 | | | | (1 | ) | | | (0.5 | %) | | Industrial | | | 97 | | | | 100 | | | | (3 | ) | | | (3.1 | %) | | Mining | | | 31 | | | | 30 | | | | 1 | | | | 3.0 | % | | Public Authorities | | | 12 | | | | 12 | | | | — | | | | (2.4 | %) | | | | | | | | | | | | | | | Total Retail Margin Revenues (non-GAAP)** | | $ | 551 | | | $ | 556 | | | $ | (5 | ) | | | (1.0 | %) | Retail Fuel Revenues | | | 279 | | | | 287 | | | | (8 | ) | | | (2.2 | %) | RES & DSM Revenues | | | 38 | | | | 25 | | | | 13 | | | | 48.8 | % | | | | | | | | | | | | | | | Net Electric Retail Sales (GAAP) | | $ | 868 | | | $ | 868 | | | $ | 0 | | | | 0.1 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Avg. Retail Margin Rate (cents / kWh): | | | | | | | | | | | | | | | | | | Residential | | | 6.50 | | | | 6.49 | | | | 0.01 | | | | 0.1 | % | | Commercial | | | 8.10 | | | | 8.04 | | | | 0.06 | | | | 0.8 | % | | Industrial | | | 4.53 | | | | 4.62 | | | | (0.09 | ) | | | (2.1 | %) | | Mining | | | 2.87 | | | | 2.82 | | | | 0.05 | | | | 1.6 | % | | Public Authorities | | | 5.07 | | | | 4.98 | | | | 0.07 | | | | 1.7 | % | | | | | | | | | | | | | | | Avg. Retail Margin Rate | | | 5.93 | | | | 5.93 | | | | 0.00 | | | | -0.1 | % | Avg. PPFAC Rate | | | 3.01 | | | | 3.05 | | | | (0.04 | ) | | | (1.4 | %) | Avg. RES & DSM Rate | | | 0.41 | | | | 0.27 | | | | 0.14 | | | | 50.0 | % | | | | | | | | | | | | | | | Total Avg. Retail Rate | | | 9.34 | | | | 9.26 | | | | 0.10 | | | | 0.9 | % | | | | | | | | | | | | | | |
| (1) | | | * | | Percent change is calculated on un-rounded data; may not correspond to data shown in table. | | ** | | Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. TEP believes that Retail Margin Revenues which is Net Electricexclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Sales less base fuel, PPFAC revenues, and revenues for DSM and RES programs,Margin Revenues between periods provides useful information to investors.investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business. |
2010 Compared with 2009
ResidentialIn 2012, residential kWh sales were 0.9% lower in 2010decreased by 1.7% compared with 2009, which led2011 due in part to a decrease in residentialthe number of Cooling Degree Days during the summer months of 2012 compared with 2011. Other factors affecting TEP’s 2012 retail sales volumes included the ACC’s Electric EE Standards and distributed generation requirements, as well as the pace of economic recovery. Residential margin revenues in 2012 decreased by $4 million when compared with 2011. Commercial Commercial kWh sales increased by 0.1% compared with 2011 due primarily to a 0.4% increase in the number of $2 million.commercial customers. Commercial margin revenues increased by less than $1 million, or 0.1%, compared with 2011. Industrial Industrial kWh sales decreased by 0.6% in 2012 compared with 2011, while margin revenues declined by 2.5%. The decline in residential kWh sales can be attributed tomargin revenues resulted from a 3.5% decreasechange in Cooling Degree Days compared with 2009, weak local economic conditions and energy efficiency measures. Commercial
Commercial kWh sales in 2010 were 1.3% below 2009 levels. A decline in Cooling Degree Days and weak economic conditions contributed to the sales decline. The lower sales volumes, and resulting lowerusage patterns by certain industrial customers that reduced their demand charges ledpaid to a decline in commercial margin revenuesTEP.Mining The continuation of $1 million. Industrial
Industrial kWh sales declined by 1.0% compared with 2009, due primarily to weak economic conditions. Margin revenues from industrial customers decreased by 3.1%, or $3 million due to changing usage patterns that reduced demand charges.
K-46
Mining
Higherhigh copper prices led to increased mining activity, resulting in a 1.4%0.9% increase in sales volumes in 20102012 compared with 2009.2011. However, margin revenues from mining customers decreased by 3.8% compared with 2011, due to changing usage patterns which resulted in lower demand charges paid to TEP.2011 Compared with 2010 Residential In 2011, residential kWh sales increased by 0.5% compared with 2010 due in part to a 0.2% increase in the number of residential customers. Residential margin revenues in 2011 were unchanged compared with 2010. Commercial Commercial kWh sales increased by 0.5% compared with 2010 due primarily to a 0.6% increase in the number of commercial customers. Commercial margin revenues increased by $1 million, or 0.6%, compared with 2010. Industrial Industrial kWh sales increased by 0.3% in 2011 compared with 2010, while margin revenues declined by 2.1%. The decline in margin revenues, despite higher kWh sales, resulted from a change in usage patterns by certain industrial customers that reduced their demand charges paid to TEP. Mining The continuation of high copper prices led to increased mining activity, resulting in a 0.3% increase in sales volumes in 2011 compared with 2010. Margin revenues from mining customers increased $1 million, or 3.0%, compared with the prior yearby 1.9% over 2010 due to higher energy consumption and changing usage patterns that increasedwhich resulted in higher demand charges. Long-Term charges paid to TEP.Wholesale Sales and Transmission Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2010 vs. | | | | | | | 2009 vs. | | | | | | | | | | | | | 2009 | | | | | | | 2008 | | | | | 2010 | | | 2009 | | | % Chng.* | | | 2008 | | | % Chng.* | | Long-Term Wholesale Contracts | | | | | | | | | | | | | | | | | | | | | | kWh Sales (Millions) | | | 988 | | | | 833 | | | | 18.6 | % | | | 1,096 | | | | (24.0 | %) | | Revenues ($ Millions) | | $ | 56 | | | $ | 48 | | | | 15.4 | % | | $ | 57 | | | | (16.1 | %) | | | | | | | | | | | | | | | | | | | | | | | Wholesale Transmission Revenues ($ Millions) | | $ | 21 | | | $ | 19 | | | | 9.9 | % | | $ | 17 | | | | 10.5 | % |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Long-Term Wholesale Revenues: | | | | | | | | | | | | | Long-Term Wholesale Margin Revenues (Non-GAAP)* | | $ | 5 | | | $ | 13 | | | $ | 28 | | Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues | | | 20 | | | | 28 | | | | 28 | | | | | | | | | | | | | | | Total Long-Term Wholesale Revenues | | $ | 25 | | | $ | 41 | | | $ | 56 | | Transmission Revenues | | | 16 | | | | 16 | | | | 21 | | Short-Term Wholesale Revenues | | | 70 | | | | 73 | | | | 64 | | | | | | | | | | | | | | | Electric Wholesale Sales (GAAP) | | $ | 111 | | | $ | 130 | | | $ | 141 | | | | | | | | | | | | | | |
| | | | * | | PercentLong-Term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change calculated on un-rounded data; may not correspondin Long-Term Wholesale Margin Revenues between periods provides useful information to data shown in table.investors because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business. |
RevenuesIn 2012, long-term wholesale margin revenues from long-term wholesale contracts increased bywere $8 million lower than in 2010 compared with 2009, due to an 18.6% increase in kWh sales.2011. The increase in sales volumes and revenues is due to higher kWh sales to TEP’s two primary long-term wholesale customers, SRP and NTUA. The margin on TEP’s long-term wholesale sales in 2010 and 2009decrease was $28 million and $25 million, respectively. The increase in margin in 2010 is due primarily to a 26% increase in sales volumes to NTUA. During 2009, NTUA received a greater allotment of federal hydro power as hydro conditionschange in the Coloradopricing of energy sold under the SRP contract. SeeFactors Affecting Results of Operations, Long-Term Wholesale Sales, Salt River basin were above normal, reducing its needProject, below, for power from TEP. more information.Wholesale transmission revenues in 2012 were the same as 2011. Unlike 2012 and 2011, in 2010 increased by $2 million as TEP temporarily provided short-term transmission capacity to SRP for Springerville Unit 4. TEP credits all revenues from short-term wholesale sales and 90% of the margin on wholesale trading activity against the fuel and purchased power costs eligible for recovery in the Purchased Power and Fuel Adjustment Clause (PPFAC). There was no wholesale trading activity in 2010, 2011, and 2012. In April 2010, TEP settled all remaining claims arising out offrom certain of its transactions with the California Power Exchange (CPX) and the California Independent System Operator (CISO) during the California energy crisis of 2000 and 2001. As a result of this settlement, TEP recorded a $3 million pre-tax charge against income in the first quarter of 2010. In December 2009, TEP recorded a pre-tax charge of $4 million against income also related to transactions with the CPX and CISO in 2000 and 2001. See Note 4. Short-Term Wholesale and TradingOther Revenues In the 2010 and 2009, TEP’s short-term wholesale and trading revenues were $71 million and $84 million, respectively. All of the revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.
2009 Compared with 2008
Residential and Commercial
Residential kWh sales increased by 1.4% in 2009 due primarily to hotter than normal weather during the third quarter. Residential revenues increased $27 million or 7.6%, that year due to hot summer weather as well as a base rate increase that took effect in December 2008.
Commercial kWh sales during 2009 were 2.3% below 2008. The decrease in commercial kWh sales was driven primarily by weak economic conditions. Revenues from commercial kWh sales increased by $8 million, or 3.8%, as a result of the base rate increase that took effect in December 2008.
Industrial, Mining and Public Authorities
Sales volumes to industrial, mining and public authority customers decreased by a combined 3.8% in 2009 due primarily to the weak economy. Associated revenues were $6 million higher than the same period last year as a result of the base rate increase that became effective in December 2008.
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Revenue related to Springerville Units 3 and 4(1) | | $ | 101 | | | $ | 97 | | | $ | 97 | | Other Revenue | | | 33 | | | | 26 | | | | 22 | | | | | | | | | | | | | | | Total Other Revenue | | $ | 134 | | | $ | 123 | | | $ | 119 | | | | | | | | | | | | | | |
K-47
Long-Term Wholesale Revenues
Revenues from long-term wholesale contracts decreased by $9 million in 2009 compared with 2008 primarily due to lower sales volumes to NTUA. In 2009, NTUA received a greater allotment of federal hydro power as hydro conditions in the Colorado River basin were above normal. In addition, low gas prices made it more economic for one of their major customers to self-generate than to purchase power from NTUA. These factors led NTUA to purchase 17% less energy under its agreement with TEP compared with 2008. The gross margin (long-term wholesale revenues less the cost of energy, which is based on TEP’s average fuel and purchased power costs) on TEP’s long-term wholesale sales for 2009 was $25 million. Prior to the implementation of the PPFAC in January 2009, TEP did not allocate fuel and purchased power costs to long-term wholesale sales.
Other Revenues
| | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | Reimbursements related to Springerville Units 3 and 4(1) | | $ | 97 | | | $ | 59 | | | $ | 53 | | | Other | | | 22 | | | | 24 | | | | 19 | | | | | | | | | | | | | | Total Other Revenue | | $ | 119 | | | $ | 83 | | | $ | 72 | | | | | | | | | | | | |
| | | | (1) | | Represents reimbursements from Tri-State and SRP, the owners of Springerville Units 3 and 4, respectively, for expenses incurred by TEP related to the operation of these plants.Springerville Units 3 and 4. |
In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include:include inter-company revenues from UNS Gas and UNS Electric for corporate services provided by TEP;TEP and miscellaneous service-related revenues such as power pole attachments, damage claims, and customer late fees. 20102012 Compared with 2009 2011Fuel and Purchased Power Expense TEP’s fuel and purchased power expense and energy resources for 2010, 20092012, 2011, and 20082010 are detailed below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Generation/Purchases | | | Expense | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of kWh- | | | -Millions of Dollars- | | | Coal-Fired Generation | | | 9,481 | | | | 9,272 | | | | 10,573 | | | $ | 219 | | | $ | 201 | | | $ | 235 | | | Gas-Fired Generation | | | 1,078 | | | | 986 | | | | 871 | | | | 60 | | | | 76 | | | | 74 | | | Renewable Generation | | | 32 | | | | 30 | | | | 34 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | Total | | | 10,591 | | | | 10,288 | | | | 11,478 | | | | 279 | | | | 277 | | | | 309 | | Regulatory Accounting Reinstatement(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (24 | ) | | | | | | | | | | | | | | | | | | | | | Total Generation(2) | | | 10,591 | | | | 10,288 | | | | 11,478 | | | | 279 | | | | 277 | | | | 285 | | | Purchased Power | | | 2,760 | | | | 3,678 | | | | 3,693 | | | | 119 | | | | 144 | | | | 251 | | | Transmission | | | — | | | | — | | | | — | | | | 3 | | | | 3 | | | | 11 | | | Increase (Decrease) to Reflect PPFAC Recovery Treatment | | | — | | | | — | | | | — | | | | (23 | ) | | | (21 | ) | | | — | | | | | | | | | | | | | | | | | | | | | | | Total Resources | | | 13,351 | | | | 13,966 | | | | 15,171 | | | $ | 378 | | | $ | 403 | | | $ | 547 | | | | | | | | | | | | | | | | | | | | | | | | | | Less Line Losses and Company Use | | | 801 | | | | 816 | | | | 1,289 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Energy Sold | | | 12,550 | | | | 13,150 | | | | 13,882 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | (1) | | See Note 2 for more information. | | (2) | | Fuel expense excludes $7 million in 2010 and $5 million in 2009 and 2008, related to Springerville Units 3 and 4; 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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | TEP | | Generation and Purchased Power | | | Fuel and Purchased Power
Expense | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of kWh- | | | -Millions of Dollars- | | Coal-Fired Generation | | | 9,702 | | | | 9,946 | | | | 9,481 | | | $ | 247 | | | $ | 254 | | | $ | 217 | | Gas-Fired Generation | | | 1,435 | | | | 929 | | | | 1,078 | | | | 65 | | | | 55 | | | | 60 | | Renewable Generation | | | 45 | | | | 28 | | | | 25 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Generation | | | 11,182 | | | | 10,903 | | | | 10,584 | | | | 312 | | | | 309 | | | | 277 | | Purchased Power | | | 2,328 | | | | 2,687 | | | | 2,846 | | | | 80 | | | | 106 | | | | 119 | | Reimbursed Fuel Expense | | | — | | | | — | | | | — | | | | 7 | | | | 8 | | | | 7 | | Transmission | | | — | | | | — | | | | — | | | | 6 | | | | (1 | ) | | | 3 | | Increase (Decrease) to Reflect PPFAC Treatment | | | — | | | | — | | | | — | | | | 31 | | | | (6 | ) | | | (21 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Total Resources | | | 13,510 | | | | 13,590 | | | | 13,430 | | | $ | 436 | | | $ | 416 | | | $ | 385 | | | | | | | | | | | | | | | | | | | | | | | | | | | Less Line Losses and Company Use | | | (839 | ) | | | (786 | ) | | | (869 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Energy Sold | | | 12,671 | | | | 12,804 | | | | 12,561 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation Coal-related fuel expense in 2010Total generating output increased by $18 millionduring 2012 compared with 20092011. The higher output was due primarily to the switching of fuelincreased gas usage at Sundt Unit 4, froma dual-fuel unit capable of using either coal or natural gas to coal. TEP fueled Sundt 4 on coal for eight months in 2010, compared with two months in 2009. Gas-related fuel expense decreased in 2010 due primarily to a decrease in realized losses on gas hedging activities. gas. K-48
Purchased Power Purchased power volumes and expense during 2010 weredecreased in 2012 compared with 2011. The lower than last yearvolume of power purchases was primarily due to a decrease in short-term wholesale sales activity, an increase in coal-firedthe increased usage of TEP’s gas-fired generating output, and a decline in retail sales volumes. resources.The table below summarizes TEP’s cost per kWh generated or purchased. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -cents per | | | | | kWh generated- | | | Coal | | | 2.30 | | | | 2.16 | | | | 2.22 | | | Gas | | | 5.58 | | | | 7.66 | | | | 8.49 | | | Purchased Power | | | 4.17 | | | | 3.92 | | | | 6.80 | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Cents Per kWh Generated- | | Coal | | | 2.54 | | | | 2.56 | | | | 2.29 | | Gas | | | 4.54 | | | | 5.99 | | | | 5.58 | | Purchased Power | | | 3.44 | | | | 3.94 | | | | 4.17 | | All Sources | | | 3.19 | | | | 3.30 | | | | 3.24 | |
Market Prices As a participant in the western U.S. wholesale power markets, TEP is directly and indirectly affected by changes in market conditions. The average annual market price for around-the-clock energy based on the Dow Jones Palo Verde Market Index was 13% higher in 2010 compared with 2009. The average annual price for natural gas based on the Permian Index was 25% higher in 2010 compared with last year. We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2011. | | | | | | | | | | | | | | | Avg. Market Price for Around-the-Clock Energy - $/MWh | | 2010 | | | 2009 | | | 2008 | | | Year ended December 31 | | $ | 34 | | | $ | 30 | | | $ | 63 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Avg. Market Price for Natural Gas - $/MMBtu | | 2010 | | | 2009 | | | 2008 | | | Year ended December 31 | | $ | 4.18 | | | $ | 3.34 | | | $ | 7.41 | | | | | | | | | | | | |
2013. The table below shows the average wholesale market price for power and natural gas. | | | | | Average Market Price for Around-the-Clock Energy (Dow Jones Palo Verde Index) | | $/MWh | | 2012 | | $ | 26 | | 2011 | | $ | 30 | | 2010 | | $ | 34 | |
| | | | | Average Market Price for Natural Gas (Permian Basin) | | $/MMBtu | | 2012 | | $ | 2.67 | | 2011 | | $ | 3.89 | | 2010 | | $ | 4.18 | |
O&M The table below summarizes the items included in TEP’s O&M expense. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | Base O&M (Non-GAAP)(1) | | $ | 228 | | | $ | 231 | | | $ | 220 | | | Reimbursed Expenses Related to Springerville Units 3 and 4 | | | 65 | | | | 41 | | | | 35 | | Gain on the Sale of SO2 Emissions Allowances | | | — | | | | — | | | | (1 | ) | Expenses Related to Customer-funded Renewable Energy and Demand-side Management Programs(2) | | | 31 | | | | 18 | | | | 3 | | | Reinstatement of Regulatory Accounting | | | — | | | | — | | | | (1 | ) | | | | | | | | | | | | | Total Other O&M (GAAP) | | $ | 324 | | | $ | 290 | | | $ | 256 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Base O&M (Non-GAAP)(1) | | $ | 234 | | | $ | 238 | | | $ | 228 | | O&M recorded in Other Expense | | | (6 | ) | | | (8 | ) | | | (7 | ) | Reimbursed expenses related to Springerville Units 3 and 4 | | | 72 | | | | 63 | | | | 65 | | Expenses related to customer funded renewable energy and DSM programs | | | 35 | | | | 38 | | | | 31 | | | | | | | | | | | | | | | Total O&M (GAAP) | | $ | 335 | | | $ | 331 | | | $ | 317 | | | | | | | | | | | | | | |
| | | | (1) | | Base O&M, a Non-GAAPnon-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. TEP believes thatWe believe Base O&M which is Other O&M less reimbursed expenses, gains on the sale of SO2 Allowances and expenses related to customer-funded renewable energy and demand-side management programs, provides useful information to investors. | | (2) | | Represents expensesinvestors because it represents the fundamental level of operating and maintenance expense related to TEP’s customer-funded renewable energy and DSM programs; the offsetting fundsour business. Base O&M excludes expenses that are directly offset by revenues collected from customers are recorded in retail revenue.and other third parties. |
TEP’s baseBase O&M expense in 20102012 was $228$4 million or $3 million below 2009. The decline islower than 2011 primarily due primarily to fewer scheduled generating plant maintenance outages and a decrease in pension and postretirement medical expense in 2010 compared with 2009. outages. K-49
Income Tax Expense In 2010,2012, TEP’s effective tax rate was 36%37% compared with 38% in 2009. The decrease is primarily due to an increase in federal deductions along with federal and state tax credits.2011. See Note 8 for more information. 20092011 Compared with 2008 2010Fuel and Purchased Power ExpenseGeneration
In 2009, coal-fired generation decreased by 12% due to: fuel switching at Sundt Unit 4 from coal to natural gas; a 1% decrease in retail kWh sales; and lower coal plant availability. Coal-related fuel expense decreased by $34 millionTotal generating output increased during 2009, excluding a $24 million gain recorded in 2008 related2011 compared with 2010. The higher output was primarily due to the adoptionincreased availability of regulatory accounting. The decrease resulted from lowerTEP’s largest coal-fired generating output, as well as $9 million of expenses recordedplants, Springerville Units 1 and 2. In 2010, Springerville Units 1 and 2 experienced unplanned outages, in the third quarter of 2008 relatedaddition to a settlement of mining-related costs. Fuel switchingplanned maintenance outage at SundtSpringerville Unit 4 led to a 13% increase1.Purchased Power Purchased power volumes decreased in gas-fired generating output in 20092011 compared with 2008. However, gas-related fuel expense increased by just $2 million2010. The lower volume of power purchases was primarily due to a decrease in the average price for natural gas.increased availability of TEP’s hedging activities have been reflected in the PPFAC since January 1, 2009. Purchased power expense decreased by $106 million in 2009 compared with 2008. The average price paid by TEP for purchased power during 2009 was approximately $39 per MWh, compared with $68 per MWh in 2008.
coal-fired generating resources.O&M TEP’s baseBase O&M expense in 2009 increased by $112011 was $238 million, compared with 2008or $10 million above 2010. The increase is due primarily to an increase in planned power plantunplanned outages and higher pension and postretirement medical expenses. TRA Amortization
TEP did not record any TRA amortization during 2009, as the TRA balance was amortized to zero in May 2008. TRA amortization was $24 million in 2008. Amortization of the TRA was the result of the 1999 Settlement Agreement with the ACC, which changed the accounting method for TEP’s generation operations. This item reflected the recovery, through 2008, of transition recovery assets which had previously been regulatory assets related to the generation business.
Income Tax Expense
In 2009, TEP’s effective tax rate was 38%, compared with 71% in 2008. In 2008, it was determined that the environmental penalties at San Juan would not be deductible for income tax purposes. As a result, an additional $3 million of tax expense was recognized in 2008 for penalties incurred in the current and prior years. Other items included in GAAP expense which will not be deductible for tax were offset by the recognition of income tax credits. See Note 8 for more information.
FACTORS AFFECTING RESULTS OF OPERATIONS Base Rate Increase Moratorium
Pursuant to the 20082012 TEP Rate Order,Case In February 2013, TEP, ACC Staff, and other parties to TEP’s base rates are frozen through December 31, 2012. TEP is prohibited from submitting an application for new base rates before June 30, 2012.pending rate case proceeding entered into a settlement agreement (2013 Settlement Agreement). The test year to be used in TEP’s next base rate application cannot end earlier than December 31, 2011. Notwithstanding2013 Settlement Agreement requires the rate increase moratorium, base rates and adjustor mechanisms may be changed in emergency conditions beyond TEP’s control ifapproval of the ACC concludes such changes are required to protect the public interest. before new rates can become effective.The moratorium does not preclude TEP from seeking rate relief in the event of the imposition of a federal carbon tax or related federal carbon regulations. For a more detailed description of the terms of the 20082013 Settlement Agreement include, but are not limited to: an increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues; an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion; a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%; a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million); a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt; and an agreement by TEP Rate Order, seeto seek recovery of costs related to the Nogales transmission line from the Federal Energy Regulatory Commission before seeking rate recovery from the ACC. The 2013 Settlement Agreement also includes cost adjustment mechanisms, an energy efficiency resource plan and modifications to TEP’s PPFAC, which are described below. Lost Fixed Cost Recovery Mechanism A Lost Fixed Cost Recovery mechanism (LFCR) would allow TEP to recover certain non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC’s Electric EE Standards and distributed generation requirements under the RES. The LFCR rate would be adjusted annually and be subject to ACC approval and a year-over-year cap of 1% of TEP’s total retail revenues. Environmental Compliance Adjustor An Environmental Compliance Adjustor (ECA) mechanism would allow TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA would be adjusted annually to recover environmental compliances costs, subject to a cap equal to 0.25% of TEP’s total retail revenues. Energy Efficiency Resource Plan The Energy Efficiency Resource Plan (EERP) would allow TEP to invest in cost-effective energy efficiency programs approved by the ACC. Investments under the EERP would be considered regulatory assets and amortized over five-years. If certain thresholds are met as established in the EE implementation plans and approved by the ACC, TEP would recover its costs associated with the EERP, including a return on and a return of its investments, through TEP’s existing demand-side management surcharge. Purchased Power and Fuel Adjustment Clause A new PPFAC rate, which includes a one-time credit of approximately $3 million related to sulfur credits and a $9.7 million deferral of certain costs, will be effective at the same time new Base Rates are approved by the ACC. TEP’s existing PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs; sulfur credits; broker fees; and 100% of the proceeds from the sale of SO2 allowances. Procedural Schedule Hearings before the ACC administrative law judge assigned to TEP’s rate case proceeding are scheduled to begin on March 6, 2013. The judge will issue a recommended opinion and order following the conclusion of hearings. That recommendation is then subject to approval by the ACC. The parties to the 2013 Settlement Agreement agreed to ask the ACC (1) to find that the terms and conditions of the 2013 Settlement Agreement are just and reasonable and in the public interest, along with any and all other necessary findings, and (2) to approve the 2013 Settlement Agreement such that it and the rates contained therein may become effective on July 1, 2013. TEP cannot predict if the 2013 Settlement Agreement will be approved or modified by the ACC. Purchased Power and Fuel Adjustment Clause SeeItem 1. — Business, TEP,,Rates and Regulation, 2008 TEP Rate Order.Purchased Power and Fuel Adjustment Clause. K-50
Springerville Units 3 and 4 TEP operates and receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Springerville Unit 4 began commercial operations in December 2009. TEP recorded In 2012, the annual impact to TEP’s pre-tax income ofresulting from operating Springerville Units 3 and 4 was approximately $21 million compared with $24 million in 2010 and $132011. The decrease is related to an unplanned outage that occurred at Springerville Unit 3 in 2012. TEP recorded a pre-tax loss of $2 million in 2009 related to2012 because the operationoutage prevented TEP from meeting certain availability requirements under the terms of these units. TEP’s operating agreement with Tri-State. The table below summarizes the income statement line items wherein which TEP records revenues and expenses related to Springerville Units 3 and 4. | | | | | | | | | | | | | 2010 | | | 2009 | | | Springerville Units 3 and 4 | | -millions of dollars- | | | Other Revenues | | $ | 97 | | | $ | 60 | | | Fuel Expense | | | 7 | | | | 5 | | | Operations and Maintenance Expense | | | 64 | | | | 41 | | | Taxes other than Income Taxes | | | 2 | | | | 1 | | | | | | | | | | | Total Pre-Tax Income | | $ | 24 | | | $ | 13 | | | | | | | | | |
Depreciation
In January 2010,4: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Other Revenues | | $ | 101 | | | $ | 97 | | | $ | 97 | | Fuel Expense | | | (7 | ) | | | (8 | ) | | | (7 | ) | O&M | | | (72 | ) | | | (63 | ) | | | (65 | ) | Taxes Other Than Income Taxes | | | (1 | ) | | | (2 | ) | | | (1 | ) | | | | | | | | | | | | | | Total Pre-Tax Income | | $ | 21 | | | $ | 24 | | | $ | 24 | | | | | | | | | | | | | | |
Tucson to Nogales Transmission Line SeeItem 1. Business, TEP, completed an updated depreciation study which indicated that its transmission assets’ depreciable lives should be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010 which had the effect of reducing transmission depreciation expense by approximately $14 million in 2010. TEP’s total depreciation expense in 2010 decreased by $10 million compared with 2009. The lower depreciation rates on TEP’s transmission assets and a lengthened depreciation period for leasehold improvements at Sundt Unit 4 were partially offset by depreciation relatedTransmission Access, Tucson to an increase in plant-in-service. The decrease in 2010 compared with 2009 excludes a $7 million adjustment that increased depreciation expense in the second quarter of 2009 related to a change in accounting for TEP’s investment in Springerville Unit 1 lease equity.
Sundt Unit 4
Until March 2010, Sundt Unit 4 was leased by TEP with a lease term expiration of January 2011. In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4 from the equity owner for approximately $52 million. In April 2010, TEP redeemed the outstanding Sundt Unit 4 lease debt of $5 million, terminated the lease agreement and caused title of Sundt Unit 4 to be transferred to TEP.
Refinancing Activity
In November 2010, TEP amended and restated its existing credit agreement (TEP Credit Agreement). As a result of the increase in the interest rate on borrowings under the revolving credit facility and the margin rate in effect on the letter of credit facility, we estimate that interest expense related to the TEP Credit Agreement will increase by $6 million in 2011 compared with 2010.
Nogales Transmission Line.Pension and PostretirementRetiree Benefit Expense In 2010 and 2009, TEP charged $13 million and $17 million, respectively, ofThe table below summarizes TEP’s pension and postretirementother retiree benefit expenses charged to O&M expense. Inin 2012, 2011, TEP expects to charge $15 million of pension and postretirement benefit expense to O&M expense.2010. See Note 9 for more information. | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Pension Expense Charged to O&M | | $ | 10 | | | $ | 10 | | | $ | 9 | | Other Retiree Benefit Expense Charged to O&M | | | 5 | | | | 4 | | | | 4 | | | | | | | | | | | | | | | Total | | $ | 15 | | | $ | 14 | | | $ | 13 | | | | | | | | | | | | | | |
In 2013, TEP expects to charge $10 million of pension and $5 million of other retiree benefit expense to O&M. Long-Term Wholesale Sales In 2010 and 2009, TEP’s margin on long-term wholesale sales was $28$5 million in 2012 and $25$13 million respectively.in 2011. TEP’s two primary long-term wholesale contracts are with SRP and NTUA. the Navajo Tribal Utility Authority (NTUA).Salt River Project Prior to June 1, 2011, under the terms of the SRP contract, TEP receivesreceived a monthly demand charge of approximately $1.8 million, or $22 million annually, and sellssold the energy at a price based on TEP’s average fuel cost. BeginningFrom June 1, 2011 to December 31, 2011, SRP will bewas required to purchase 73,000 MWh per month, or 876,000month. From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh annually.of on-peak energy per year. TEP willdoes not receive a demand charge and the price of energy will beis based on a slight discount to the price of on-peak power on the Palo Verde Market Index. As of February 15, 2011,13, 2013, the average around-the-clock forward price of on-peak power on the Palo Verde Market Index for the calendar year 2013 was $36 per MWh. In 2012, the average on-peak price of power on the Palo Verde Market Index for June through December 2011 was $34approximately $29 per MWh. K-51
Navajo Tribal Utility Authority TEP serves the portion of NTUA’s load that is not served from NTUA’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh. Since 2010, the price of 50% of the MWh sales from June to September has been based on the Palo Verde Market Index. In 2010,2012, approximately 25%13% of the total energy sold to NTUA was priced based on the Palo Verde Market Index. The remaining power sales occur at a fixed price under TEP’s contract with NTUA.For more information on long-term wholesale sales seeItem. 1 Business, TEP, Service Area and Customers, Wholesale Business. El Paso Electric Dispute
TEP and El Paso Electric (El Paso) have a dispute regarding transmission service from Luna to TEP’s system. In 2008, the FERC issued an order supporting TEP’s position; and, pending resolution, El Paso refunded $10 million that TEP had paid for transmission service from Luna to TEP’s system from 2006 to 2008, along with interest of $1 million.
In July 2010, the FERC issued an order denying El Paso's request for rehearing of FERC's 2008 order. El Paso filed an appeal in the United States Court of Appeals of the District of Columbia Circuit. In January 2011, in response to a joint motion filed by El Paso and FERC, the United States Court of Appeals of the District of Columbia Circuit ordered the appeal proceeding to be held in abeyance to allow TEP and El Paso time to continue settlement negotiations in this matter. TEP has not recognized income as a result of the July 2010 FERC decision. TEP cannot predict the timing or outcome of this proceeding.
Electric Energy Efficiency Standards In August 2010, the ACC approved new EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost effective DSM programs. In 2010, TEP’s programs saved 1.1% of 2009 sales. In 2011, the EE Standards target total kWh savings of 1.25% of 2010 sales. The EE Standards increase thereafter up to the targeted cumulative annual reduction in retail kWh sales of 22% by 2020. For more information, seeSeeItem. 1Item 1. Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling. Renewable Energy Standard and Tariff SeeItem 1. Business, TEP, Rates and Regulation, Renewable Energy Standard and Tariff. Retail Electric Competition RulesSeeItem 1. Business, TEP, Rates and Regulation, Retail Electric Competition Rules. Competition New technological developments and the implementation of Electric EE Standards may reduce energy consumption by TEP’s retail customers. TEP’s customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP’s services. Self-generation by TEP’s customers 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. SeeItem 1. Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decouplingfor more information. Renewable Energy Standard and Tariff
In 2010, the ACC approved a funding mechanism that allows TEP to use RES funds to recover operating costs, depreciation, property taxes and provide TEP with a return on its investments in TEP-owned solar projects until these costs are recovered as part of TEP’s base rates. TEP invested $14 million in two solar projects that were completed in December 2010 and began cost recovery through the RES surcharge in January 2011. In 2011, TEP expects to earn approximately $0.6 million on its 2010 investment in solar projects.
The ACC approved an additional investment of $28 million for approximately 7 MW of solar capacity in 2011. In 2012, TEP expects to earn approximately $2 million on its company-owned solar projects. TEP expects to invest $28 million annually in 2012 through 2014 in solar PV projects, subject to approval by the ACC. For more information seeItem. 1 Business, TEP, Rates and Regulation, Renewable Energy Standard and Tariff.
K-52
Sales to Mining Customers The rise in the market priceContinued pricing of copper over the last two years has led to increasedabove $3 per pound triggered an increase in mining activity at the copper mines operating in TEP’s service area. TEP’s mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP’s mining load could increase by up to 100 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry’s expansion plans. In 2010,2012, sales to TEP’s mining customers increased 1.4%0.9% compared with 20092011 and represented 12% of TEP’s total retail kWh sales and 7%6% of total retail margin revenues. In addition to the mining customers that TEP currently serves, in 2007, Augusta Resources Corporation (Augusta) filed a plan of operations with the United States Forest Service (USFS)in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona. Augusta must receiveThe Rosemont Copper Mine requires electric service from TEP via a Record138 kilo-volt (kV) transmission line for the construction and ongoing operation of Decisionthe mine. A certificate of environmental compatibility (CEC) from the USFS prior to receiving permits for mine construction and operations. As part of the USFS’ decision process, it must issue an Environmental Impact Statement (EIS). A draft EIS is expected to be issuedstate line siting committee was approved in 2011 and will be followed by public hearings.for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine reacheswere to reach full production, it would be expected to become TEP’s largest retail customer.customer, with TEP would serveserving approximately 10090 MW of the Rosemont Copper Mine’smine’s total estimated load of approximately 110100 MW. TEP cannot predict if or when existing mines will expand operations or new or re-opened mines will commence operations. Interest Rates TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under its revolving credit facility. At December 31, 2012, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 20% on $178 million of bonds and 10% on the other $37 million. During 2012, the average rates paid ranged from 0.06% to 0.26%. At February 13, 2013, the average rate on the debt was 0.12%. TEP has a fixed-for-floating interest rate swap in place to hedge $50 million of its variable rate IDBs. TEP is also subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR and other benchmark interest rates increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk. Fair Value Measurements TEP’s income statement exposure to risk is mitigated as TEP reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability, or as a component of AOCIaccumulated other comprehensive income (AOCI) rather than in the income statement. See Note 11 for more information. LIQUIDITY AND CAPITAL RESOURCES The table below shows the cash available to TEP after capital expenditures, scheduled debt payments, and payments on capital lease obligations: | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Net Cash Flows — Operating Activities (GAAP) | | $ | 298 | | | $ | 265 | | | $ | 266 | | | Amounts from Statements of Cash Flows: | | | | | | | | | | | | | | Less: Capital Expenditures (Including Purchase of Sundt Unit 4) | | | (267 | ) | | | (232 | ) | | | (292 | ) | | | | | | | | | | | | | Net Cash Flows after Capital Expenditures (non-GAAP)* | | | 31 | | | | 33 | | | | (26 | ) | | | | | | | | | | | | | Amounts from Statements of Cash Flows: | | | | | | | | | | | | | | Less: Retirement of Capital Lease Obligations | | | (56 | ) | | | (24 | ) | | | (74 | ) | | Plus: Proceeds from Investment in Lease Debt | | | 26 | | | | 13 | | | | 25 | | | | | | | | | | | | | | Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)* | | $ | 1 | | | $ | 22 | | | $ | (75 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | Net Cash Flows — Operating Activities (GAAP) | | $ | 298 | | | $ | 265 | | | $ | 266 | | | Net Cash Flows — Investing Activities (GAAP) | | | (248 | ) | | | (246 | ) | | | (388 | ) | | Net Cash Flows — Financing Activities (GAAP) | | | (52 | ) | | | (29 | ) | | | 129 | | | Net Cash Flows after Capital Expenditures (non-GAAP)* | | | 24 | | | | 33 | | | | (26 | ) | | Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)* | | | 1 | | | | 22 | | | | (75 | ) |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | Net Cash Flows – Operating Activities (GAAP) | | $ | 268 | | | $ | 268 | | | $ | 302 | | Amounts from Statements of Cash Flows: | | | | | | | | | | | | | Less: Capital Expenditures(1) | | | (253 | ) | | | (352 | ) | | | (277 | ) | | | | | | | | | | | | | | Net Cash Flows after Capital Expenditures (Non-GAAP)(2) | | | 15 | | | | (84 | ) | | | 25 | | Amounts From Statements of Cash Flows: | | | | | | | | | | | | | Less: Retirement of Capital Lease Obligations | | | (89 | ) | | | (74 | ) | | | (56 | ) | Plus: Proceeds from Investment in Lease Debt | | | 19 | | | | 38 | | | | 26 | | | | | | | | | | | | | | | Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)(2) | | $ | (55 | ) | | $ | (120 | ) | | $ | (5 | ) | | | | | | | | | | | | | |
| (1) | 2010 includes a $51 million payment for the purchase of Sundt Unit 4 lease equity. |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | Net Cash Flows – Operating Activities (GAAP) | | $ | 268 | | | $ | 268 | | | $ | 302 | | Net Cash Flows – Investing Activities (GAAP) | | | (228 | ) | | | (312 | ) | | | (253 | ) | Net Cash Flows – Financing Activities (GAAP) | | | 12 | | | | 51 | | | | (52 | ) | Net Cash Flows after Capital Expenditures (Non-GAAP)(2) | | | 15 | | | | (84 | ) | | | 25 | | Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)(2) | | | (55 | ) | | | (120 | ) | | | (5 | ) |
| (2) | | * | | Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows — Flows—Operating Activities, which is determined in accordance with GAAP as a measure of liquidity.GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations provide useful information to investors as measures of liquidity and ourTEP’s ability to fund our capital requirements, make required principal payments on debt and capital lease obligations (net), and pay dividends to UniSourceUNS Energy. |
K-53
Liquidity Outlook During 2011,2013, TEP expects to generate sufficient internal cash flows to fund the majority of its capital expenditures and operating activities. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to fund its business activities. In 2010,2012, net cash flows from operating activities increased by $33 millionwere the same when compared with 2009.2011. Net operating cash flows in 2012 were impacted by: a $34 million increase in cash receipts from operating Springerville Units 3 and 4. Approximately $23 million the collection of the increase is related to the reimbursement of incurred costs that are included primarily in operating and maintenance costs and fuel costs. Approximately $11 million of the increase represents operating synergies that directly benefit TEP’s operating cash flows; and
a $55 million increase in cash receipts from electric retail and wholesale sales, net ofunder-recovered fuel and purchased power costs. The increase iscosts; a decrease in purchased power costs due to: higher customer surcharges under the RES, which is usedin part to fund programs whoselower market prices for power; lower O&M costs are primarily includeddue in operating and maintenance costs; an increase in long-term wholesale electric sales; higher wholesale transmission revenues; partially offset by lower retail electric kWh sales.
These factors were partially offset by:
| • | | a $5 million increase in total interest paid due in part to the conversion of $130 million of debt from variable rate to fixed rate. Although the fixed interest rate is higher than the variable interest rate that was in effect at the time of the conversion, the fixed rate conversion reduced TEP’s future interest rate risk and provided other benefits described below inFinancing Activities, Bond Issuances — 2010; |
a $16 million increase in income taxes paid (net of refunds) due primarily to higher taxable income andfewer scheduled outages at TEP’s generating facilities; a decrease in income tax refunds;
a $5 millionrefunds received due to overestimated payments made in 2010 and refunded in 2011; higher fuel costs paid due in part to an increase in wages paid;coal inventory at Sundt Unit 4 and
an increase in the output of gas-fired generating units; an increase in property tax payments due to higher rates and property values; and a $4 million decrease in interest received due primarily to a lowerthe declining balance of TEP’s investment in lease debt balance. debt.Investing Activities Net cash flows used for investing activities increaseddecreased by $2$84 million in 20102012 compared with 2009. Investing activities2011. A decrease in 2010 included:
the usecapital expenditures of $216$99 million for capital expenditures;
the purchase of Sundt Unit 4 for $51 million;
the receipt of $26was partially offset by a $19 million related todecrease in proceeds from the return of investment in Springerville lease debt;
the purchase of renewable energy credits for $7 million which TEP recovers through the RES surcharge; and
insurance proceeds for replacement assets of $1 million.
Investing activities in 2009 included:
| • | | the use of $232 million for capital expenditures; | | | • | | an investment of $31 million to purchase Springerville lease debt; |
the receipt of $13 million related to the return of investment in Springerville lease debt; and
insurance proceeds for replacement assets of $5 million.
debt. K-54
Capital Expenditures TEP’s forecasted capital expenditures are summarized below: | | | | | | | | | | | | | | | | | | | | | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Category | | -Millions of Dollars- | | | Transmission and Distribution | | $ | 143 | | | $ | 99 | | | $ | 166 | | | $ | 116 | | | $ | 82 | | | Generation Facilities | | | 71 | | | | 49 | | | | 86 | | | | 65 | | | | 69 | | | Renewable Energy Generation | | | 29 | | | | 30 | | | | 29 | | | | 30 | | | | 30 | | | Environmental | | | 8 | | | | 56 | | | | 60 | | | | 82 | | | | 71 | | | General and Other | | | 55 | | | | 39 | | | | 31 | | | | 29 | | | | 34 | | | | | | | | | | | | | | | | | | | | Total | | $ | 306 | | | $ | 273 | | | $ | 372 | | | $ | 322 | | | $ | 286 | | | | | | | | | | | | | | | | | | |
TEP’s estimated capital expenditures for 2011-2014 are $1.3 billion, which is approximately $400 million higher than the estimates reported in UniSource Energy and TEP’s 2009 Annual Report on Form 10-K. The increase is due primarily to: projected investments in renewable energy projects; an increase in TEP’s share of estimated environmental compliance costs at the San Juan and Navajo generating stations; an increase in high voltage transmission investments designed to increase TEP’s energy import capability into its service territory; and an increase in investments to upgrade and maintain TEP’s local distribution system. SeeItem 1. Business, TEP, Environmental Matters, for more information on TEP’s estimated capital costs related to environmental compliance.
| | | | | | | | | | | | | | | | | | | | | | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | | | -Millions of Dollars- | | Transmission and Distribution | | $ | 156 | | | $ | 116 | | | $ | 161 | | | $ | 108 | | | $ | 89 | | Generation Facilities | | | 88 | | | | 83 | | | | 68 | | | | 56 | | | | 82 | | Renewable Energy Generation | | | 35 | | | | 36 | | | | 35 | | | | 36 | | | | 36 | | Environmental | | | 5 | | | | 23 | | | | 35 | | | | 50 | | | | 38 | | General and Other | | | 39 | | | | 38 | | | | 32 | | | | 37 | | | | 33 | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 323 | | | $ | 296 | | | $ | 331 | | | $ | 287 | | | $ | 278 | | | | | | | | | | | | | | | | | | | | | | |
TEP’s estimated capital expenditures in 2015 exclude the potential $159 million purchase of interests in Springerville Unit 1 and the potential $120 million purchase of interests in Springerville Coal Handling Facilities upon the expiration of their respective leases in January 2015. SeeCapital Lease Obligations, below, for more information. TEP’s estimated capital expenditure forecast does notexpenditures include approximately $25 million for TEP’s share of potential environmental expenditures related to the estimated costinstallation of SNCR at San Juan Unit 1. TEP estimates its share of capital expenditures would be approximately $200 million if SCR technology were to construct a proposed Tucson to Nogales, Arizona 345 KV transmission linebe installed at San Juan Units 1 and 2 instead of $120 million.SNCR at San Juan Unit 1. SeeItem 1.Item. 1 Business, TEP, Transmission Access, Tucson to Nogales Transmission LineEnvironmental Matters, Regional Haze Rules, San Juan,for more information. All of these estimates are subject to continuing review and adjustment. Actual capital expenditures may be different from these estimates due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations, and other factors. InvestmentsFinancing Activities In 2012, net cash from financing activities was $39 million lower than in Springerville Lease Debt At December 31, 2010, TEP had $72 million2011 due to: higher dividends paid to, and lower capital contributions from, UNS Energy; lower borrowings (net of investmentsrepayments) made under TEP’s Revolving Credit Facility; and an increase in lease debtscheduled payments on its balance sheet. In March 2009, TEP made a $31 million purchase of Springerville Unit 1 lease debt. The table below provides a summary of the investment balances in lease debt.
| | | | | | | | | | | | | Lease Debt Investment Balance | | | | | December 31, 2010 | | | December 31, 2009 | | | Leased Asset | | - In Millions - | | | Investments in Lease Debt: | | | | | | | | | | Springerville Unit 1 | | $ | 67 | | | $ | 88 | | | Springerville Coal Handling Facilities | | | 1 | | | | 7 | | | | | | | | | | | Total Investment in Lease Debt | | $ | 68 | | | $ | 95 | | | | | | | | | |
Unless TEP makes new investments in lease debt, the investment in lease debt balance declines over time due to the amortization of lease debt that occurs as a result of the normal payments TEP makes on itsTEP’s capital lease obligations. The Springerville Unit 1 and Springerville Coal Handling Facilities leases expire in 2015.
See Note 6 for more information.
K-55
Financing Activities
NetThese cash proceeds used for financing activities increased by $23 million in 2010 compared with 2009 due to:
net repayments of revolving credit facility borrowings of $35 million in 2010 compared with net proceeds of $25 million in 2009;
a $15 million decrease in equity investments from UniSource Energy;
a $32 million increase in payments of capital lease obligations; and
a $5 million increase in debt issuance/retirement costs;outflows were partially offset by
an $88 million increase onin proceeds from the issuance of long-term debt (net of repayments of long-term debt)repayments). In November 2010, TEP amended and restated its existing credit agreement (TEP Credit Agreement). The TEP Credit Agreement had previously included a $150 million revolving credit facility and a $341 million letter of credit facility to support $329 million aggregate principal amount of tax-exempt variable rate bonds. As amended, the TEP Credit Agreement consists of a $200 million revolving credit and revolving letter of credit facility and a $341$186 million letter of credit facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 20142016 and is secured by $541$386 million of Mortgage Bonds. AtAs of December 31, 2010, TEP had2012, there were no outstanding borrowings outstanding and less than $1 million of letters of creditLOCs issued under the revolving credit facility. TEP Revolving Credit Facility.In 2011, TEP reduced its LOC facility from $341 million to $186 million, following the repurchase of $150 million of variable rate IDBs and the cancellation of $155 million of LOCs supporting those bonds. See2011 Bond Issuances, Purchase and Redemptions, below. The TEP Credit Agreement contains restrictions on liens, mergers, and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UniSourceUNS Energy. As of December 31, 2010,2012, TEP was in compliance with the terms of the TEP Credit Agreement. In March 2010 TEP entered into a $30 million term loan agreement to help fund a portion of the purchase of Sundt Unit 4 and for other general corporate purposes. TEP repaid the term loan in October 2010.
TEP Reimbursement Agreement In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million letter of creditLOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of creditLOC supports $37 million aggregate principal amount of variable rate tax-exempt IDBspollution control bonds that were issued on behalf of TEP in December 2010. SeeBond Issuances — 2010, below. The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. As of December 31, 2010,2012, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement. Capital Contribution from UniSourceUNS Energy In March2011, UNS Energy contributed $30 million of capital to TEP. TEP used the proceeds to partially fund the purchase of its headquarters building. In 2010, UniSourceUNS Energy contributed $15 million of capital to TEP. TEP used the proceeds to helppartially fund the purchase of Sundt Unit 4. 2012 Bond Issuances and Redemptions In March 2009, UniSource Energy contributed $302012, $177 million of capital to TEP. TEP used the proceeds to purchase Springerville Unit 1 lease debt. There were no capital contributions from UniSource Energy to TEP in 2008. Bond Issuances — 2010
In December 2010, the Coconino County, Arizona Pollution Control Corporation (Coconino PCC) issued approximately $37 million of its 2010 Series Aunsecured tax-exempt pollution control revenue bonds (2010 Coconino A Bonds) for TEP’s benefit. The proceeds of the bonds were used to redeem a corresponding principal amountissued on behalf of 7.125% 1997 Coconino Series A bonds.TEP. The 2010 Coconino A Bonds accrue interest at a weekly rate until the interest rate is converted to another mode as provided for in the loan agreement and indenture. The initial weekly interest rate was 0.30%. The variable rate 2010 Coconino A Bonds are supported by a letter of credit issued under the 2010 TEP Reimbursement Agreement. SeeTEP Reimbursement Agreement, above.
K-56
In October 2010, the Pima Authority issued $100 million of its 2010 Series A tax-exempt IDBs for TEP’s benefit. The 2010 Pima Series A IDBs are unsecured,bonds bear interest at a fixed rate of 5.25%4.50%, mature in October 2040,March 2030 and are callablemay be redeemed at par on or after OctoberMarch 1, 2020. Net2022. In April 2012, the proceeds of an underwriting discount, $99the bond issuance, as well as $7 million of internal cash, were used to redeem $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6.In June 2012, approximately $16 million of unsecured tax-exempt IDBs were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.50%, mature in June 2030 and may be redeemed at par on or after June 1, 2022. In July 2012, the proceeds of the bond issuance were deposited inused to redeem approximately $16 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. See Note 6. In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 15, 2022, with a construction fundmake-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the bond trustee. Theremaining proceeds are to be applied to the construction of certain of TEP’s transmissionused for general corporate purposes. See Note 6. 2011 Bond Issuances, Purchases, and distribution facilities used to provide electric service in Pima County. As of December 31, 2010,Redemptions In November 2011, TEP had drawn $88issued $250 million of 5.15% Notes due November 2021. TEP may call the debt anytime before August 15, 2021, with a make-whole premium plus accrued interest. After August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the construction fund,sale to: repurchase $150 million of variable rate bonds; redeem $22 million of 6.1% fixed rate bonds; and repay $78 million of outstanding revolving credit facility balances. The $150 million of tax-exempt variable rate debt purchased by TEP was not retired but will be held in treasury and may be reissued or refunded in the future. See Note 6. 2010 Bond Issuances In 2010, $137 million of tax-exempt bonds were issued on behalf of TEP, with the remaining $11$37 million expectedof such bonds being applied to be drawn down by the endredeem a corresponding amount of the first quarter of 2011. outstanding tax-exempt bonds. In Januaryaddition, in 2010 TEP converted the interest rate mode on its $130 million of 2008 Pima B Bondstax-exempt bonds from a variable rate to a fixed rate. Tax-Exempt Bonds TEP has financed a substantial portion of utility plant assets with revenue bonds issued by governmental entities on TEP’s behalf. The 2008 Pima Binterest on these bonds were re-offered in January 2010 with a term rateis excluded from gross income of 5.75% through maturitythe bondholder for federal income tax purposes. The proceeds of September 2029. Interest is payable semi-annually beginning June 1, 2010. Thethe bonds are callableloaned to TEP, with TEP agreeing to repay the loans by making payments in amounts and at par beginning January 2015. Although the fixed interest rate is higher than the variable interest rate that was in effect at the timetimes to enable payments of the conversion, the fixed rate conversion reduced TEP’s future interest rate riskprincipal and allowed TEP to terminate the $132 million letter of credit (LOC) that supported the bonds, and cancel the mortgage bonds that secured the LOC facility. Bond Issuances — 2009
In October 2009, the Pima Authority issued approximately $80 million of its 2009 Series A tax-exempt pollution control bonds (2009 Pima A San Juan Bonds) for TEP’s benefit. At the same time, the Coconino PCC issued approximately $15 million of its 2009 Series A tax-exempt pollution control bonds (2009 Coconino A Bonds) for TEP’s benefit. The 2009 Pima A San Juan bonds are unsecured, bear interest at a rate of 4.95%, mature on October 1, 2020, and are not callable prior to maturity. The 2009 Coconino A Bonds are unsecured, bear interest at 5.125%, mature on October 1, 2032, and are callable at par beginning October 1, 2019. Semi-annual interest payments on both series of bonds are payable beginning April 1, 2010. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs for each through the respective maturity dates.
The proceeds from the issuance of the 2009 Pima A San Juan Bonds and the 2009 Coconino A Bonds were deposited with a trustee and were used in November 2009 to redeem approximately $80 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control Bonds and approximately $15 million of 7.0% 1997 Series B Coconino County Pollution Control Bonds. The average annual interest savings is expected to be approximately $2 million.
Interest Rate Risk
TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under its revolving credit facility. At December 31, 2010 and December 31, 2009, TEP had $365 million and $459 million, respectively, inthe tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable underbonds to be paid when due. Of the indentures for the bonds was 10% on the $37$824 million of 2010 Coconino A Bonds and is 20% on the other $329 million in IDBs. During 2010, the average rates paid ranged from 0.17% to 0.39%. During 2009, the average rates paid ranged from 0.25% to 0.79%. At February 15, 2011, the average rate on the debt was 0.27%.
TEP manages its exposure to variable interest rate risk by entering into transactions to maintain a mix of variable rate to fixed rate long-term debt of approximately one-third to two-thirds. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.
TEP is also subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR and other benchmark interest rates increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A.Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below.
Interest Rate Swaps — Springerville Common Facilities Lease Debt
In 2006 and 2009, TEP entered into interest rate swaps to hedge the floating interest rate risk associated with the Springerville Common Facilities Lease Debt. Interest on the lease debt is payable at six-month LIBOR plus a spread. The applicable spread was 1.625%tax-exempt bonds outstanding as of December 31, 20102012, $609 million are unsecured and December 31, 2009.bear interest at fixed rates and $215 million are variable rate bonds. The swapsvariable rate bonds accrue interest at a weekly rate, with bondholders having the right to require their bonds to be purchased upon demand at a purchase price of par plus accrued interest. Variable rate bonds which have been put for purchase are generally remarketed to third parties to pay the effectpurchase price. Payments of fixingprincipal, interest, and purchase price on the interest ratesvariable rate bonds are supported by direct-pay LOCs, with TEP being required to reimburse the LOC banks for drawings on $64 million of the lease debt outstanding at December 31, 2010 at rates ranging from 3.18% to 5.77%.
LOCs. SeeTEP Credit Agreement andTEP Reimbursement Agreementfor more information. K-57
Mortgage Indenture TEP’s mortgage indenture creates a lien on and security interest in most of TEP’s utility plant assets. Springerville Unit 2, which is owned by San Carlos, is not subject to this lien and security interest. The mortgage indenture allows TEP to issue additional mortgage bonds on the basis of (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 mortgage indenture. At December 31, 2010,2012, TEP had a total of $578$423 million in outstanding Mortgage Bonds, consisting of $541$386 million in bonds securing the TEP Credit Agreement and $37 million in bonds securing the 2010 TEP Reimbursement Agreement. 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 Tucson metropolitan area of Pima County as well as Fort Huachuca in contiguous Cochise County.
TEP has financed the following facilities, in whole or in part, with the proceeds of tax-exempt local furnishing bonds: Springerville Unit 2, a portion of TEP’s local must-run generation, 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.
In December 2008, the Arizona Department of Commerce allocated $200 million of tax-exempt financing volume cap to TEP for purposes of financing local furnishing transmission and distribution projects in Pima County. In October 2010, the Pima Authority issued $100 million of tax-exempt local furnishing bonds for TEP’s benefit. TEP has until December 2011 to use the remaining volume cap allocation. Upon receipt of this allocation in December 2008, TEP paid a $2 million security deposit to the Arizona Department of Commerce. This security deposit is refundable on a pro-rata basis after each new series of IDBs is issued. TEP received $1 million of its deposit back upon the issuance of the 2010 Pima A Bonds. SeeBond Issuances, above.
As of December 31, 2010, TEP had approximately $680 million of tax-exempt local furnishing bonds outstanding. Approximately $331 million in principal amount of such bonds financed Springerville Unit 2 and the Express Line.
K-58
Capital Lease Obligations At December 31, 2010,2012, TEP had $489$353 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts in each of the obligations. | | | | | | | | | | | | | Capital Lease Obligation | | | | | | | | | Balance | | | | | | | Leased Asset | | at December 31, 2010 | | | Expiration | | Purchase Option | | | | - In Millions - | | | | | | | Springerville Unit 1 | | $ | 302 | | | 2015 | | Fair market value purchase option | | | | | | | | | | | | Springerville Coal Handling Facilities | | | 77 | | | 2015 | | Fixed price purchase option of $120 million | | | | | | | | | | | | Springerville Common Facilities | | | 110 | | | 2017 & 2021 | | Fixed price purchase option of $106 million | | | | | | | | | | | | | | | | | | | | | Total Capital Lease Obligations | | $ | 489 | | | | | | | | | | | | | | |
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. 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 owners of Springerville Units 3 and 4 to purchase such facilities. The renewal and purchase option for Springerville Unit 1 is 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.
obligations: | | | | | | | | | Leases | | Capital Lease Obligation
Balance | | | Expiration | | Renewal/Purchase Option | | | | -Millions of Dollars- | | | | | | Springerville Unit 1(1) | | $ | 197 | | | 2015 | | Fair market value purchase option of $159 million(2) | Springerville Coal Handling Facilities | | | 48 | | | 2015 | | Fixed price purchase option of $120 million(3) | Springerville Common Facilities(3) | | | 108 | | | 2017 and 2021 | | Fixed price purchase option of $106 million(4) | | | | | | | | | | Total Capital Lease Obligations | | $ | 353 | | | | | | | | | | | | | | |
| (1) | The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. |
| (2) | SeeItem 3. – Legal Proceedings, Springerville Unit 1 Appraisalfor information on a dispute related to the purchase option. |
| (3) | TEP agreed with Tri-State, the lessee of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either (1) buy a portion of these facilities; or (2) continue making payments to TEP for the use of these facilities. |
| (4) | The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities. |
TEP’s capital lease obligation balances decline over time due to the normal capital lease payments made by TEP. See Note 6 for more information about the fixed purchase price amounts. K-59
Contractual Obligations The following chart displays TEP’s contractual obligations as of December 31, 20102012 by maturity and by type of obligation. TEP’s Contractual Obligations
- - Millions of Dollars -
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Payment Due in Years | | | | | | | | | | | | | | | | | | | | | | 2016 | | | | | | | | | Ending December 31, | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | and after | | | Other | | | Total | | | Long Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | — | | | $ | — | | | $ | — | | | $ | 365 | | | $ | — | | | $ | 638 | | | $ | — | | | $ | 1,003 | | | Interest | | | 46 | | | | 47 | | | | 49 | | | | 47 | | | | 36 | | | | 535 | | | | — | | | | 760 | | | Capital Lease Obligations | | | 107 | | | | 118 | | | | 122 | | | | 195 | | | | 24 | | | | 79 | | | | — | | | | 645 | | | Operating Leases | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel (including Transportation) | | | 52 | | | | 42 | | | | 36 | | | | 35 | | | | 35 | | | | 104 | | | | — | | | | 304 | | | Purchased Power | | | 26 | | | | 15 | | | | 8 | | | | 4 | | | | — | | | | — | | | | — | | | | 53 | | | Transmission | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 10 | | | | — | | | | 20 | | | Coal Transportation Agreement | | | 1 | | | | 1 | | | | 1 | | | | 1 | | | | — | | | | ��� | | | | — | | | | 4 | | | Other Long-Term Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension & Other Post Retirement Obligations | | | 27 | | | | 5 | | | | 6 | | | | 6 | | | | 6 | | | | 36 | | | | — | | | | 86 | | | Acquisition of Springerville Coal Handling and Common Facilities | | | — | | | | — | | | | — | | | | — | | | | 120 | | | | 106 | | | | — | | | | 226 | | | Solar Installation Commitments | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 35 | | | | 35 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 262 | | | $ | 230 | | | $ | 224 | | | $ | 655 | | | $ | 223 | | | $ | 1,508 | | | $ | 35 | | | $ | 3,137 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
obligation: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TEP’s Contractual Obligations - Millions of Dollars - | | Payment Due in Years Ending December 31, | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018
and after | | | Other | | | Total | | Long-Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | — | | | $ | 37 | | | $ | — | | | $ | 178 | | | $ | — | | | $ | 1,009 | | | $ | — | | | $ | 1,224 | | Interest | | | 55 | | | | 55 | | | | 54 | | | | 54 | | | | 51 | | | | 493 | | | | — | | | | 762 | | Capital Lease Obligations | | | 121 | | | | 194 | | | | 23 | | | | 17 | | | | 18 | | | | 42 | | | | — | | | | 415 | | Operating Leases | | | 2 | | | | 2 | | | | 2 | | | | 1 | | | | 1 | | | | 10 | | | | — | | | | 18 | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel (including Transportation) | | | 65 | | | | 65 | | | | 50 | | | | 47 | | | | 39 | | | | 60 | | | | — | | | | 326 | | Purchased Power | | | 50 | | | | 41 | | | | 29 | | | | 28 | | | | 28 | | | | 386 | | | | — | | | | 562 | | Transmission | | | 3 | | | | 3 | | | | 3 | | | | 3 | | | | 3 | | | | 22 | | | | — | | | | 37 | | RES Performance-Based Incentives | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 42 | | | | | | | | 62 | | Solar Equipment | | | 12 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 12 | | Service Agreement | | | 2 | | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4 | | Other Long-Term Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension & Other Post- Retirement Obligations | | | 29 | | | | 6 | | | | 6 | | | | 6 | | | | 6 | | | | 33 | | | | — | | | | 86 | | Acquisition of Springerville Coal Handling and Common Facilities | | | — | | | | — | | | | 120 | | | | — | | | | 38 | | | | 68 | | | | — | | | | 226 | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 23 | | | | 23 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 343 | | | $ | 409 | | | $ | 291 | | | $ | 338 | | | $ | 188 | | | $ | 2,165 | | | $ | 23 | | | $ | 3,757 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SeeUniSourceUNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations. We have reviewed our contractual obligations and provide the following additional information: TEP’s Credit Agreement contains pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its letters of creditLOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility. | | • | | TEP’s Credit Agreement contains certain financial and other restrictive covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2010,2012, TEP was in compliance with these covenants. SeeTEP Credit Agreement,above. |
TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or a letter of creditan LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of December 31, 2010,2012, TEP had posted aless than $1 million letter of creditin LOCs as collateral with counterparties for credit enhancement. Dividends on Common Stock TEP declared and paid $30 million of dividends to UniSourceUNS Energy ofin 2012. TEP did not pay any dividends to UNS Energy in 2011. TEP paid $60 million of dividends to UNS Energy in 2010, $60 million in 2009, and $3 million in 2008. 2010.TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement, and certain financial covenants. As of December 31, 2010,2012, TEP was in compliance with the terms of the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement. K-60
The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings. UNS GAS RESULTS OF OPERATIONS UNS Gas reported net income of $9 million in 2010, $72012, $10 million in 2009,2011, and $9 million in 2008.2010. We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months. The table below provides summary financial information for UNS Gas. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Gas Revenues | | $ | 146 | | | $ | 149 | | | $ | 172 | | | Other Revenues | | | 4 | | | | 4 | | | | 2 | | | | | | | | | | | | | | Total Operating Revenues | | | 150 | | | | 153 | | | | 174 | | | | | | | | | | | | | | Total Purchased Gas and PGA Expense | | | 91 | | | | 99 | | | | 119 | | | Other Operations and Maintenance Expense | | | 26 | | | | 25 | | | | 25 | | | Depreciation and Amortization | | | 8 | | | | 7 | | | | 7 | | | Taxes other than Income Taxes | | | 3 | | | | 3 | | | | 3 | | | | | | | | | | | | | | Total Other Operating Expenses | | | 128 | | | | 134 | | | | 154 | | | | | | | | | | | | | | Operating Income (Loss) | | | 22 | | | | 19 | | | | 20 | | | | | | | | | | | | | | Total Interest Expense | | | 7 | | | | 6 | | | | 6 | | | Total Other Income | | | — | | | | — | | | | — | | | Income Tax Expense (Benefit) | | | 6 | | | | 6 | | | | 5 | | | | | | | | | | | | | Net Income (Loss) | | $ | 9 | | | $ | 7 | | | $ | 9 | | | | | | | | | | | | |
Gas: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Gas Revenues | | $ | 128 | | | $ | 148 | | | $ | 146 | | Other Revenues | | | 5 | | | | 3 | | | | 4 | | | | | | | | | | | | | | | Total Operating Revenues | | | 133 | | | | 151 | | | | 150 | | | | | | | | | | | | | | | Purchased Gas Expense | | | 74 | | | | 90 | | | | 91 | | O&M | | | 25 | | | | 25 | | | | 26 | | Depreciation and Amortization | | | 9 | | | | 8 | | | | 8 | | Taxes Other Than Income Taxes | | | 4 | | | | 4 | | | | 3 | | | | | | | | | | | | | | | Total Other Operating Expenses | | | 112 | | | | 127 | | | | 128 | | | | | | | | | | | | | | | Operating Income | | | 21 | | | | 24 | | | | 22 | | Interest Expense | | | 6 | | | | 7 | | | | 7 | | Income Tax Expense | | | 6 | | | | 7 | | | | 6 | | | | | | | | | | | | | | | Net Income | | $ | 9 | | | $ | 10 | | | $ | 9 | | | | | | | | | | | | | | |
The table below shows UNS Gas’ therm sales and revenues for 2010, 2009 and 2008. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gas Sales (Millions of Therms) | | | Gas Revenues (Millions of Dollars) | | | | | | | | | | | | | 2010 vs. | | | | | | | | | | | | | | | 2010 vs. | | | | | | | | | | | | | | | | 2009 | | | | | | | | | | | | | | | 2009 | | | | | | | | 2010 | | | 2009 | | | % Chng* | | | 2008 | | | 2010 | | | 2009 | | | % Chng* | | | 2008 | | Retail Therm Sales: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Residential | | | 73 | | | | 70 | | | | 4.9 | % | | | 72 | | | $ | 89 | | | $ | 91 | | | | (2.2 | %) | | $ | 97 | | | Commercial | | | 30 | | | | 30 | | | | 2.0 | % | | | 31 | | | | 31 | | | | 32 | | | | (6.1 | %) | | | 36 | | | Industrial | | | 2 | | | | 2 | | | | (8.1 | %) | | | 2 | | | | 2 | | | | 2 | | | | (17.5 | %) | | | 2 | | | Public Authorities | | | 7 | | | | 6 | | | | 1.6 | % | | | 7 | | | | 6 | | | | 7 | | | | (7.2 | %) | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Retail Therm Sales | | | 112 | | | | 108 | | | | 3.7 | % | | | 112 | | | $ | 128 | | | $ | 132 | | | | (3.7 | %) | | $ | 143 | | | Transport | | | — | | | | — | | | | — | | | | — | | | | 3 | | | | 3 | | | | 5.2 | % | | | 4 | | | DSM | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | 1 | | | | 42.5 | % | | | — | | | Negotiated Sales Program (NSP) | | | 28 | | | | 30 | | | | (4.6 | %) | | | 32 | | | | 14 | | | | 13 | | | | 7.4 | % | | | 25 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Therm Sales | | | 140 | | | | 138 | | | | 1.9 | % | | | 144 | | | $ | 146 | | | $ | 149 | | | | (2.3 | %) | | $ | 172 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | | | | 2012 | | | 2011 | | | Amount | | | Percent(1) | | | 2010 | | Energy Sales, Therms (in millions): | | | | | | | | | | | | | | | | | | | | | Gas Retail Sales: | | | | | | | | | | | | | | | | | | | | | Residential | | | 67 | | | | 74 | | | | (7 | ) | | | (9.1 | %) | | | 73 | | Commercial | | | 29 | | | | 31 | | | | (2 | ) | | | (5.7 | %) | | | 30 | | Industrial | | | 2 | | | | 2 | | | | — | | | | (15.1 | %) | | | 2 | | Public Authorities | | | 6 | | | | 7 | | | | (1 | ) | | | (13.0 | %) | | | 7 | | | | | | | | | | | | | | | | | | | | | | | Total Gas Retail Sales | | | 104 | | | | 114 | | | | (10 | ) | | | (8.5 | %) | | | 112 | | Negotiated Sales Program (NSP) | | | 32 | | | | 26 | | | | 6 | | | | 21.2 | % | | | 28 | | | | | | | | | | | | | | | | | | | | | | | Total Gas Sales | | | 136 | | | | 140 | | | | (4 | ) | | | (3.02 | %) | | | 140 | | | | | | | | | | | | | | | | | | | | | | | Gas Revenues (in millions): | | | | | | | | | | | | | | | | | | | | | Retail Margin Revenues: | | | | | | | | | | | | | | | | | | | | | Residential | | $ | 38 | | | $ | 40 | | | $ | (2 | ) | | | (3.5 | %) | | $ | 39 | | Commercial | | | 11 | | | | 11 | | | | — | | | | 0.9 | % | | | 10 | | Public Authorities | | | 2 | | | | 2 | | | | — | | | | (4.5 | %) | | | 2 | | | | | | | | | | | | | | | | | | | | | | | Total Retail Margin Revenues (Non-GAAP)(2) | | | 51 | | | | 53 | | | | (2 | ) | | | (2.7 | %) | | | 51 | | Transport and NSP | | | 16 | | | | 17 | | | | (1 | ) | | | (4.2 | %) | | | 17 | | DSM | | | 1 | | | | 1 | | | | — | | | | — | % | | | 1 | | Retail Fuel Revenues | | | 60 | | | | 77 | | | | (17 | ) | | | (22.5 | %) | | | 77 | | | | | | | | | | | | | | | | | | | | | | | Total Gas Revenues (GAAP) | | $ | 128 | | | $ | 148 | | | $ | (20 | ) | | | (13.2 | %) | | $ | 146 | | | | | | | | | | | | | | | | | | | | | | | Weather Data: | | | | | | | | | | | | | | | | | | | | | Heating Degree Days | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | 19,026 | | | | 21,484 | | | | (2,458 | ) | | | (11.4 | %) | | | 21,188 | | 10-Year Average | | | 20,567 | | | | 20,759 | | | | NM | | | | NM | | | | 20,704 | |
| (1) | | | * | | Percent change calculated on un-rounded data;unrounded data and may not correspond exactly to data shown in table. |
K-61
The table below summarizes UNS Gas’ retail margin revenues and fuel revenues collected from customers.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | 2010 | | | 2009 | | | Amount | | | Percent* | | Gas Revenues (in millions): | | | | | | | | | | | | | | | | | Retail Margin Revenues: | | | | | | | | | | | | | | | | | | Residential | | $ | 39 | | | $ | 36 | | | $ | 3 | | | | 6.4 | % | | Commercial | | | 10 | | | | 10 | | | | — | | | | 4.8 | % | | Industrial | | | — | | | | — | | | | — | | | | (6.0 | %) | | Public Authorities | | | 2 | | | | 2 | | | | — | | | | 2.7 | % | | | | | | | | | | | | | | | Total Retail Margin Revenues (Non-GAAP)** | | $ | 51 | | | $ | 48 | | | $ | 3 | | | | 5.9 | % | | Transport and NSP | | | 17 | | | | 16 | | | | 1 | | | | 7.4 | % | | DSM | | | 1 | | | | 1 | | | | — | | | | 27.1 | % | | Retail Fuel Revenues | | | 77 | | | | 84 | | | | (7 | ) | | | (9.1 | %) | | | | | | | | | | | | | | | Total Gas Revenues (GAAP) | | $ | 146 | | | $ | 149 | | | $ | (3 | ) | | | (2.3 | %) | | | | | | | | | | | | | | |
| (2) | | | * | | Percent change calculated on un-rounded data; may not correspond to data shown in table. | | ** | | Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Retail ThermTotal Gas Revenues, which is determined in accordance with GAAP. UNS Gas believes that Retail Margin Revenues which is Totalexcludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Therm Sales less retail fuel revenues and revenues for DSM programs,Margin Revenues between periods provides useful information to investors.investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business. |
Retail therm sales in 2010 increasedduring 2012 decreased by 3.7%8.5% compared with 20092011 due in part to cooler weather.an 11.4% decrease in Heating degree days increased 4% compared with both 2009 and the ten-year average. As of December 31, 2010,Degree Days. Retail margin revenues decreased by 2.7%, or $2 million. UNS Gas had approximately 146,500149,000 retail customers, which represents an increase of less than 1% compared with the end of 2009. The increase in gas sales volumes as well as a 2% base rate increase that took effect in April 2010 resulted in a $3 million increase in retail margin revenues. 2011.UNS Gas supplies natural gas to some of its large transportation customers. Approximately one half of the margin earned on these NSP sales is retained by UNS Gas while the remainder benefits retail customers through a credit to the PGAPurchase Gas Adjustor (PGA) mechanism which reduces the gas commodity price. FACTORS AFFECTING RESULTS OF OPERATIONS New technological developments and the implementation of Gas EE Standards may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas. SeeItem 1. Business, UNS Gas, Rates and Regulation, Gas Utility Energy Efficiency Standards and Decoupling,above,for more information. 20102012 UNS Gas Rate Order In 2008,April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a LFCR mechanism to enable UNS Gas filedto recover lost fixed cost revenues as a general rate case requestingresult of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed cost revenues of less than $0.1 million in 2013, based on estimated lost retail therm sales from May through December 2012. The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills is offset by a $10 million increase. In March 2010,temporary credit adjustment to the ACC issued an order authorizing a $3 million, or 2%, base rate increase effective April 2010.PGA. SeeItem 1. Business, UNS Gas, expectsRates and Regulation, Purchased Gas Adjustor. Purchased Gas Adjustor SeeItem 1. Business, UNS Gas, Rates and Regulation, Purchased Gas Adjustor. Interest Rates UNS Gas is subject to file a newinterest rate case with the ACCrisk resulting from changes in 2011interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be required to recover increasing costs. pay higher rates of interest on borrowings under its revolving credit facility. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Interest Rate Risk, below. K-62
Fair Value Measurements UNS Gas’sGas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability or as a component of AOCI rather than in the income statement. See Note 11 for more information. LIQUIDITY AND CAPITAL RESOURCES UNS Gas’ capital requirements consist primarily of capital expenditures. In 2010,2012, capital expenditures were $10$16 million. UNS Gas expects operating cash flows to fund its future operating activities and a large portion of its construction expenditures. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements. Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contributions from UniSourceUNS Energy. The rate increase approved by the ACC in April 2010 covers some, but not all, of UNS Gas’ higher costs and capital investments. Operating Cash Flow and Capital Expenditures The table below provides summary cash flow information for UNS Gas. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Cash provided by (used in): | | | | | | | | | | | | | | Operating Activities | | $ | 18 | | | $ | 37 | | | $ | 3 | | | Investing Activities | | | (9 | ) | | | (13 | ) | | | (16 | ) | | Financing Activities | | | (11 | ) | | | — | | | | 1 | | | | | | | | | | | | | | Net Increase (Decrease) in Cash | | | (2 | ) | | | 24 | | | | (12 | ) | | Beginning Cash | | | 31 | | | | 7 | | | | 19 | | | | | | | | | | | | | | Ending Cash | | $ | 29 | | | $ | 31 | | | $ | 7 | | | | | | | | | | | | |
Gas: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Cash Provided By (Used In): | | | | | | | | | | | | | Operating Activities | | $ | 28 | | | $ | 32 | | | $ | 18 | | Investing Activities | | | (15 | ) | | | (12 | ) | | | (9 | ) | Financing Activities | | | (20 | ) | | | (11 | ) | | | (11 | ) | | | | | | | | | | | | | | Net Increase (Decrease) in Cash | | | (7 | ) | | | 9 | | | | (2 | ) | Beginning Cash | | | 38 | | | | 29 | | | | 31 | | | | | | | | | | | | | | | Ending Cash | | $ | 31 | | | $ | 38 | | | $ | 29 | | | | | | | | | | | | | | |
Operating Activities Operating cash flows decreased by $4 million in 20102012 when compared with 2011 due in part to the return of over-collected PGAa $4 million decrease in total gas costs to customers and cash outflows related to cash collateral deposited with gas supply and hedging counterparties. Forecastedrevenues.Investing Activities UNS Gas incurred capital expenditures of $16 million in 2012 compared with $13 million in 2011. Financing Activities Cash used for financing activities at UNS Gas are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | | | - Millions of Dollars - | | | UNS Gas | | $ | 12 | | | $ | 11 | | | $ | 14 | | | $ | 16 | | | $ | 22 | | | | | | | | | | | | | | | | | | |
was $9 million higher in 2012 than in 2011 due in part to an increase of $10 million in dividends paid to UNS Energy.UNS Gas/UNS Electric Revolver In November 2010, UNS Gas and UNS Electric amended and restated their existing credit agreement (UNS Gas/UNS Electric Revolver). The UNS Gas/UNS Electric Revolver was previouslyconsists of a $60$100 million unsecured revolving credit facility that matured in August 2011. Either borrower could borrow up to a maximumand revolving letter of $45 million so long as the combined amount borrowed by both companies did not exceed $60 million. As amended, the UNS Gas/UNS Electric Revolver is a $100 million unsecured facility that expires in November 2014.credit facility. Either company can borrow up to a maximum of $70 million soas long as the combined amount borrowed by both companies does not exceed $100 million. The UNS Gas/UNS Electric Revolver expires in November 2016.UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue LOCs to provide credit enhancement for its natural gas procurement and hedging activities. As of December 31, 2012, UNS Electric. Gas had no outstanding borrowings or LOCs under the UNS Gas/UNS Electric Revolver. K-63
The UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. As of December 31, 2010,2012, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver. UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue letters of credit to provide credit enhancement for its natural gas procurement and hedging activities. As of February 15, 2011, UNS Gas had no outstanding borrowings or letters of credit under the UNS Gas/UNS Electric Revolver.
Interest Rate Risk
UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be required to pay higher rates of interest on borrowings under its revolving credit facility. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Credit Risk, below.
UNS Gas has $100 million of 6.23% senior unsecured notes outstanding, of which $50 million maturematures in 20112015 and $50 million maturematures in 2015. These2026. All of UNS Gas’ senior unsecured notes are guaranteed by UES. The note purchase agreementagreements for UNS Gas restrictsrestrict transactions with affiliates, mergers, liens, restricted payments, and incurrence of indebtedness, andindebtedness. The agreements also containscontain a minimum net worth test. As of December 31, 2010,2012, UNS Gas was in compliance with the terms of its note purchase agreement. agreements.UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $7$5 million in short-term debt. Note Issuance In August 2011, UNS Gas issued $50 million of 5.39% senior unsecured notes. The proceeds were used to pay off $50 million of senior unsecured notes that matured in August 2011. Contractual Obligations UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased. UNS Gas has firm transportation agreements with capacity sufficient to meet its current load requirements. These contracts expire in various years between 20112013 and 2023.2024. These costs are passed through to UNS Gas’ customers via the PGA. UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers. These purchases and hedges are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month. UNS Gas hedged approximately 45%55% of its expected monthly consumption for the 2010/20112012/2013 winter season (November through March). Additionally, UNS Gas has approximately 38%37% of its expected gas consumption hedged for April through October 2011,2013, and 32%30% hedged for the period November 2011 through March 2012. 2013/2014 winter season. K-64
The following table displays UNS Gas’ contractual obligations as of December 31, 20102012 by maturity and by type of obligation. UNS Gas Contractual Obligations
- -Millions of Dollars-
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Payment Due in Years | | | | | | | | | | | | | | | | | | | | | | 2016 | | | | | | | | | Ending December 31, | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | and after | | | Other | | | Total | | | Long Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | 50 | | | $ | — | | | $ | — | | | $ | — | | | $ | 50 | | | $ | — | | | $ | — | | | $ | 100 | | | Interest | | | 6 | | | | 3 | | | | 3 | | | | 3 | | | | 4 | | | | — | | | | — | | | | 19 | | | Purchase Obligations — Fuel | | | 25 | | | | 10 | | | | 5 | | | | 4 | | | | 3 | | | | 19 | | | | — | | | | 66 | | | Pension & Other Post Retirement Obligations | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 82 | | | $ | 13 | | | $ | 8 | | | $ | 7 | | | $ | 57 | | | $ | 19 | | | $ | 1 | | | $ | 187 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
obligation: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Gas Contractual Obligations -Millions of Dollars- | | | | | | | | | | | | | | Payment Due in Years Ending December 31, | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018
and
after | | | Other | | | Total | | Long Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | — | | | $ | — | | | $ | 50 | | | $ | — | | | $ | — | | | $ | 50 | | | $ | — | | | $ | 100 | | Interest | | | 6 | | | | 6 | | | | 6 | | | | 3 | | | | 3 | | | | 24 | | | | — | | | | 48 | | Purchase Obligations—Fuel | | | 26 | | | | 13 | | | | 8 | | | | 6 | | | | 4 | | | | 17 | | | | — | | | | 74 | | Pension & Other Postretirement Obligations | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 33 | | | $ | 19 | | | $ | 64 | | | $ | 9 | | | $ | 7 | | | $ | 91 | | | $ | — | | | $ | 223 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
UNS Gas conducts certain of its gas procurement and risk management activities under agreements whereby UNS Gas may be required to post margin due to changes in contract values, a change in UNS Gas’ creditworthiness, or exposures exceeding credit limits provided to UNS Gas. As of December 31, 2010,2012, UNS Gas had not posted $3 million inany such credit enhancements. Dividends on Common Stock UNS Gas paid dividends to UniSourceUNS Energy of $20 million in 2012, and $10 million in both April 20102011 and February 2011.2010. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors. The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a)(i) no default or event of default exists and (b)(ii) it could incur additional debt under the debt incurrence test. As of December 31, 2010,2012, UNS Gas was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above. UNS ELECTRIC RESULTS OF OPERATIONS UNS Electric reportedhad net income of $10$17 million in 2010, $62012, compared with net income of $18 million in 2009 and $4 million in 2008. Results in 2010 include $2 million of after-tax income related to a settlement2011. As with APS for refunds related to transactions with the California Power Exchange. Similar to TEP’s operations, we expectTEP, UNS Electric’s operations to beare generally seasonal in nature, with peak energy demand occurring in the summer months. K-65
The table below provides summary financial information for UNS Electric. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Retail Electric Revenues | | $ | 183 | | | $ | 180 | | | $ | 183 | | | Wholesale Electric Revenues | | | 31 | | | | 5 | | | | 10 | | | Other Revenues | | | 2 | | | | 2 | | | | 2 | | | | | | | | | | | | | | Total Operating Revenues | | | 216 | | | | 187 | | | | 195 | | | | | | | | | | | | | | Purchased Energy and Fuel Expense | | | 148 | | | | 128 | | | | 143 | | | Other Operations and Maintenance Expense | | | 29 | | | | 25 | | | | 22 | | | Depreciation and Amortization | | | 15 | | | | 14 | | | | 14 | | | Taxes other than Income Taxes | | | 4 | | | | 4 | | | | 4 | | | | | | | | | | | | | | Total Other Operating Expenses | | | 196 | | | | 171 | | | | 183 | | | | | | | | | | | | | | Operating Income | | | 20 | | | | 16 | | | | 12 | | | | | | | | | | | | | | Total Other Income | | | 4 | | | | 1 | | | | 1 | | | Total Interest Expense | | | 7 | | | | 7 | | | | 7 | | | Income Tax Expense | | | 7 | | | | 4 | | | | 2 | | | | | | | | | | | | | Net Income | | $ | 10 | | | $ | 6 | | | $ | 4 | | | | | | | | | | | | |
Electric: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Retail Electric Revenues | | $ | 171 | | | $ | 182 | | | $ | 183 | | Wholesale Electric Revenues | | | 17 | | | | 6 | | | | 2 | | Other Revenues | | | 2 | | | | 2 | | | | 2 | | | | | | | | | | | | | | | Total Operating Revenues | | | 190 | | | | 190 | | | | 187 | | Fuel and Purchased Energy Expense | | | 101 | | | | 106 | | | | 109 | | O&M | | | 31 | | | | 27 | | | | 29 | | Depreciation and Amortization | | | 18 | | | | 17 | | | | 16 | | Taxes Other Than Income Taxes | | | 4 | | | | 4 | | | | 4 | | | | | | | | | | | | | | | Total Other Operating Expenses | | | 154 | | | | 154 | | | | 158 | | | | | | | | | | | | | | | Operating Income | | | 36 | | | | 36 | | | | 29 | | Other Income | | | — | | | | — | | | | 3 | | Interest Expense | | | 8 | | | | 7 | | | | 7 | | Income Tax Expense | | | 11 | | | | 11 | | | | 10 | | | | | | | | | | | | | | | Net Income | | $ | 17 | | | $ | 18 | | | $ | 15 | | | | | | | | | | | | | | |
The table below summarizes UNS Electric’s kWh sales and revenues for 2010, 2009 and 2008. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Sales — Millions of kWh | | | Electric Revenues — Millions of Dollars | | | | | | | | | | | | | 2010 vs. | | | | | | | | | | | | | | | 2010 vs. | | | | | | | | | | | | | | | | 2009 | | | | | | | | | | 2009 | | | | | | | | 2010 | | | 2009 | | | % Chng* | | | 2008 | | | 2010 | | | 2009 | | | % Chng* | | | 2008 | | Electric Retail Sales | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Residential | | | 820 | | | | 814 | | | | 0.8 | % | | | 822 | | | $ | 81 | | | $ | 82 | | | | (1.6 | %) | | $ | 92 | | | Commercial | | | 606 | | | | 608 | | | | (0.3 | %) | | | 620 | | | | 61 | | | | 63 | | | | (3.2 | %) | | | 70 | | | Industrial | | | 219 | | | | 197 | | | | 11.3 | % | | | 189 | | | | 18 | | | | 17 | | | | 7.3 | % | | | 17 | | | Mining | | | 210 | | | | 163 | | | | 28.0 | % | | | 30 | | | | 14 | | | | 12 | | | NM | | | | 3 | | | Other | | | 2 | | | | 2 | | | | (9.1 | %) | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 1,857 | | | | 1,784 | | | | 4.1 | % | | | 1,663 | | | $ | 174 | | | $ | 174 | | | | 0.3 | % | | $ | 182 | | | RES & DSM | | | — | | | | — | | | | — | | | | — | | | | 9 | | | | 6 | | | | 34.8 | % | | | 1 | | | Wholesale Sales | | | 707 | | | | 154 | | | NM | | | | 153 | | | | 31 | | | | 5 | | | NM | | | | 10 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Electric Sales | | | 2,564 | | | | 1,938 | | | | 32.3 | % | | | 1,816 | | | $ | 214 | | | $ | 185 | | | | 15.2 | % | | $ | 193 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | | | | 2012 | | | 2011 | | | Amount | | | Percent(1) | | | 2010 | | Energy Sales, kWh (in millions) | | | | | | | | | | | | | | | | | | | | | Electric Retail Sales: | | | | | | | | | | | | | | | | | | | | | Residential | | | 836 | | | | 828 | | | | 8 | | | | 1.0 | % | | | 820 | | Commercial | | | 614 | | | | 602 | | | | 12 | | | | 2.0 | % | | | 606 | | Industrial | | | 213 | | | | 221 | | | | (8 | ) | | | (3.5 | %) | | | 219 | | Mining | | | 91 | | | | 200 | | | | (109 | ) | | | (54.8 | %) | | | 210 | | Public Authorities | | | 2 | | | | 2 | | | | — | | | | (1.7 | %) | | | 2 | | | | | | | | | | | | | | | | | | | | | | | Total Electric Retail Sales | | | 1,756 | | | | 1,853 | | | | (97 | ) | | | (5.3 | %) | | | 1,857 | | | | | | | | | | | | | | | | | | | | | | | Electric Retail Revenues (in millions): | | | | | | | | | | | | | | | | | | | | | Retail Margin Revenues: | | | | | | | | | | | | | | | | | | | | | Residential | | $ | 32 | | | $ | 31 | | | $ | 1 | | | | 2.6 | % | | $ | 27 | | Commercial | | | 29 | | | | 29 | | | | — | | | | — | % | | | 27 | | Industrial | | | 9 | | | | 9 | | | | — | | | | — | % | | | 9 | | Mining | | | 7 | | | | 7 | | | | — | | | | (1.5 | %) | | | 6 | | Public Authorities | | | — | | | | — | | | | — | | | | (33.3 | %) | | | — | | | | | | | | | | | | | | | | | | | | | | | Total Retail Margin Revenues (Non-GAAP)(2) | | $ | 77 | | | $ | 76 | | | $ | 1 | | | | 0.8 | % | | $ | 69 | | Retail Fuel Revenues | | | 83 | | | | 99 | | | | (16 | ) | | | (15.9 | %) | | | 105 | | DSM and RES Revenues | | | 11 | | | | 7 | | | | 4 | | | | 71.2 | % | | | 9 | | | | | | | | | | | | | | | | | | | | | | | Total Retail Revenues (GAAP) | | $ | 171 | | | $ | 182 | | | $ | (11 | ) | | | (5.8 | %) | | $ | 183 | | | | | | | | | | | | | | | | | | | | | | | Weather Data: | | | | | | | | | | | | | | | | | | | | | Cooling Degree Days | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | 9,639 | | | | 9,092 | | | | 547 | | | | 6.0 | % | | | 8,821 | | 10-Year Average | | | 9,052 | | | | 8,994 | | | | NM | | | | NM | | | | 9,031 | |
| (1) | | | * | | Percent change calculated on un-rounded data;unrounded data and may not correspond exactly to data shown in table. |
K-66
The table below summarizes UNS Electric’s retail margin revenues and fuel revenues collected from customers.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | 2010 | | | 2009 | | | Amount | | | Percent* | | Electric Retail Revenues (in millions): | | | | | | | | | | | | | | | | | Retail Margin Revenues | | | | | | | | | | | | | | | | | | Residential | | $ | 22 | | | $ | 21 | | | $ | 1 | | | | 5.8 | % | | Commercial | | | 23 | | | | 22 | | | | 1 | | | | 2.7 | % | | Industrial | | | 7 | | | | 7 | | | | — | | | | 14.2 | % | | Mining | | | 5 | | | | 3 | | | | 2 | | | | 35.9 | % | | | | | | | | | | | | | | | Total Retail Margin Revenues (Non-GAAP)** | | $ | 57 | | | $ | 53 | | | $ | 4 | | | | 7.4 | % | | Retail Fuel Revenues | | | 117 | | | | 121 | | | | (4 | ) | | | (2.8 | %) | | DSM and RES Revenues | | | 9 | | | | 6 | | | | 3 | | | NM | | | | | | | | | | | | | | | | Total Retail Revenues (GAAP) | | | 183 | | | | 180 | | | | 3 | | | | 1.5 | % | | Electric Wholesale Revenues | | | 31 | | | | 5 | | | | 26 | | | NM | | | | | | | | | | | | | | | | Total Electric Revenues | | $ | 214 | | | $ | 185 | | | $ | 29 | | | | 15.2 | % | | | | | | | | | | | | | | |
| (2) | | | * | | Percent change calculated on un-rounded data; may not correspond to data shown in table. | | ** | | Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net ElectricTotal Retail Sales,Revenues, which is determined in accordance with GAAP. UNS Electric believes that Retail Margin Revenues which is Net Electricexclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Retail Sales less base fuel and PPFAC revenues, and revenues for DSM and REST programs,Margin Revenues between periods provides useful information to investors.investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business. |
In 2010,2012, retail kWh sales increaseddecreased by 4.1%5.3% compared with 2009. The increase is2011 due primarily to increased usage by a copper mining customer and a new industrial customer in UNS Electric’s service area. The increase in retail kWh sales, as well as a 4% base rate increase that took effect in October 2010, contributed to a $4 million increase in retail margin revenues in 2010 compared with 2009. large customer generating a portion of its own electricity needs.As of December 31, 2010,2012, UNS Electric had approximately 90,90092,000 retail customers, which was an increase of less than 1% compared with 2009. 2011.Wholesale revenues increased by $26$11 million in 20102012 due to an increase in short-term wholesale trading activity.sales. All revenues from wholesaleswholesale sales are credited against costs recovered through UNS Electric’s PPFAC. FACTORS AFFECTING RESULTS OF OPERATIONS2012 UNS Electric Rate Case In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric’s 2010 Rate Order. The key provisions of UNS Electric’s rate request include: an increase in non-fuel retail Base Rates of $7.5 million, or 4.6%, over adjusted test year revenues; an original cost rate base of approximately $217 million, which includes approximately $13 million of post test year adjustments for utility plant that is expected to be in service by June 30, 2013; a capital structure of approximately 47% debt and 53% equity; and a cost of long-term debt of 5.97% and return on equity of 10.50%. Lost Fixed Cost Recovery Mechanism UNS Electric proposed a LFCR mechanism that would allow UNS Electric to recover non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to compliance with the ACC’s Electric EE Standards and distributed generation requirements under the ACC’s RES. The LFCR is not a full decoupling mechanism and is not intended to recover lost fixed costs attributable to weather or economic conditions. Transmission Cost Adjustment Mechanism UNS Electric proposed a Transmission Cost Adjustment Mechanism (TCA) that would allow UNS Electric to recover, on a more timely basis, transmission costs associated with serving retail customers. UNS Electric’s proposed retail Base Rates include a transmission cost reflective of the current FERC rate. As the FERC rate changes, the TCA will result in a corresponding adjustment to the transmission component of retail Base Rates. Energy Efficiency Resource Plan UNS Electric proposed a three-year pilot program that would allow it to invest in energy efficiency programs in order to meet the ACC’s Electric EE Standards in the most cost-effective manner. Electric EE Standards investments would be considered regulatory assets and amortized over a four-year period. UNS Electric would earn a return on its investments and recover the return and amortization expense through the existing demand-side management surcharge. UNS Electric requested new rates be effective no later than January 1, 2014. We cannot predict the outcome of this proceeding or whether UNS Electric’s rate request will be adopted by the ACC in whole or in part. Competition New technological developments and the implementation of Electric EE Standards may reduce energy consumption by UNS Electric’s retail customers. UNS Electric’s customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on UNS Electric’s services. Self-generation by UNS Electric’s customers has not had a significant impact to date. SeeItem 1. Business, UNS Electric, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling,above,for more information. 2010 UNS Electric Rate Order
In September 2010, the ACC issued an order authorizing a $7.4 million, or 4%, base rate increase that took effect October 1, 2010. The ACC order requires UNS Electric to file a rate case no later than 12 month after the transfer of BMGS into rate base. SeeItem 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Orderfor more information. Power Purchase Agreement
In May 2008, UNS Electric and UED entered into a PPA to secure all the output.Large Customers One of the 90 MW gas-fired Black Mountain Generating Station (BMGS) from UED over a five-year term. The PPA is a tolling arrangement in which UNS Electric takes operational control of BMGS and assumes all risk of operation and maintenance costs, including fuel. A capacity charge and other costs associated with the PPA are recoverable through UNS Electric’s PPFAC. largest retail customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric’s retail rate structure and the customer’s peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer shut down its operations in UNS Electric’s service territory. As a result of these two events, we estimate UNS Electric’s non-residential retail margin revenues will be approximately $4 million lower in 2013 than in 2012. K-67
Renewable Energy Standard and Tariff As part of the 2010 UNS Electric Rate Order, the ACC approved a funding mechanism that will allow UNS Electric to use RES funds to recover operating costs, depreciation, property taxes and a return on its investment in the UNS Electric-owned solar projects until these costs could be recovered as part of UNS Electric’s base rates. Under these terms, UNS Electric expects to invest $5 million annually in 2011 through 2014 in solar PV projects. We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity. We expect the first project to be completed by the end of 2011 and UNS Electric to begin cost recovery through the RES in January 2012. For more information, seeSeeItem. 1Item 1. Business, UNS Electric, Rates and Regulation, 2010 Renewable Energy Standard and Tariff.Tariff Fair Value Measurements
UNS Electric’s exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives classified as Level 3 in the fair value hierarchy as a regulatory asset or a regulatory liability, or as a component of AOCI rather than in the income statement. See Note 11 for more information.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
In 2010, UNS Electric’s capital expenditures were $22 million. UNS Electric expects operating cash flows to fund a portion of its construction expenditures. Additional sources of funding future capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy.
Operating Cash Flow and Capital Expenditures
The table below provides summary cash flow information for UNS Electric.
| | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Cash provided by (used in): | | | | | | | | | | | | | | Operating Activities | | $ | 23 | | | $ | 37 | | | $ | 14 | | | Investing Activities | | | (23 | ) | | | (28 | ) | | | (30 | ) | | Financing Activities | | | 1 | | | | (8 | ) | | | 22 | | | | | | | | | | | | | | Net Increase (Decrease) in Cash | | | 1 | | | | 1 | | | | 6 | | | Beginning Cash | | | 10 | | | | 9 | | | | 3 | | | | | | | | | | | | | | Ending Cash | | $ | 11 | | | $ | 10 | | | $ | 9 | | | | | | | | | | | | |
Operating cash flows decreased in 2010 due in part to cash collateral received in 2009 from energy supply and hedging counterparties.
Forecasted capital expenditures for UNS Electric are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | | | - Millions of Dollars - | | | UNS Electric | | $ | 99 | | | $ | 51 | | | $ | 25 | | | $ | 30 | | | $ | 32 | | | | | | | | | | | | | | | | | | |
UNS Electric’s capital expenditure estimate for 2011 includes the purchase of BMGS from UED for approximately $62 million.
UNS Gas/UNS Electric Revolver
SeeUNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolverabove for description of UNS Electric’s unsecured revolving credit agreement.
. K-68
UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue letters of credit to provide credit enhancement for its energy procurement and hedging activities. At February 15, 2011, UNS Electric had $13 million outstanding under the UNS Gas/UNS Electric Revolver.
Interest Rate Risk
UNS Electric is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Electric may be required to pay higher rates of interest on borrowings under its revolving credit facility. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, CreditInterest Rate Risk, below. Fair Value Measurements UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11 for more information. LIQUIDITY AND CAPITAL RESOURCES Liquidity Outlook In 2012, UNS Electric’s capital expenditures were $38 million. In 2011, UNS Electric had capital expenditures of $96 million, which included the purchase of BMGS for $63 million from an affiliate, UED. Going forward, UNS Electric expects operating cash flows to fund a large portion of its construction expenditures. Additional sources of funding future capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy. Operating Cash Flow The table below provides summary cash flow information for UNS Electric: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Cash Provided By (Used In): | | | | | | | | | | | | | Operating Activities | | $ | 50 | | | $ | 43 | | | $ | 34 | | Investing Activities | | | (37 | ) | | | (93 | ) | | | (23 | ) | Financing Activities | | | (10 | ) | | | 44 | | | | (10 | ) | | | | | | | | | | | | | | Net Increase (Decrease) in Cash | | | 3 | | | | (6 | ) | | | 1 | | Beginning Cash | | | 5 | | | | 11 | | | | 10 | | | | | | | | | | | | | | | Ending Cash | | $ | 8 | | | $ | 5 | | | $ | 11 | | | | | | | | | | | | | | |
Operating Activities Cash provided by operating activities increased by $7 million in 2012 compared with 2011 due primarily to higher cash receipts from electric sales (net of fuel and purchased energy costs paid) partially offset by higher operations and maintenance costs. Investing Activities UNS Electric had capital expenditures of $38 million in 2012 compared with $96 million in 2011. Capital expenditures in 2011 included $63 million related to the acquisition of BMGS from UED. Financing Activities Cash provided by financing activities at UNS Electric in 2012 decreased by $54 million compared with 2011. Financing activities in 2012 included $10 million in dividends paid to UNS Energy. Financing activities in 2011 included the following items related to the acquisition of BMGS: the issuance of $30 million of long-term debt; a $20 million equity investment from UNS Energy; and a $6 million payment to UED. UNS Gas/UNS Electric Revolver SeeUNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver, above, for a description of UNS Electric’s unsecured revolving credit agreement. UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At December 31, 2012, UNS Electric had less than $1 million of outstanding LOCs under the UNS Gas/UNS Electric Revolver. Senior Unsecured Notes UNS Electric has $100 million of senior unsecured notes outstanding, consisting of $50 million of 6.50% notes due in 2015 and $50 million of 7.10% notes due in August 2023. The notes are guaranteed by UES. The note purchase agreement for UNS Electric contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. As of December 31, 2010,2012, UNS Electric was in compliance with the terms of its note purchase agreement. Under the note purchase agreement, UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt. UNS Electric Credit Agreement In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending in August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES. The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens, and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement. As of December 31, 2012, UNS Electric was in compliance with the terms of the credit agreement. Contractual Obligations UNS Electric Power Supply and Transmission Contracts UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. UNS Electric’s power purchase contracts and risk management activities are subject to master agreements that may require UNS Electric to post margin due to changes in contract values or if there has been a material change in UNS Electric’s creditworthiness, or exposures exceeding credit limits provided to UNS Electric. As of December 31, 2010,2012, UNS Electric had posted $13less than $1 million of such credit enhancements in the form of letters of credit. LOCs.UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. SeeItem 1. Business, UNS Electric’s transmission capacity agreements with WAPA provideElectric, Power Supply and Transmission, Transmission for annual rate adjustments and expire in 2011 and 2017. more information. K-69
The following table displays UNS Electric’s contractual obligations as of December 31, 20102012 by maturity and by type of obligation. obligation: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Electric Contractual Obligations -Millions of Dollars- | | | | | | | | | | | Payment Due in Years Ending December 31, | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018
and
after | | | Other | | | Total | | Long Term Debt: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | — | | | $ | — | | | $ | 80 | | | $ | — | | | $ | — | | | $ | 50 | | | $ | — | | | $ | 130 | | Interest | | | 7 | | | | 7 | | | | 7 | | | | 4 | | | | 4 | | | | 21 | | | | — | | | | 50 | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased Power | | | 55 | | | | 50 | | | | 14 | | | | 6 | | | | 5 | | | | 80 | | | | — | | | | 210 | | Transmission | | | 4 | | | | 2 | | | | 2 | | | | 1 | | | | — | | | | — | | | | — | | | | 9 | | Solar Project | | | 4 | | | | 4 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 8 | | Pension & Other Postretirement Obligations | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 6 | | | | 6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 71 | | | $ | 63 | | | $ | 103 | | | $ | 11 | | | $ | 9 | | | $ | 151 | | | $ | 6 | | | $ | 414 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SeeUNS ElectricEnergy Consolidated, Liquidity and Capital Resources, Contractual Obligations
- -Millions, above, for a description of Dollars- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Payment Due in Years | | | | | | | | | | | | | | | | | | | | | | 2016 | | | | | | | | | Ending December 31, | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | and after | | | Other | | | Total | | | Long Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Principal | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 50 | | | $ | 50 | | | $ | — | | | $ | 100 | | | Interest | | | 7 | | | | 7 | | | | 7 | | | | 7 | | | | 7 | | | | 27 | | | | — | | | | 62 | | | Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased Power | | | 47 | | | | 33 | | | | 35 | | | | — | | | | — | | | | — | | | | — | | | | 115 | | | Transmission | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | — | | | | — | | | | 10 | | | Pension & Other Post Retirement Obligations | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | Unrecognized Tax Benefits | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4 | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Contractual Cash Obligations | | $ | 57 | | | $ | 42 | | | $ | 44 | | | $ | 9 | | | $ | 59 | | | $ | 77 | | | $ | 4 | | | $ | 292 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
these obligations.Dividends on Common Stock As of December 31, 2010, UNS Electric has not paid $10 million of dividends to UniSource Energy.UNS Energy in 2012. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors. The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a)(i) no default or event of default exists and (b)(ii) it could incur additional debt under the debt incurrence test. As of December 31, 2010,2012, UNS Electric was in compliance with the terms of its note purchase agreement. SeeSenior Unsecured Notes, above. MILLENNIUM
RESULTS OF OPERATIONS
Millennium recorded a net loss of $13 million in 2010 compared with net income of $2 million in 2009. The net loss in 2010 resulted from several factors including the write-off of deferred tax assets and impairment losses on certain investments. Millennium’s results in 2009 included a $6 million pre-tax gain on the sale of an investment.
In December 2009 and December 2010, Millennium received interest payments of $0.5 million and $1 million, respectively on its $15 million note receivable from Mimosa.
FACTORS AFFECTING RESULTS OF OPERATIONS
Millennium Investments
Millennium is in the process of exiting its remaining investments which may yield gains or losses. At December 31, 2010, Millennium had assets of $22 million including a $15 million note receivable, land and buildings of $2 million, deferred tax assets of $2 million and a cash balance of $3 million.
In June 2009, Millennium finalized the sale of its 50% interest in Sabinas to Mimosa. The terms called for an upfront $5 million payment which Millennium received in January 2009. Other key terms of the transaction include a three-year, 6% interest-bearing, collateralized $15 million note from Mimosa due June 2012. In June 2009, Millennium recorded a $6 million pre-tax gain on the sale.
Millennium made $8 million in dividend payments to UniSource Energy in 2010, $3 million in 2009 and $25 million in 2008. All of these dividends represented return of capital distributions. Millennium’s remaining commitment for all of its investments combined is less than $1 million.
Millennium’s financial assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2010 consist of Cash Equivalents of $1 million, which are valued based on observable market prices and are comprised of the fair value of money market funds.
K-70
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. | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | - Millions of Dollars - | | | | | | | | | | | | | | | | | UniSource Energy Parent Company | | $ | (6 | ) | | $ | (5 | ) | | $ | (6 | ) | | UED | | | 4 | | | | 5 | | | | 3 | | | | | | | | | | | | | | Total Other Net Loss | | $ | (2 | ) | | $ | — | | | $ | (3 | ) | | | | | | | | | | | |
UniSourceyears: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | - Millions of Dollars - | | Millennium | | $ | 2 | | | $ | 2 | | | $ | (13 | ) | Other(1) | | | (2 | ) | | | (5 | ) | | | (6 | ) | | | | | | | | | | | | | | Total Other Net Loss | | $ | — | | | $ | (3 | ) | | $ | (19 | ) | | | | | | | | | | | | | |
| (1) | Includes parent company expenses, UED, and reconciling adjustments. |
Millennium Millennium’s net loss in 2010 resulted primarily from the write-off of deferred tax assets and impairment losses on certain investments. UNS Energy Parent Company UniSourceUNS Energy parent company expenses in 2012, 2011, and 2010 primarily include interest expense (net of tax) related to the UniSourceUNS Energy Convertible Senior Notes and the UniSourceUNS Credit Agreement. During the first six months of 2012, UNS Energy converted or redeemed all $150 million of outstanding Convertible Senior Notes. UED In its September 2010 UniSourceUNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other conditions. The FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for $63 million in July 2011. UED did not pay any dividends to UNS Energy had capital expendituresin 2012. In 2011, UED paid a $39 million dividend to UNS Energy, of $16which $28 million related to the constructionrepresented a return of a new headquarters building. UED
In 2010 and 2009, UED recorded after-tax income of $4 million and $5 million, respectively, related to the operation of BMGS.
capital. In 2010, UED paid a $9 million dividend to UniSourceUNS Energy, of which $4 million represented a return of capital distribution. capital.FACTORS AFFECTING RESULTS OF OPERATIONS Millennium Investments At December 31, 2012, Millennium had assets of $7 million including a cash balance of $4 million. In July 2011, Millennium sold a building for $3 million resulting in an after-tax gain of approximately $1 million. Note Receivable In 2009, UED paidMillennium sold an equity investment, receiving an upfront payment of $5 million in 2009 and a $30$15 million promissory note. Millennium received the remaining principal amount of $15 million in 2012. Dividends on Common Stock Millennium made $14 million in dividend payments to UniSourceUNS Energy which alsoin 2012, $3 million in 2011, and $8 million in 2010. All of these dividends represented a return of capital. In 2008, UED made distributions to UniSource Energy of less than $1 million. In September 2010, the ACC issued a rate order for UNS Electric that approved the purchase of BMGS by UNS Electric, pending certain conditions. UNS Electric expects to complete the purchase during 2011. SeeUNS Electric, Factors Affecting Results of Operations, Rates, 2010 UNS Electric Rate Order, above for more information.
CRITICAL ACCOUNTING POLICIES The preparation of the financial statements in accordance with U.S. Generally Accepted Accounting Principles (GAAP)GAAP requires management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. UniSourceUNS Energy considers the areas described in the Critical Accounting Policies as those that could yield materially different financial statement results based on application and interpretation of accounting policy, sincepolicy. Since making estimates and assumptions are subjective and complex, actual results could differ in subsequent periods. For additional information on UniSourceUNS Energy’s other significant accounting policies and recently issued accounting standards see Note 1. Accounting for Rate Regulation TEP, UNS Gas and UNS ElectricWe generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. However, sometimes these principles require special accounting treatment for regulated companies to show the effect of regulation. For example, the ACC can determine that TEP, UNS Gas or UNS Electricwe are allowed to recover certain expenses at a designated time in the future. In this situation, TEP, UNS Gas or UNS Electricwe defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when theywe are allowed to recover the costs from ratepayers.customers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until the rates charged to retail customers are reduced. TEP, UNS Electric and UNS GasWe evaluate regulatory assets each period and believe recovery is probable. K-71
If in the future a separable portion of those operations no longer meets theregulatory accounting criteria, stated in Note 1 the impact of not meeting the criteria would be material to the financial statements. If TEP, UNS Gas and UNS Electricwe stopped applying regulatory accounting to all itsour regulated operations, we would write off the related balances of regulatory assets as an expense and record the regulatory liabilities as revenue onin the income statement or in accumulated other comprehensive income (AOCI). Upon approval by the ACC of a settlement agreement in November 1999, TEP discontinued application of regulatory accounting for its generation operations. Beginning in December 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation related operations. Throughout the period 1999 — 2008, TEP continued to apply regulatory accounting to its transmission and distribution operations.
AOCI.At December 31, 2010,2012, regulatory liabilities net of regulatory assets totaled $12$50 million at TEP and $19$35 million at UNS Gas. Regulatory assets net of regulatory liabilities totaled $8$5 million at UNS Electric as of December 31, 2010. TEP, UNS Gas and UNS ElectricElectric. We regularly assess whether we can continue to apply regulatory accounting to cost-based rate regulated operations. Expectations of future recovery are generally based on orders issued by regulatory commissions and historical experience. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. See Note 2 for details regarding TEP, UNS Gas and UNS Electric regulatory assets and liabilities. 2.Accounting for Asset Retirement Obligations TEP is required to record the fair value of a liability for a legal obligation to retire ana long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. TEP incurs legal obligations as a result of environmental and other governmental regulations, contractual agreements and other factors. To estimate the liability, management must use significant judgment and assumptions in: determining whether a legal obligation exists to remove assets; estimating the probability of a future event for a conditional obligation; estimating the fair value of the cost of removal; estimating when final removal will occur; and estimating the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations. A liability for the fair value of ana legal asset retirement obligation (ARO) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to depreciation expense over itsthe useful life.life of related tangible assets, or when applicable the terms of a lease subject to ARO requirements. Upon retirement of the asset, TEP either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount. TEP identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations. The land on which these stations reside is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Additionally, TEP entered into ground lease agreements with certain land owners for the installation of photovoltaic (PV) assets. The provisions of the PV ground leases require TEP to remove the PV facilities upon expiration of the leases. The ARO related to the PV assets is estimated to be approximately $9 million at the retirement date. TEP also has certain environmental obligations at the Luna, San Juan, Sundt and Springerville Generating Stations. TEP estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt and Springerville environmental obligations will be approximately $48$159 million at the retirement date.dates. 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 that was placed into commercial operation in April 2006. SeeItem 1. — Business, TEP, Generating and Other Resources, Future Generating Resources. The new owners assumed asset retirement obligations to remove certain piping and evaporation ponds and to restore the ground to its original condition. TEP estimated its share of the obligations will be approximately $2 million at the date of retirement.
TEP has various transmission and distribution lines that operate under leases and rights-of-way that contain end dates and restrictiverestorative clauses. TEP operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As such, there are no legal obligations that require applicationAROs for these assets. However, TEP has identified in its distribution equipment certain AROs for which the accrual amount is less than $1 million at December 31, 2012. The total net present value of the accounting requirements for asset retirement obligations. ARO accrual was $14 million and reported in Deferred Credits and Other Liabilities—Other on the balance sheets at December 31, 2012. Nevertheless, included in the revenue requirement underlying the Company’sTEP’s retail electric service rates is a component of depreciation expense intended to enable TEP to accrue the future costs of retiring assets for which no legal obligations exists.exist. The accumulated balance of such$231 million at December 31, 2012 representing non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, is reported as a regulatory liability.was included in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrent on TEP’s balance sheet See Note 2 for details regarding our Asset Retirement Obligation. net cost of removal for interim retirements. K-72
UNS Gas and UNS Electric UNS Gas and UNS Electric have various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses. UNS Gas and UNS Electric operate their transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, UNS Gas and UNS Electric are not recognizing the cost of final removal of the transmission and distribution lines in the financial statements. The net present value of AROs related to the Generation and PV assets of UNS Electric was included in the Deferred Credits and Other Liabilities, Other on UNS Energy’s consolidated balance sheet on December 31, 2012. Both UNS Electric and UNS Gas accrue the future costs of retiring assets, for which no legal obligation exist through their own rate recovery mechanisms. The total accumulated balance of $36 million including UNS Electric’s and UNS Gas’ non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, was reported in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrent on UNS Energy’s consolidated balance sheet on December 31, 2012. See Note 2 for details regarding net cost of removal. 2.Pension and Other PostretirementRetiree Benefit Plan Assumptions TEP, UNS Gas, and UNS Electric record plan assets, obligations, and expenses related to pension and other postretirementretiree benefit plans based on actuarial valuations, which include key assumptions on discount rates, expected returns on plan assets, compensation increases, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally recorded or amortized over future periods. We believe that the assumptions used in recording obligations are reasonable based on prior experience, market conditions, and the advice of plan actuaries. Note 9 discusses the rate of return and discount rate used in the calculation of pension plan and other postretirementretiree plan obligations for TEP, UNS Gas, and UNS Electric. TEP is required to recognize the underfunded status of its defined benefit pension and other postretirementretiree plans as a liability. The underfunded status is the difference between the fair value of the plans’plans assets and the projected benefit obligation for pension plans or accumulated postretirementretiree benefit obligation for other postretirementretiree benefit plans. As the funded status, discount rates, and actuarial facts change, the liability will vary significantly in future years. TEP records the underfunded amount for its pension and other postretirementretiree obligations as a liability and a regulatory asset to reflect expected recovery of pension and other postretirementretiree obligations through rates. the rates charged to retail customers.At December 31, 2010,2012, TEP discounted its future pension plan obligations at 5.6%4.1% and its other postretirementretiree plan obligations at a rate of 5.2%3.8%. The discount rate for future pension plan and other postretirementretiree plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-ratedAA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point change in the discount rate would increase or decrease the projected benefit obligationProjected Benefit Obligation (PBO) by approximately $8$12 million and the 20112013 plan expense by $1 million. For TEP’s other postretirementretiree benefit plan, a 25-basis point change in the discount rate would increase or decrease the accumulated postretirement benefit obligationAccumulated Postretirement Benefit Obligation (APBO) by approximately $2 million. A 25-basis point change in the discount rate would impact plan expense by less than $1 million. TEP calculates the market-related value of pension plan assets using the fair value of the assets on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2010.2012. In establishing its assumption as to the expected return on assets, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward lookingforward-looking views of the financial markets. Pension expense decreases as the expected rate of return on assets increases. A 25-basis point change in the expected return on assets would impact pension expense in 20112013 by less than $1 million. TEP used a current year health care cost trend rate of 7.9%6.9% in valuing its postretirementretiree benefit obligation at December 31, 2010.2012. This rate reflects both market conditions and historical experience. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage point change in assumed health care cost trend rates would change the postretirementretiree benefit obligation by approximately $5 million and the related plan expense in 20112013 by less than $1 million. In 2011,2013, TEP will incur pension costs of approximately $14 million and other postretirementretiree benefit costs of approximately $12 million and $6 million, respectively.million. TEP expects to charge approximately $15 million of these costs to O&M expense, and $3$4 million to capital.capital, and $1 million to Other Expense. TEP expects to make pension plan contributions of $20$22 million in 2011.2013. In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA)VEBA trust to fund its other postretirementretiree benefit plan. In 2011,2013, TEP expects to make benefit payments to retirees under the postretirementretiree benefit plan of approximately $4 million and contributions to the VEBA trust of $2$3 million. K-73
UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 5.5%4.3% at December 31, 2010.2012. For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 20112013 pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2011,2013, of which less than $1 million will be capitalized. UNS Gas and UNS Electric expect to make combined pension plan contributions of $3$2 million in 2011. 2013.UNS Gas and UNS Electric discounted their other postretirementretiree plan obligations using a rate of 5.2%3.8% at December 31, 2010.2012. UNS Gas and UNS Electric will record postretirementretiree medical benefit expense and make benefit payments to retirees under the postretirementretiree benefit plan of less than $1$0.5 million in 2011. 2013.Accounting for Derivative Instruments Trading Activities and Hedging Activities Commodity Derivative Contracts TEP, UNS Gas, and UNS Electric enter into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, or one year, within established limits to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. TEP and UNS Gas enter into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted summer gas purchases. As a result of the 2008 TEP Rate Order, TEP is permitted to recover in the PPFAC, prudent hedging transactions in a similar manner as UNS Electric and UNS Gas in their PPFAC and PGA, respectively. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability on the balance sheets of TEP, UNS Gas, and UNS Electric. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC or PGA mechanisms. Interest Rate Swaps
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to LIBOR on the Springerville Common Facilities Lease. TEP entered into swaps that had the effect of converting approximately $30 million and $35 million of variable rate lease debt payments for the Springerville Common Facilities Lease to a fixed rate from May 2009 through July 1, 2014, and June 2006 through January 2, 2020, respectively. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable rate industrial development bonds to a fixed rate from September 2009 through September 2014. See Note 6 for additional details regarding interest rate swaps.
Commodity Cash Flow Hedge
TEP hedges the cash flow risk associated with a six-year power wholesale supply agreement using a six-year power purchase swap agreement. Unrealized gains and losses are recorded in AOCI.
The market prices used to determine fair values for TEP,TEP’s, UNS GasGas’, and UNS Electric’s derivative instruments at December 31, 2010,2012, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value. TEP, UNS Gas, and UNS Electric manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty. Interest Rate Swaps TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to LIBOR on the Springerville Common Facilities Lease. As of December 31, 2012, approximately $25 million of variable rate lease debt for the Springerville Common Facilities Lease had been hedged through an interest rate swap agreement through July 1, 2014, and $34 million had been hedged through January 2, 2020. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable-rate IDBs to a fixed rate from September 2009 through September 2014. In August 2011, UNS Electric entered into an interest rate swap with the effect of converting the variable interest rate for their $30 million term loan to a fixed rate from August 2011 through August 2015. See Note 6. Commodity Cash Flow Hedge TEP hedges the cash flow risk associated with a six-year power wholesale supply agreement using a six-year power purchase swap agreement. Unrealized gains and losses are recorded in AOCI. See Note 1 for additional details regarding Cash Flow Hedges. K-74
cash flow hedges. SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk. Unbilled Revenue — TEP, UNS Gas and UNS Electric TEP, UNS Gas, and UNS Electric’s retail revenues, which are recognized in the period that electricity or energy is delivered and consumed by customers, include unbilled revenue based on an estimate of MWh/therms delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated MWh/therms delivered to the MWh/therms billed to TEP, UNS Gas and UNS Electric’sour retail customers. The excess of estimated MWh/therms delivered over MWh/therms billed is then allocated to the retail customer classes based on estimated usage by each customer class. TEP, UNS Gas and UNS ElectricWe then record revenue for each customer class based on the various bill ratesRetail Rates for each customer class. Due to the seasonal fluctuations of TEP and UNS Electric’s actual load, the unbilled revenue amount increases during the spring and summer and decreases during the fall and winter. Conversely the unbilled revenue amount for UNS Gas sales increases during the fall and winter and decreases during the spring and summer. A provision for uncollectible accounts is recorded as a component of operations and maintenanceO&M expense. Plant Asset Depreciable Lives — TEP, UNS Gas and UNS Electric TEP, UNS Gas, and UNS Electric have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. Useful life of plant assets is further detailed in Note 5. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded onin the income statement.statements. The estimated useful lives andACC approves depreciation rates presently used to calculate depreciation expense for electricall generation and distribution assets for TEP, UNS Gas and UNS Electric have been approved by the ACC in prior rate decisions.assets. Depreciation rates for such assets cannot be changed without ACC approval. For current approved ACC depreciation rates see Note 1. Depreciation rates for electricTEP and UNS Electric transmission assets fall underare subject to the jurisdiction of the FERC. In January 2010, TEP obtained an updated depreciation study which indicated that its transmission assets’ depreciable lives should be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010, which have the effect of reducing depreciation expense by approximately $14 million annually. Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. Using the income tax rates in effect on the balance sheet date,We account for this difference is accounted for by recording deferred income tax assets and liabilities onusing the effective income tax rate at our balance sheets. sheet date.Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income and deductions as reported in the consolidated tax return. A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. At December 31, 2010, UniSource2012, UNS Energy had a $7 million valuation allowance. The valuation allowanceallowances related to unregulated investments’ losses are treated as capital losses for income tax purposes. If UniSourceUNS Energy incurs additional capital losses in the future, a valuation allowance will be recorded against the deferred tax asset unless management can identify future capital gains to offset the losses. For additional information see Note 8. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The following recently issued accounting standards are not yet reflected in the UniSource Energy and TEP financial statements:
The Financial Accounting Standards Board (FASB) issued authoritative guidance that will require entities to disclose both gross and net information about instruments and transactions eligible for multiple deliverable revenue arrangements that provides another alternative for determiningoffset in the selling pricestatement of deliverablesfinancial position as well as instruments and eliminates the residual method of allocating consideration.transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013 and do not expect this pronouncement requires expandedto have a material impact on our disclosures. The FASB issued authoritative guidance which amends the guidance for impairment testing of indefinite-lived intangible assets. An entity will have the option to perform qualitative andanalysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative disclosures and is effective for revenue arrangements entered into after January 1, 2011. After adoptingimpairment test. We will be required to comply in the first quarter of 2013; however, we do not expect this guidancepronouncement to have a material impact on January 1, 2011, TEP and UNS Electric will continueour financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to assign costscomply with renewable resources requirements. The FASB decided to both renewable energy credits and energy when purchased through a renewable purchased power agreement. K-75
The Financial Accounting Standards Board issued amendments that require some new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and clarify some existing disclosure requirements about fair value measurements. Disclosures about purchases, sales, issuances, and settlementsthe income statement line items affected by the reclassification. This information can be presented parenthetically on the face of the financial statements or in the rollforward of activityfootnotes. We plan to present this information in Level 3 fair value measurements are effective for interim and annual reporting periods beginning January 1, 2011.a footnote. We will incorporate these new disclosuresbe required to comply in the first quarter of 2013 and do not expect this decision to have a material impact on our March 31, 2011 financial statements.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UniSourceUNS Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UniSourceUNS Energy or TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts”, “projects”, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UniSourceUNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UniSourceUNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report. Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in Item 1A. Risk Factors,Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other parts of this report: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of the company’sour pension and other postretirementretiree benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; cyber attacks or challenges to our information security; and the performance of TEP’s generating plants. | | | ITEM 7A. | | — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 7A. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKMarket Risks We are exposed to various forms of market risk. Changes in interest rates, returns on marketable securities, and changes in commodity prices may affect our future financial results. For additional information concerning risk factors, including market risks, seeSafe 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 and the fuel and power procurement activities at TEP, UNS Gas, and UNS Electric. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, and generation operations departments of UniSourceUNS Energy. To limit TEP, UNS Gas, and UNS Electric’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP, UNS Gas, and UNS Electric’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits. K-76
Interest Rate Risk TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. AtTEP had $215 million at December 31, 2010 and December 31, 2009, TEP had $365 million and $459 million2012 in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest rate payable under the indentures for these bonds is 10% on the 2010 Coconino A Bonds and the 2008 Pima B Bondsfor $37 million of variable rate IDBs, and 20% on the other $329remaining $178 million in variable rate IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.26%0.17% in 20102012 and 0.41%0.18% in 2009.2011. The average weekly interest rate ranged from 0.17%0.06% to 0.39%0.26% in 20102012 and 0.25%0.05% to 0.79%0.34% during 2009.2011. Although short-term interest rates have been relatively low and stable in 20102012 and 2009,2011, TEP may still be subject to volatility in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve month period, would result in a decrease in TEP’s pre-tax net income of approximately $3$2 million. TEP manages its exposure to variable interest rate risk by entering into interest rate swaps and financing transactions to maintain a long-term debtrebalance its mix of approximately one-third variable rate and two-thirds fixed rate. To maintain this balance, rate long-term debt. TEP has fixed-for-floating interest rate swaps in place to hedge floating rate interest rate risk associated with $59 million of Springerville Common Facilities lease debt and $50 million of its variable rate IDBs. TEP also entered into the following transactions to change its mix of fixed and floating rate debt. TEP issued $250 million of 5.15% fixed-rate unsecured notes in 20092011, and 2010: In 2009, TEP entered into an interest rate swap that hadused a portion of the effect of converting $50proceeds to repurchase $150 million of variable rate industrial revenue bondsIDBs to a fixed rate of 2.4% from 2009 to 2014;hold in treasury.
In January 2010, TEP converted the interest rate on its $130 million principal amount of 2008 Pima B BondsIDBs from a variable rate to a fixed rate of 5.75% through maturity in 2029; and2029. After issuing $100 million in new fixed rate 2010 Pima A Bonds at a rate of 5.25% in October 2010, TEP refinanced $36.7 million of its 7.125% fixed rate 1997 Coconino A Bonds with a like principal amount of 2010 Coconino A Bonds at a variable rate.
As a result of these transactions, TEP’s un-hedged variable rate debt comprised approximately 31%13% of its total long-term debt at December 31, 2010. Capital Lease Debt
At December 31, 20102012 and 2009, TEP’s debt also included variable rate lease debt totaling $63 million and $65 million, respectively, related to its Springerville Common Facilities Leases. The notes underlying the leases mature in June 2017 and January 2020. Interest is payable at six-month LIBOR plus an applicable spread. The applicable spread was 1.625%15% at December 31, 2010 and December 31, 2009.
Interest Rate Swaps
2011.In June 2006 and May 2009, TEPAugust 2011, UNS Electric entered into a fixed-for-floating interest rate swapsswap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount through August 2015 to hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows: | | | | | | | | | | | Outstanding at Dec. 31, 2010 | | Fixed Rate | | | LIBOR Spread | | | $35 million | | | 5.77 | % | | | 1.625 | % | | $22 million | | | 3.18 | % | | | 1.625 | % | | $7 million | | | 3.32 | % | | | 1.625 | % |
its $30 million credit agreement. K-77
To adjust the value of TEP’s interest rate swaps, classified as a cash flow hedge,hedges, to fair value in Other Comprehensive Income (Loss), TEP recorded the following net unrealized gains (losses): | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | - In Millions- | | | Unrealized Gains (Losses) | | $ | (8 | ) | | $ | 1 | | | $ | (5 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -In Millions- | | Unrealized Gains (Losses) | | $ | (2 | ) | | $ | (5 | ) | | $ | (8 | ) |
Revolving Credit Facilities UniSourceUNS Energy, TEP, UNS Gas, and UNS Electric are also subject to interest rate risk resulting from changes in interest rates on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on the basis of a spread over LIBOR or an Alternate Base Rate. With the recent disruptions in the financial markets, the spread between LIBOR and other similar maturity short-term rates, such as U.S. Treasury securities, has been significantly higher than historical relationships. As a result, UniSourceUNS Energy, TEP, UNS Gas, and UNS Electric may experience significant volatility in the rates paid on LIBOR borrowings under their revolving credit facilities. Marketable Securities Risk UniSourceUNS Energy has a short-term investment policy which governs the investment of excess cash balances by UniSourceUNS Energy and its subsidiaries. We review this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio. As of December 31, 2010, UniSource2012, UNS Energy’s short-term investments consisted of liquid, highly-rated and liquid money market funds commercial paper, and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the balance sheet. At December 31, 2010 and 2009, TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $112$32 million at December 31, 2012, and $140$50 million respectively.at December 31, 2011. At December 31, 2010 and 2009,2012, the carrying value exceeded fair value by $13 million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future rates charged to retail customers. At December 31, 2011, the fair value exceeded the carrying value by $7 million and $8 million, respectively.$16 million. These securities represent TEP’s investments in lease debt and equity underlying certain of TEP’s capital lease obligations. Changes in the fair value of such debt securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity. TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, and coal. Beginning January 1, 2009, thisThis risk is mitigated through a PPFAC mechanism which fully recovers the actual retail fuel and purchased power costs incurred on a timely basis from TEP’s retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, TEP is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference. Purchases and Sales of Energy To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future delivery period. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified market approach to provide a balance between long-term, mid-term, and spot energy sales. TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve requirements, and account for other contracts and resource contingencies. TEP also enters into limited forward purchases and sales to optimize its resource portfolio and take advantage of locationalgeographical differences in price. These positions are managed on both a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk Management Committee. For example, the risk management policies provide that TEP should not take a short physical position in the third quarter and must have owned generation backing up all physical forward sales positions at the time the sale is made. TEP’s risk management policies also restrict entering into forward positions with maturities extending beyond the end of the next calendar year except for approved hedging purposes. K-78
TEP’s risk management policies also allow for financial purchases and sales of energy subject to specified risk parameters established and monitored by the Risk Management Committee. These include financial trades in a futures account on an exchange, with the intent of optimizing market opportunities. The majority of TEP’sTEP enters into forward contracts are considered to be “normal purchases and sales” of electric energy and are therefore not accounted for as derivatives. TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered. From time to time, however, TEP also enters into forward contracts that meet the definition of a derivative.are not considered to be “normal purchases and sales” and therefore are accounted for as derivatives. When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other Southwestern U.S. trading hubs. TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market. Long-Term Wholesale Sales Prior to June 1, 2011, under the terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 1, 2011 to December 31, 2011, SRP was required to purchase 73,000 MWh per month. From January 1, 2012 through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on the Palo Verde Market Index. As of February 13, 2013, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2013 was $36 per MWh. The chart below summarizes the annual change in pre-tax income if the market price of on-peak power on the Palo Verde Market Index changes by $5 per MWh. | | | | | | | | | | | | Change in Per MWh Price | | | | | $5 Increase | | | $5 Decrease | | | | | -Millions of Dollars- | | Change in Pre-Tax Income | | $ | 3 | | | $ | (3 | ) |
Natural Gas TEP is also subject to commodity price risk from changes in the price of natural gas. In addition to energy from its coal-fired facilities, TEP typically uses power purchases, supplemented by generation from its gas-fired units to meet the summer peak demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are price indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed power purchases, and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets. As required by fair value accounting rules, for the year ended December 31, 2010,2012, TEP considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for TEP was less than $1$0.5 million at December 31, 2010. 2012.To adjust the value of its commodity derivatives to fair value in Regulatory Assetsregulatory assets or Regulatory Liabilities,regulatory liabilities, TEP recorded the following net unrealized gains (losses): | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | - In Millions- | | | Unrealized Gains (Losses) | | $ | 4 | | | $ | 11 | | | $ | (19 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Unrealized Gains (Losses) | | $ | 6 | | | $ | (2 | ) | | $ | 4 | |
The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts. | | | | | | | | | | | | | | | | | | | | | Unrealized Gain (Loss) of TEP’s | | | | | Hedging and Trading Activities | | | | | - Millions of Dollars - | | | | | | | | | | | | Total | | | | | Maturity 0 – 6 | | | Maturity 6 – 12 | | | Maturity | | | Unrealized | | | Source of Fair Value at Dec. 31, 2010 | | months | | | months | | | over 1 yr. | | | Gain (Loss) | | | Prices actively quoted | | $ | (3 | ) | | $ | (3 | ) | | $ | (3 | ) | | $ | (9 | ) | | Prices based on models and other valuation methods | | | — | | | | 1 | | | | 2 | | | | 3 | | | | | | | | | | | | | | | | | Total | | $ | (3 | ) | | $ | (2 | ) | | $ | (1 | ) | | $ | (6 | ) | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Unrealized Gain (Loss) of TEP’s Hedging Activities | | | | | - Millions of Dollars - | | Source of Fair Value at Dec. 31, 2012 | | Maturity 0 – 6
months | | | Maturity 6 – 12
months | | | Maturity
over 1 yr. | | | Total
Unrealized
Gain (Loss) | | Prices Actively Quoted | | $ | (2 | ) | | $ | (2 | ) | | $ | — | | | $ | (4 | ) | Prices Based on Models and Other Valuation Methods | | | 1 | | | | 1 | | | | — | | | | 2 | | | | | | | | | | | | | | | | | | | Total | | $ | (1 | ) | | $ | (1 | ) | | $ | — | | | $ | (2 | ) | | | | | | | | | | | | | | | | | |
Sensitivity Analysis of Derivatives TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. Beginning in December 2008, as a result of the 2008 TEP Rate Order, which permits the recovery of prudent costs associated with hedging contracts through the PPFAC,records unrealized gains and losses are recorded as either a regulatory asset or regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%. | | | | | | | | | | | | - Millions of Dollars - | | Change in Market Price As of December 31, 2012 | | 10% Increase | | | 10% Decrease | | Non-Cash Flow Hedges | | | | | | | | | Forward Power Sales and Purchase Contracts | | $ | 1 | | | $ | (1 | ) | Forward Gas Swaps and Collars Contracts | | | 2 | | | | (2 | ) |
K-79
| | | | | | | | | | | | | - Millions of Dollars - | | | Change in Market Price As of December 31, 2010 | | 10% Increase | | | 10% Decrease | | Non-Cash Flow Hedges | | | | | | | | | | Forward power sales and purchase contracts | | $ | — | | | $ | — | | | Gas swap agreements | | | 3 | | | | (3 | ) | | | | | | | | | | | Cash Flow Hedges | | | | | | | | | | Forward power sales and purchase contracts | | $ | 1 | | | $ | (1 | ) | | Gas swap agreements | | | — | | | | — | |
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 beis 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, thisThis range would be from $24$19.30 to $30$26.15 per ton. TEP estimates its future minimum annual payments under this contract to be $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 $7 million in 2011. TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for Sundt Unit 4 on the spot market and can supply that unit with natural gas when the price is competitive with coal. Coal burned at Sundt Unit 4 represents less than 10% of TEP’s total coal consumption. The long-term rail contract for Sundt Unit 4 is in effect untilIn December 2011, the earliest oftake-or-pay obligations under a coal transportation agreement previously effective through December 2015 or the remaining life of Sundt Unit 4. 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 makewere terminated. As a minimum payment of $1 million. In 2010,result, TEP was notifiedrelieved of the closure of the mine that has served as the primary source of coal transported under that contract. The alternate sources identified in the contract are not viable alternatives for TEP. Therefore we recorded a minimum take-or-pay transportation accrual of $4 million for the remaining minimum paymentsobligation recognized under this contract in December 2010. We will recover the minimum transportation charges via the PPFAC when they are paid annually. TEP reversed a $4 million regulatory asset.TEP also participates in jointly-owned generating facilities at Four Corners, Navajo, and San Juan, where coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations. The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an estimated average annual cost of $21 million for the next five years. SeeItem 7. —– Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSourceUNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations and Note 4 of Notes to Consolidated Financial Statements — Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments. 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 ratesRetail Rates to recover the actual costs of gas and transportation. UNS Gas further reduces this risk by purchasing forward fixed price contracts or entering into financial gas swaps for a portion of its projected gas needs under its Price Stabilization Plan. UNS Gas purchases at least 45% of its estimated gas needs in this manner. As required by fair value accounting rules, for the year ended December 31, 2010,2012, UNS Gas considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Gas was less than $1$0.5 million at December 31, 2010. 2012. K-80
To adjust the value of its commodity derivatives to fair value in Regulatory Assetsregulatory assets or Regulatory Liabilities,regulatory liabilities, UNS Gas recorded the following net unrealized gains (losses): | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | - In Millions - | | | Unrealized Gains (Losses) | | $ | (2 | ) | | $ | 6 | | | $ | (13 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Unrealized Gains (Losses) | | $ | 6 | | | $ | 1 | | | $ | (2 | ) |
For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $3$2 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $3$2 million. UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated through a PPFAC mechanism which fully recoversallows for the recovery of costs incurred on a timely basis. As part of the May 2008 ACC order, a new PPFAC mechanism took effect on June 1, 2008.from retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, UNS Electric is exposed to the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference. UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. UNS Electric estimates its future minimum payments under these contracts to be $47 million in 2011, $33 million in 2012, and $35 million in 2013, based on natural gas prices at the date of the contracts. Because a portion of the costs under these contracts will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under these new contracts on a timely basis. For UNS Electric’s forward power sales and purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $9$5 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $9$5 million. UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchased power agreements with fixed price contracts. In addition, UNS Electric hedges a portion of its anticipated natural gas exposure from plant fuel. UNS Electric currently has approximately 53%45% of this aggregate summer exposure hedged for the summer of 2010.2013. UNS Electric will satisfy its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets. As required by fair value accounting rules, for the year ended December 31, 2012, UNS Electric considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment required for UNS Electric was less than $1$0.5 million at December 31, 2010. 2012.To adjust the value of its commodity derivatives to fair value in Regulatory Assetsregulatory assets or Regulatory Liabilities,regulatory liabilities, UNS Electric recorded the following net unrealized gains (losses): | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | �� | | | | - In Millions - | | | Unrealized Gains (Losses) | | $ | (2 | ) | | $ | 12 | | | $ | (33 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Unrealized Gains (Losses) | | $ | 9 | | | $ | (1 | ) | | $ | (2 | ) |
For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net losses reported as a regulatory asset of $1 million, while a 10% increase in market prices would result in a decrease in unrealized net losses reported as a reduction in regulatory assets of $1 million. K-81
Credit Risk UniSourceUNS Energy is exposed to credit risk in its energy-related marketing and trading activities related to potential nonperformancenon-performance by counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. We calculate counterparty credit exposure by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. A positive number means that we are exposed to the creditworthiness of our counterparties. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or a letter of credit. Conversely, a negative exposure means that a counterparty is exposed to the creditworthiness of TEP, UNS Gas, or UNS Electric. If such exposure exceeds credit limits or collateral thresholds, we may be required to post collateral in the form of cash or letters of credit. During the last three years, financial institution counterparties have become active participants in the wholesale energy markets. LOCs.TEP, UNS Gas, and UNS Electric each have entered into short-term and long-term transactions with several financial institution counterparties with terms of one month through five years. Due to the recent turmoil in the financial and credit markets, we have been closely monitoring our transactions with financial institutions. As of December 31, 2010,2012, the combined credit exposure to TEP, UNS Gas, and UNS Electric from financial institution counterparties was approximately $4$3 million. As of December 31, 2010,2012, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $20$15 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $5$3 million. TEP maintains a margin account with a broker TEP’s total exposure to support certain risk management and trading activities. non-investment grade counterparties was $3 million.At December 31, 2010,2012, TEP hadposted no cash collateral and less than $1 million in that margin account. At December 31, 2010, TEP had $1 million inLOCs as credit enhancements posted with its counterparties, and did not hold any collateral from its counterparties. UNS Gas is subject to credit risk from non-performance by its supply and hedging counterparties to the extent that these contracts have a mark-to-market value in favor of UNS Gas. As of December 31, 2010,2012, UNS Gas had purchased under fixed price contracts approximately 32%30% of its expected consumption for the 2011/20122013/2014 winter season. At December 31, 2010,2012, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts.As of December 31, 2010,2012, UNS Gas had posted $3 million inno cash collateral and no letters of creditLOCs as credit enhancements with its counterparties, and did not hold any collateral from counterparties. UNS Electric enters into energy purchase agreements as well as gas hedging contracts to hedge the risk in its gas-indexed power purchase agreements. To the extent that such contracts have a positive mark-to-market value, UNS Electric is exposed to credit risk under those contracts. At December 31, 2010,2012, UNS Electric had $3less than $1 million in credit exposure under such contracts. As of December 31, 2010,2012, UNS Electric had posted $13less than $1 million in letters of creditLOCs and no cash collateral as credit enhancements with its counterparties, and had not collected any collateral margin from its counterparties. | | | ITEM 8. | | — CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
ITEM 8. – CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAUniSource Energy — UNS Energy—Management’s Report on Internal Controls Over Financial Reporting
UniSource Energy Corporation’sUNS Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of the UniSource Energy Corporation’sUNS Energy’s internal control over financial reporting as of December 31, 2010.2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control —– Integrated Framework. Based on management’s assessment using those criteria management has concluded that, as of December 31, 2010, UniSource Energy Corporation’s2012, UNS Energy’s internal control over financial reporting was effective. K-82
The effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report in Item 8 of this Annual Report on Form 10-K.
Tucson Electric Power Company — Company—Management’s Report on Internal Controls Over Financial Reporting Tucson Electric Power Company’sTEP’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 Tucson Electric Power Company’sTEP’s internal control over financial reporting as of December 31, 2010.2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inCOSO Internal Control —– Integrated Framework. Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2010, Tucson Electric Power Company’s2012, TEP’s internal control over financial reporting was effective. K-83
Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of
UniSource UNS Energy Corporation: In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of UniSourceUNS Energy Corporation and its subsidiaries at December 31, 20102012 and December 31, 2009,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010,2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedulesschedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2012, based on criteria established inInternal Control — Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules,schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls OverControl over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules,schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. | | | | /s/ PricewaterhouseCoopers LLP | PricewaterhouseCoopers LLP
Phoenix, Arizona
March 1, 2011 | | February 26, 2013 |
K-84
Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholder of
Tucson Electric Power Company: In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 20102012 and 2009,December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010,2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. | | | | /s/ PricewaterhouseCoopers LLP | PricewaterhouseCoopers LLP
Phoenix, Arizona
March 1, 2011
| | February 26, 2013 |
K-85
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | - Thousands of Dollars - | | | | | (Except Per Share Amounts) | | Operating Revenues | | | | | | | | | | | | | | Electric Retail Sales | | $ | 1,051,002 | | | $ | 1,047,619 | | | $ | 988,612 | | | Provision for Rate Refunds — CTC Revenue | | | — | | | | — | | | | (58,092 | ) | | | | | | | | | | | | | Net Electric Retail Sales | | | 1,051,002 | | | | 1,047,619 | | | | 930,520 | | | Electric Wholesale Sales | | | 151,673 | | | | 130,904 | | | | 248,855 | | | California Power Exchange (CPX) Provision for Wholesale Refunds | | | (2,970 | ) | | | (4,172 | ) | | | — | | | Gas Revenue | | | 141,036 | | | | 144,609 | | | | 163,977 | | | Other Revenues | | | 112,936 | | | | 77,741 | | | | 66,714 | | | | | | | | | | | | | Total Operating Revenues | | | 1,453,677 | | | | 1,396,701 | | | | 1,410,066 | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | Fuel | | | 296,980 | | | | 298,655 | | | | 299,987 | | | Purchased Energy | | | 307,288 | | | | 296,861 | | | | 454,765 | | | Transmission | | | 10,945 | | | | 10,181 | | | | 19,214 | | | Decrease to Reflect PPFAC/PGA Recovery Treatment | | | (31,105 | ) | | | (17,091 | ) | | | (10,975 | ) | | | | | | | | | | | | Total Fuel and Purchased Energy | | | 584,108 | | | | 588,606 | | | | 762,991 | | | Other Operations and Maintenance | | | 370,067 | | | | 333,887 | | | | 295,658 | | | Depreciation | | | 128,215 | | | | 144,960 | | | | 132,366 | | | Amortization | | | 28,094 | | | | 31,058 | | | | 15,324 | | | Amortization of Transition Recovery Asset | | | — | | | | — | | | | 23,945 | | | Taxes Other Than Income Taxes | | | 46,241 | | | | 45,857 | | | | 39,339 | | | | | | | | | | | | | Total Operating Expenses | | | 1,156,725 | | | | 1,144,368 | | | | 1,269,623 | | | | | | | | | | | | | Operating Income | | | 296,952 | | | | 252,333 | | | | 140,443 | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Income (Deductions) | | | | | | | | | | | | | | Interest Income | | | 7,779 | | | | 12,072 | | | | 11,011 | | | Other Income | | | 11,038 | | | | 18,063 | | | | 7,838 | | | Other Expense | | | (15,202 | ) | | | (5,292 | ) | | | (9,286 | ) | | | | | | | | | | | | Total Other Income (Deductions) | | | 3,615 | | | | 24,843 | | | | 9,563 | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest Expense | | | | | | | | | | | | | | Long-Term Debt | | | 65,020 | | | | 58,134 | | | | 70,227 | | | Capital Leases | | | 46,740 | | | | 49,270 | | | | 52,511 | | | Other Interest Expense | | | 1,651 | | | | 3,468 | | | | 1,837 | | | Interest Capitalized | | | (2,587 | ) | | | (2,302 | ) | | | (5,565 | ) | | | | | | | | | | | | Total Interest Expense | | | 110,824 | | | | 108,570 | | | | 119,010 | | | | | | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 189,743 | | | | 168,606 | | | | 30,996 | | | Income Tax Expense | | | 78,266 | | | | 64,348 | | | | 16,975 | | | | | | | | | | | | | Net Income | | $ | 111,477 | | | $ | 104,258 | | | $ | 14,021 | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted-Average Shares of Common Stock Outstanding (000) | | | 36,415 | | | | 35,858 | | | | 35,632 | | | | | | | | | | | | | | | | | | | | | | | | | | | Basic Earnings per Share | | $ | 3.06 | | | $ | 2.91 | | | $ | 0.39 | | | | | | | | | | | | | Diluted Earnings per Share | | $ | 2.82 | | | $ | 2.69 | | | $ | 0.39 | | | | | | | | | | | | | Dividends Declared per Share | | $ | 1.56 | | | $ | 1.16 | | | $ | 0.96 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | - Thousands of Dollars - | | | | | (Except Per Share Amounts) | | Operating Revenues | | | | | | | | | | | | | Electric Retail Sales | | $ | 1,087,279 | | | $ | 1,085,822 | | | $ | 1,051,002 | | Electric Wholesale Sales | | | 125,414 | | | | 132,346 | | | | 123,943 | | California Power Exchange (CPX) Provision for Wholesale Refunds | | | — | | | | — | | | | (2,970 | ) | Gas Revenue | | | 123,133 | | | | 145,053 | | | | 141,036 | | Other Revenues | | | 125,940 | | | | 115,481 | | | | 112,936 | | | | | | | | | | | | | | | Total Operating Revenues | | | 1,461,766 | | | | 1,478,702 | | | | 1,425,947 | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | Fuel | | | 327,832 | | | | 324,520 | | | | 295,652 | | Purchased Energy | | | 224,696 | | | | 276,610 | | | | 279,269 | | Transmission | | | 14,540 | | | | 7,334 | | | | 10,945 | | Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment | | | 32,246 | | | | (4,932 | ) | | | (29,622 | ) | | | | | | | | | | | | | | Total Fuel and Purchased Energy | | | 599,314 | | | | 603,532 | | | | 556,244 | | Operations and Maintenance | | | 383,689 | | | | 379,220 | | | | 370,037 | | Depreciation | | | 141,303 | | | | 133,832 | | | | 128,215 | | Amortization | | | 35,784 | | | | 30,983 | | | | 28,094 | | Taxes Other Than Income Taxes | | | 49,881 | | | | 49,428 | | | | 46,243 | | | | | | | | | | | | | | | Total Operating Expenses | | | 1,209,971 | | | | 1,196,995 | | | | 1,128,833 | | | | | | | | | | | | | | | Operating Income | | | 251,795 | | | | 281,707 | | | | 297,114 | | | | | | | | | | | | | | | Other Income (Deductions) | | | | | | | | | | | | | Interest Income | | | 1,106 | | | | 4,568 | | | | 7,779 | | Other Income | | | 7,085 | | | | 8,288 | | | | 11,038 | | Other Expense | | | (7,988 | ) | | | (5,279 | ) | | | (15,202 | ) | | | | | | | | | | | | | | Total Other Income (Deductions) | | | 203 | | | | 7,577 | | | | 3,615 | | | | | | | | | | | | | | | Interest Expense | | | | | | | | | | | | | Long-Term Debt | | | 71,909 | | | | 73,217 | | | | 65,020 | | Capital Leases | | | 33,613 | | | | 40,359 | | | | 46,740 | | Other Interest Expense | | | 1,983 | | | | 2,535 | | | | 1,651 | | Interest Capitalized | | | (2,153 | ) | | | (3,753 | ) | | | (2,587 | ) | | | | | | | | | | | | | | Total Interest Expense | | | 105,352 | | | | 112,358 | | | | 110,824 | | | | | | | | | | | | | | | Income Before Income Taxes | | | 146,646 | | | | 176,926 | | | | 189,905 | | Income Tax Expense | | | 55,727 | | | | 66,951 | | | | 76,921 | | | | | | | | | | | | | | | Net Income | | $ | 90,919 | | | $ | 109,975 | | | $ | 112,984 | | | | | | | | | | | | | | | Weighted-Average Shares of Common Stock Outstanding (000) | | | | | | | | | | | | | Basic | | | 40,362 | | | | 36,962 | | | | 36,415 | | | | | | | | | | | | | | | Diluted | | | 41,755 | | | | 41,609 | | | | 41,041 | | | | | | | | | | | | | | | Earnings per Share | | | | | | | | | | | | | Basic | | $ | 2.25 | | | $ | 2.98 | | | $ | 3.10 | | | | | | | | | | | | | | | Diluted | | $ | 2.20 | | | $ | 2.75 | | | $ | 2.86 | | | | | | | | | | | | | | | Dividends Declared per Share | | $ | 1.72 | | | $ | 1.68 | | | $ | 1.56 | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements. UNS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | Comprehensive Income | | | | | | | | | | | | | Net Income | | $ | 90,919 | | | $ | 109,975 | | | $ | 112,984 | | | | | | | | | | | | | | | Other Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges, net of $1,119, $2,376, and $4,216 income taxes | | | (1,710 | ) | | | (3,626 | ) | | | (6,431 | ) | | | | | Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(1,862), $(1,412), and $(2,140) income taxes | | | 2,844 | | | | 2,153 | | | | 3,264 | | | | | | SERP Benefit Adjustments, net of $608, $(804) and $523 income taxes | | | (840 | ) | | | 1,158 | | | | (800 | ) | | | | | | | | | | | | | | Total Other Comprehensive Income (Loss), Net of Income Taxes | | | 294 | | | | (315 | ) | | | (3,967 | ) | | | | | | | | | | | | | | Total Comprehensive Income | | $ | 91,213 | | | $ | 109,660 | | | $ | 109,017 | | | | | | | | | | | | | | |
K-86See Notes to Consolidated Financial Statements.
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | - Thousands of Dollars - | | | | | | | | | | | | | | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | Cash Receipts from Electric Retail Sales | | $ | 1,142,364 | | | $ | 1,145,051 | | | $ | 1,079,964 | | | Cash Receipts from Electric Wholesale Sales | | | 194,580 | | | | 175,679 | | | | 353,618 | | | Cash Receipts from Gas Sales | | | 157,819 | | | | 163,441 | | | | 182,271 | | | Cash Receipts from Operating Springerville Unit 3 & 4 | | | 102,563 | | | | 68,951 | | | | 57,657 | | | Interest Received | | | 10,026 | | | | 13,470 | | | | 17,246 | | | Performance Deposits Received | | | 18,470 | | | | 34,630 | | | | 34,404 | | | Income Tax Refunds Received | | | 341 | | | | 20,242 | | | | 22,355 | | | Other Cash Receipts | | | 24,642 | | | | 15,465 | | | | 16,631 | | | Refund of Disputed Transmission Costs | | | — | | | | — | | | | 10,665 | | | Purchased Energy Costs Paid | | | (357,751 | ) | | | (334,481 | ) | | | (577,588 | ) | | Fuel Costs Paid | | | (247,484 | ) | | | (300,810 | ) | | | (292,646 | ) | | Payment of Other Operations and Maintenance Costs | | | (255,329 | ) | | | (236,184 | ) | | | (196,860 | ) | | Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | | | (163,037 | ) | | | (161,574 | ) | | | (154,548 | ) | | Wages Paid, Net of Amounts Capitalized | | | (125,893 | ) | | | (122,245 | ) | | | (108,504 | ) | | Interest Paid, Net of Amounts Capitalized | | | (59,749 | ) | | | (54,641 | ) | | | (58,774 | ) | | Performance Deposits Paid | | | (19,220 | ) | | | (22,260 | ) | | | (48,520 | ) | | Capital Lease Interest Paid | | | (38,646 | ) | | | (38,598 | ) | | | (43,828 | ) | | Income Taxes Paid | | | (22,797 | ) | | | (9,050 | ) | | | (9,900 | ) | | Allowance for Equity Funds Used During Construction | | | (4,232 | ) | | | (4,113 | ) | | | (3,244 | ) | | Excess Tax Benefit from Stock Options Exercised | | | (3,338 | ) | | | (3,256 | ) | | | (633 | ) | | Other Cash Payments | | | (10,970 | ) | | | (6,520 | ) | | | (5,999 | ) | | | | | | | | | | | | Net Cash Flows — Operating Activities | | | 342,359 | | | | 343,197 | | | | 273,767 | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | Capital Expenditures | | | (265,141 | ) | | | (282,991 | ) | | | (354,080 | ) | | Purchase of Sundt Unit 4 Lease Asset | | | (51,389 | ) | | | — | | | | — | | | Purchase of Springerville Lease Debt | | | — | | | | (31,375 | ) | | | — | | | Purchase of Renewable Energy Credits | | | (7,185 | ) | | | — | | | | — | | | Prepayment Deposits on UED Debt | | | (3,188 | ) | | | (3,625 | ) | | | — | | | Deposit — Collateral Trust Bond Trustee | | | — | | | | — | | | | (133,111 | ) | | Return of Investments in Springerville Lease Debt | | | 25,615 | | | | 12,736 | | | | 24,918 | | | Customer Advance Reimbursement from Citizens | | | 1,254 | | | | — | | | | — | | | Other Cash Receipts | | | 373 | | | | 331 | | | | 5,137 | | | Return of Investment from Millennium Energy Businesses | | | 423 | | | | 8,333 | | | | 839 | | | Insurance Proceeds for Replacement Assets | | | 1,041 | | | | 4,928 | | | | 8,035 | | | Investment in and Loans to Equity Investees | | | (401 | ) | | | (207 | ) | | | (600 | ) | | Other Cash Payments | | | (1,901 | ) | | | (661 | ) | | | (711 | ) | | | | | | | | | | | | Net Cash Flows — Investing Activities | | | (300,499 | ) | | | (292,531 | ) | | | (449,573 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | Proceeds from Borrowings Under Revolving Credit Facilities | | | 239,000 | | | | 203,000 | | | | 242,000 | | | Proceeds from Issuance of Long-Term Debt | | | 127,815 | | | | — | | | | 320,745 | | | Proceeds from Issuance of Short-Term Debt | | | — | | | | 30,000 | | | | — | | | Proceeds from Stock Options Exercised | | | 13,391 | | | | 3,441 | | | | 1,969 | | | Excess Tax Benefit from Stock Options Exercised | | | 3,338 | | | | 3,256 | | | | 633 | | | Other Cash Receipts | | | 9,068 | | | | 5,681 | | | | 6,028 | | | Repayments of Borrowings Under Revolving Credit Facilities | | | (268,500 | ) | | | (198,000 | ) | | | (237,000 | ) | | Common Stock Dividends Paid | | | (56,590 | ) | | | (41,429 | ) | | | (34,043 | ) | | Payments of Capital Lease Obligations | | | (55,997 | ) | | | (24,192 | ) | | | (74,316 | ) | | Repayments of Long-Term Debt | | | (51,592 | ) | | | (6,000 | ) | | | (76,000 | ) | | Payments of Debt Issue/Retirement Costs | | | (8,341 | ) | | | (2,268 | ) | | | (3,739 | ) | | Other Cash Payments | | | (2,775 | ) | | | (2,405 | ) | | | (5,672 | ) | | | | | | | | | | | | Net Cash Flows — Financing Activities | | | (51,183 | ) | | | (28,916 | ) | | | 140,605 | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Increase (Decrease) in Cash and Cash Equivalents | | | (9,323 | ) | | | 21,750 | | | | (35,201 | ) | Cash and Cash Equivalents, Beginning of Year | | | 76,922 | | | | 55,172 | | | | 90,373 | | | | | | | | | | | | | Cash and Cash Equivalents, End of Year | | $ | 67,599 | | | $ | 76,922 | | | $ | 55,172 | | | | | | | | | | | | | | | | | | | | | | | | | | | Non-Cash Financing Activity | | | | | | | | | | | | | | Repayment of UED Short-Term Debt | | $ | (3,188 | ) | | $ | (3,625 | ) | | $ | — | | | Repayment of Collateral Trust Bonds | | $ | — | | | $ | — | | | $ | (128,300 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | - Thousands of Dollars - | | Cash Flows from Operating Activities | | | | | | | | | | | | | Cash Receipts from Electric Retail Sales | | $ | 1,197,390 | | | $ | 1,163,537 | | | $ | 1,142,364 | | Cash Receipts from Electric Wholesale Sales | | | 149,722 | | | | 183,151 | | | | 194,580 | | Cash Receipts from Gas Sales | | | 141,590 | | | | 159,529 | | | | 157,397 | | Cash Receipts from Operating Springerville Units 3 & 4 | | | 107,927 | | | | 104,754 | | | | 102,563 | | Cash Receipts from Wholesale Gas Sales | | | 5,233 | | | | 12,404 | | | | 422 | | Interest Received | | | 2,947 | | | | 6,334 | | | | 10,026 | | Income Tax Refunds Received | | | 1,821 | | | | 4,672 | | | | 341 | | Performance Deposits Received | | | 200 | | | | 7,050 | | | | 18,470 | | Other Cash Receipts | | | 24,105 | | | | 23,937 | | | | 32,011 | | Fuel Costs Paid | | | (321,355 | ) | | | (277,386 | ) | | | (243,639 | ) | Payment of Operations and Maintenance Costs | | | (291,512 | ) | | | (295,662 | ) | | | (259,833 | ) | Purchased Energy Costs Paid | | | (250,231 | ) | | | (328,713 | ) | | | (364,132 | ) | Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | | | (187,257 | ) | | | (179,766 | ) | | | (163,037 | ) | Wages Paid, Net of Amounts Capitalized | | | (127,176 | ) | | | (122,370 | ) | | | (125,893 | ) | Interest Paid, Net of Amounts Capitalized | | | (69,478 | ) | | | (68,027 | ) | | | (59,749 | ) | Capital Lease Interest Paid | | | (28,788 | ) | | | (32,103 | ) | | | (38,646 | ) | Wholesale Gas Costs Paid | | | — | | | | (11,822 | ) | | | — | | Performance Deposits Paid | | | (200 | ) | | | (4,550 | ) | | | (19,220 | ) | Income Taxes Paid | | | — | | | | (700 | ) | | | (22,797 | ) | Other Cash Payments | | | (6,829 | ) | | | (6,949 | ) | | | (14,308 | ) | | | | | | | | | | | | | | Net Cash Flows—Operating Activities | | | 348,109 | | | | 337,320 | | | | 346,920 | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | Return of Investments in Springerville Lease Debt | | | 19,278 | | | | 38,353 | | | | 25,615 | | Proceeds from Note Receivable | | | 15,000 | | | | — | | | | — | | Other Cash Receipts | | | 22,094 | | | | 15,251 | | | | 12,958 | | Capital Expenditures | | | (307,277 | ) | | | (374,122 | ) | | | (279,240 | ) | Purchase of Intangibles—Renewable Energy Credits | | | (10,317 | ) | | | (5,992 | ) | | | (7,514 | ) | Deposit—San Juan Mine Reclamation Trust | | | (1,445 | ) | | | — | | | | — | | Purchase of Sundt Unit 4 Lease Asset | | | — | | | | — | | | | (51,389 | ) | Other Cash Payments | | | (232 | ) | | | (578 | ) | | | (5,490 | ) | | | | | | | | | | | | | | Net Cash Flows—Investing Activities | | | (262,899 | ) | | | (327,088 | ) | | | (305,060 | ) | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | Proceeds from Borrowings Under Revolving Credit Facilities | | | 359,000 | | | | 391,000 | | | | 239,000 | | Proceeds from Issuance of Long-Term Debt | | | 149,513 | | | | 340,285 | | | | 127,815 | | Proceeds from Stock Options Exercised | | | 3,570 | | | | 8,115 | | | | 13,391 | | Other Cash Receipts | | | 4,865 | | | | 4,743 | | | | 12,406 | | Repayments of Borrowings Under Revolving Credit Facilities | | | (381,000 | ) | | | (351,000 | ) | | | (268,500 | ) | Payments of Capital Lease Obligations | | | (89,452 | ) | | | (74,381 | ) | | | (55,997 | ) | Common Stock Dividends Paid | | | (69,648 | ) | | | (61,904 | ) | | | (56,590 | ) | Repayments of Long-Term Debt | | | (9,341 | ) | | | (252,125 | ) | | | (51,592 | ) | Payments of Debt Issue/Retirement Costs | | | (3,547 | ) | | | (4,361 | ) | | | (8,341 | ) | Other Cash Payments | | | (1,642 | ) | | | (1,813 | ) | | | (2,775 | ) | | | | | | | | | | | | | | Net Cash Flows—Financing Activities | | | (37,682 | ) | | | (1,441 | ) | | | (51,183 | ) | | | | | | | | | | | | | | Net Increase (Decrease) in Cash and Cash Equivalents | | | 47,528 | | | | 8,791 | | | | (9,323 | ) | Cash and Cash Equivalents, Beginning of Year | | | 76,390 | | | | 67,599 | | | | 76,922 | | | | | | | | | | | | | | | Cash and Cash Equivalents, End of Year | | $ | 123,918 | | | $ | 76,390 | | | $ | 67,599 | | | | | | | | | | | | | | | Non-Cash Financing Activity | | | | | | | | | | | | | Repayment of UED Short-Term Debt | | $ | — | | | $ | — | | | $ | (3,188 | ) | | | | | | | | | | | | | |
See Note 15 for supplemental cash flow information. See Notes to Consolidated Financial Statements. K-87
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | - Thousands of Dollars - | | ASSETS | | | | | | | | | Utility Plant | | | | | | | | | | Plant in Service | | $ | 4,452,928 | | | $ | 4,147,268 | | | Utility Plant Under Capital Leases | | | 583,374 | | | | 720,628 | | | Construction Work in Progress | | | 210,971 | | | | 144,551 | | | | | | | | | | Total Utility Plant | | | 5,247,273 | | | | 5,012,447 | | | Less Accumulated Depreciation and Amortization | | | (1,824,843 | ) | | | (1,652,296 | ) | | Less Accumulated Amortization of Capital Lease Assets | | | (460,932 | ) | | | (574,437 | ) | | | | | | | | | Total Utility Plant — Net | | | 2,961,498 | | | | 2,785,714 | | | | | | | | | | | | | | | | | | | | Investments and Other Property | | | | | | | | | | Investments in Lease Debt and Equity | | | 103,844 | | | | 132,168 | | | Other | | | 61,676 | | | | 60,239 | | | | | | | | | | Total Investments and Other Property | | | 165,520 | | | | 192,407 | | | | | | | | | | | | | | | | | | | | Current Assets | | | | | | | | | | Cash and Cash Equivalents | | | 67,599 | | | | 76,922 | | | Accounts Receivable — Customer | | | 84,048 | | | | 80,191 | | | Unbilled Accounts Receivable | | | 53,084 | | | | 53,361 | | | Allowance for Doubtful Accounts | | | (6,125 | ) | | | (5,977 | ) | | Fuel Inventory | | | 29,216 | | | | 48,159 | | | Materials and Supplies | | | 65,832 | | | | 68,633 | | | Derivative Instruments | | | 5,214 | | | | 2,653 | | | Regulatory Assets — Current | | | 56,962 | | | | 41,772 | | | Deferred Income Taxes — Current | | | 35,028 | | | | 52,355 | | | Investments in Lease Debt | | | 1,433 | | | | — | | | Other | | | 28,659 | | | | 28,236 | | | | | | | | | | Total Current Assets | | | 420,950 | | | | 446,305 | | | | | | | | | | | | | | | | | | | | Regulatory and Other Assets | | | | | | | | | | Regulatory Assets — Noncurrent | | | 191,124 | | | | 147,325 | | | Derivative Instruments | | | 9,806 | | | | 4,498 | | | Other Assets | | | 30,425 | | | | 24,993 | | | | | | | | | | Total Regulatory and Other Assets | | | 231,355 | | | | 176,816 | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 3,779,323 | | | $ | 3,601,242 | | | | | | | | | |
| | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | -Thousands of Dollars- | | ASSETS | | | | | | | | | Utility Plant | | | | | | | | | Plant in Service | | $ | 5,005,768 | | | $ | 4,856,108 | | Utility Plant Under Capital Leases | | | 582,669 | | | | 582,669 | | Construction Work in Progress | | | 128,621 | | | | 89,749 | | | | | | | | | | | Total Utility Plant | | | 5,717,058 | | | | 5,528,526 | | Less Accumulated Depreciation and Amortization | | | (1,921,733 | ) | | | (1,869,300 | ) | Less Accumulated Amortization of Capital Lease Assets | | | (494,962 | ) | | | (476,963 | ) | | | | | | | | | | Total Utility Plant—Net | | | 3,300,363 | | | | 3,182,263 | | | | | | | | | | | Investments and Other Property | | | | | | | | | Investments in Lease Debt and Equity | | | 36,339 | | | | 65,829 | | Other | | | 36,537 | | | | 34,205 | | | | | | | | | | | Total Investments and Other Property | | | 72,876 | | | | 100,034 | | | | | | | | | | | Current Assets | | | | | | | | | Cash and Cash Equivalents | | | 123,918 | | | | 76,390 | | Accounts Receivable—Customer | | | 93,742 | | | | 98,633 | | Unbilled Accounts Receivable | | | 53,568 | | | | 51,464 | | Allowance for Doubtful Accounts | | | (6,545 | ) | | | (5,572 | ) | Materials and Supplies | | | 93,322 | | | | 82,649 | | Fuel Inventory | | | 62,019 | | | | 33,263 | | Regulatory Assets—Current | | | 51,619 | | | | 97,056 | | Deferred Income Taxes—Current | | | 34,260 | | | | 23,158 | | Investments in Lease Debt | | | 9,118 | | | | — | | Derivative Instruments | | | 3,165 | | | | 11,966 | | Other | | | 33,567 | | | | 32,577 | | | | | | | | | | | Total Current Assets | | | 551,753 | | | | 501,584 | | | | | | | | | | | Regulatory and Other Assets | | | | | | | | | Regulatory Assets—Noncurrent | | | 191,077 | | | | 173,199 | | Other Assets | | | 24,360 | | | | 32,199 | | | | | | | | | | | Total Regulatory and Other Assets | | | 215,437 | | | | 205,398 | | | | | | | | | | | Total Assets | | $ | 4,140,429 | | | $ | 3,989,279 | | | | | | | | | | |
See Notes to Consolidated Financial Statements. (Consolidated Balance Sheets Continued) K-88
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | - Thousands of Dollars - | | CAPITALIZATION AND OTHER LIABILITIES | | | | | | | | | Capitalization | | | | | | | | | | Common Stock Equity | | $ | 820,786 | | | $ | 750,865 | | | Capital Lease Obligations | | | 429,074 | | | | 488,349 | | | Long-Term Debt | | | 1,352,977 | | | | 1,307,795 | | | | | | | | | | Total Capitalization | | | 2,602,837 | | | | 2,547,009 | | | | | | | | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | Current Obligations Under Capital Leases | | | 60,347 | | | | 40,441 | | | Borrowing Under Revolving Credit Facility | | | — | | | | 35,000 | | | Current Maturities of Long-Term Debt | | | 57,000 | | | | 12,195 | | | Accounts Payable — Trade | | | 109,318 | | | | 98,990 | | | Interest Accrued | | | 39,120 | | | | 41,396 | | | Accrued Taxes Other than Income Taxes | | | 39,140 | | | | 36,698 | | | Accrued Employee Expenses | | | 26,969 | | | | 27,545 | | | Customer Deposits | | | 29,795 | | | | 25,978 | | | Regulatory Liabilities — Current | | | 69,483 | | | | 42,229 | | | Derivative Instruments | | | 30,574 | | | | 21,186 | | | Other | | | 1,678 | | | | 4,038 | | | | | | | | | | Total Current Liabilities | | | 463,424 | | | | 385,696 | | | | | | | | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | | Deferred Income Taxes — Noncurrent | | | 244,148 | | | | 227,199 | | | Regulatory Liabilities — Noncurrent | | | 201,329 | | | | 211,903 | | | Derivative Instruments | | | 22,969 | | | | 19,489 | | | Pension and Other Postretirement Benefits | | | 127,343 | | | | 123,476 | | | Other | | | 117,273 | | | | 86,470 | | | | | | | | | | Total Deferred Credits and Other Liabilities | | | 713,062 | | | | 668,537 | | | | | | | | | | | | | | | | | | | | Commitments and Contingencies (Note 4) | | | | | | | | | | | | | | | | | | | Total Capitalization and Other Liabilities | | $ | 3,779,323 | | | $ | 3,601,242 | | | | | | | | | |
| | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | -Thousands of Dollars- | | CAPITALIZATION AND OTHER LIABILITIES | | | | | | | | | Capitalization | | | | | | | | | Common Stock Equity | | $ | 1,065,465 | | | $ | 888,474 | | Capital Lease Obligations | | | 262,138 | | | | 352,720 | | Long-Term Debt | | | 1,498,442 | | | | 1,517,373 | | | | | | | | | | | Total Capitalization | | | 2,826,045 | | | | 2,758,567 | | | | | | | | | | | Current Liabilities | | | | | | | | | Current Obligations Under Capital Leases | | | 90,583 | | | | 77,482 | | Borrowing Under Revolving Credit Facilities | | | — | | | | 10,000 | | Accounts Payable—Trade | | | 107,740 | | | | 109,760 | | Accrued Taxes Other than Income Taxes | | | 41,939 | | | | 41,997 | | Interest Accrued | | | 31,950 | | | | 38,302 | | Accrued Employee Expenses | | | 24,094 | | | | 25,660 | | Regulatory Liabilities—Current | | | 43,516 | | | | 41,911 | | Customer Deposits | | | 34,048 | | | | 32,485 | | Derivative Instruments | | | 14,742 | | | | 36,467 | | Other | | | 10,517 | | | | 8,455 | | | | | | | | | | | Total Current Liabilities | | | 399,129 | | | | 422,519 | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred Income Taxes—Noncurrent | | | 364,756 | | | | 300,326 | | Regulatory Liabilities—Noncurrent | | | 279,111 | | | | 234,945 | | Pension and Other Retiree Benefits | | | 159,401 | | | | 139,356 | | Derivative Instruments | | | 12,709 | | | | 20,403 | | Other | | | 99,278 | | | | 113,163 | | | | | | | | | | | Total Deferred Credits and Other Liabilities | | | 915,255 | | | | 808,193 | | | | | | | | | | | Commitments, Contingencies, and Environmental Matters (Note 4) | | | | | | | | | Total Capitalization and Other Liabilities | | $ | 4,140,429 | | | $ | 3,989,279 | | | | | | | | | | |
See Notes to Consolidated Financial Statements. (Consolidated Balance Sheets Concluded) K-89
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, | | | | | | | | | | | | | 2010 | | | 2009 | | | | | | | | | | | | | - Thousands of Dollars - | | COMMON STOCK EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock-No Par Value | | | | | | | | | | $ | 715,688 | | | $ | 696,206 | | | | | | | | 2010 | | | | 2009 | | | | | | | | | | | | | | | | | | | | | | | | | | | Shares Authorized | | | 75,000,000 | | | | 75,000,000 | | | | | | | | | | | Shares Outstanding | | | 36,541,954 | | | | 35,851,185 | | | | | | | | | | | Accumulated Earnings | | | | | | | | | | | 114,867 | | | | 60,461 | | | Accumulated Other Comprehensive Loss | | | | | | | | | | | (9,769 | ) | | | (5,802 | ) | | | | | | | | | | | | | | | | | Total Common Stock Equity | | | | | | | | | | | 820,786 | | | | 750,865 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PREFERRED STOCK | | | | | | | | | | | | | | | | | | No Par Value, 1,000,000 Shares Authorized, None Outstanding | | | | | | | | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CAPITAL LEASE OBLIGATIONS | | | | | | | | | | | | | | | | | | Springerville Unit 1 | | | | | | | | | | | 302,229 | | | | 320,843 | | | Springerville Coal Handling Facilities | | | | | | | | | | | 76,583 | | | | 85,224 | | | Springerville Common Facilities | | | | | | | | | | | 110,571 | | | | 109,499 | | | Sundt Unit 4 | | | | | | | | | | | — | | | | 13,077 | | | Other | | | | | | | | | | | 38 | | | | 147 | | | | | | | | | | | | | | | | | | | Total Capital Lease Obligations | | | | | | | | | | | 489,421 | | | | 528,790 | | | Less Current Maturities | | | | | | | | | | | (60,347 | ) | | | (40,441 | ) | | | | | | | | | | | | | | | | | Total Long-Term Capital Lease Obligations | | | | | | | | | | | 429,074 | �� | | | 488,349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | LONG-TERM DEBT | | | | | | | | | | | | | | | | | | | Issue | | Maturity | | | Interest Rate | | | | | | | | | | | | | | | | | | | | | | | | | | | UniSource Energy: | | | | | | | | | | | | | | | | | | Convertible Senior Notes | | | 2035 | | | | 4.50% | | | | 150,000 | | | | 150,000 | | | Credit Agreement | | | 2014 | | | | Variable | | | | 27,000 | | | | 40,000 | | | Tucson Electric Power Company: | | | | | | | | | | | | | | | | | | Variable Rate IDBs | | | 2014 | | | | Variable | | | | 365,300 | | | | 458,600 | | | Unsecured IDBs | | | 2020 – 2040 | | | | 4.95% to 6.375% | | | | 638,315 | | | | 445,015 | | | UNS Gas and UNS Electric: | | | | | | | | | | | | | | | | | | Senior Unsecured Notes | | | 2011 – 2023 | | | | 6.23% to 7.1% | | | | 200,000 | | | | 200,000 | | | UED: | | | | | | | | | | | | | | | | | | Secured Term Loan | | | 2012 | | | | Variable | | | | 29,362 | | | | 26,375 | | | | | | | | | | | | | | | | | Total Stated Principal Amount | | | | | | | | | | | 1,409,977 | | | | 1,319,990 | | | Less Current Maturities | | | | | | | | | | | (57,000 | ) | | | (12,195 | ) | | | | | | | | | | | | | | | Total Long-Term Debt | | | | | | | | | | | 1,352,977 | | | | 1,307,795 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Capitalization | | | | | | | | | | $ | 2,602,837 | | | $ | 2,547,009 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, | | | | | | | | | | | 2012 | | | 2011 | | | | | | | | | | | - Thousands of Dollars - | | COMMON STOCK EQUITY | | | | | | | | | | | | | | | | | Common Stock-No Par Value | | | | | | | | | | $ | 882,138 | | | $ | 725,903 | | | | | | | | | | 2012 | | | 2011 | | | | | | | | Shares Authorized | | | 75,000,000 | | | | 75,000,000 | | | | | | | | | | Shares Outstanding | | | 41,343,851 | | | | 36,918,024 | | | | | | | | | | Accumulated Earnings | | | | | | | | | | | 193,117 | | | | 172,655 | | Accumulated Other Comprehensive Loss | | | | | | | | | | | (9,790 | ) | | | (10,084 | ) | | | | | | | | | | | | | | | | | | Total Common Stock Equity | | | | | | | | | | | 1,065,465 | | | | 888,474 | | | | | | | | | | | | | | | | | | | PREFERRED STOCK | | | | | | | | | | | | | | | | | No Par Value, 1,000,000 Shares Authorized, None Outstanding | | | | | | | | | | | — | | | | — | | | | | | | | | | | | | | | | | | | CAPITAL LEASE OBLIGATIONS | | | | | | | | | | | | | | | | | Springerville Unit 1 | | | | | | | | | | | 196,843 | | | | 253,481 | | Springerville Coal Handling Facilities | | | | | | | | | | | 48,038 | | | | 65,022 | | Springerville Common Facilities | | | | | | | | | | | 107,840 | | | | 111,699 | | | | | | | | | | | | | | | | | | | Total Capital Lease Obligations | | | | | | | | | | | 352,721 | | | | 430,202 | | Less Current Maturities | | | | | | | | | | | (90,583 | ) | | | (77,482 | ) | | | | | | | | | | | | | | | | | | Total Long-Term Capital Lease Obligations | | | | | | | | | | | 262,138 | | | | 352,720 | | | | | | | | | | | | | | | | | | | | | | | | LONG-TERM DEBT | | | | | | | | | | | | | | | | | | | | | | Issue | | Maturity | | | Interest Rate | | | | | | | | UNS Energy: | | | | | | | | | | | | | | | | | Convertible Senior Notes | | | 2035 | | | | 4.50% | | | | — | | | | 150,000 | | Credit Agreement | | | 2016 | | | | Variable | | | | 45,000 | | | | 57,000 | | Tucson Electric Power Company: | | | | | | | | | | | | | | | | | Variable Rate Tax-Exempt Bonds | | | 2014 – 2016 | | | | Variable | | | | 215,300 | | | | 215,300 | | Unsecured Fixed Rate Bonds | | | 2020 – 2040 | | | | 4.50% – 6.38% | | | | 609,320 | | | | 615,855 | | Unsecured Notes | | | 2021 – 2023 | | | | 3.85% – 5.15% | | | | 398,822 | | | | 249,218 | | UNS Gas and UNS Electric: | | | | | | | | | | | | | | | | | Senior Unsecured Notes | | | 2015 – 2026 | | | | 5.39% – 7.10% | | | | 200,000 | | | | 200,000 | | UNS Electric: | | | | | | | | | | | | | | | | | Unsecured Term Loan | | | 2015 | | | | Variable | | | | 30,000 | | | | 30,000 | | | | | | | | | | | | | | | | | | | Total Long-Term Debt | | | | | | | | | | | 1,498,442 | | | | 1,517,373 | | | | | | | | | | | | | | | | | | | Total Capitalization | | | | | | | | | | $ | 2,826,045 | | | $ | 2,758,567 | | | | | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements. K-90
UNISOURCEUNS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated | | | | | | | | Common | | | | | | | | | | | Other | | | Total | | | | | Shares | | | Common | | | Accumulated | | | Comprehensive | | | Stockholders’ | | | | | Outstanding* | | | Stock | | | Earnings (Deficit) | | | Loss | | | Equity | | | | | | Balances at December 31, 2007 | | | 35,315 | | | $ | 702,368 | | | $ | (628 | ) | | $ | (11,665 | ) | | $ | 690,075 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Impact of Change in Pension Plan Measurement Date | | | | | | | | | | | (603 | ) | | | | | | | (603 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income (Loss): | | | | | | | | | | | | | | | | | | | | | | 2008 Net Income | | | | | | | | | | | 14,021 | | | | | | | | 14,021 | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Loss on Interest Rate Swap (net of $2,181 income taxes) | | | | | | | | | | | | | | | (3,326 | ) | | | (3,326 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Gain on Cash Flow Hedges to Regulatory Asset (net of $1,370 income taxes) | | | | | | | | | | | | | | | (2,089 | ) | | | (2,089 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Loss on Cash Flow Hedges to Net Income (net of $1,569 income taxes) | | | | | | | | | | | | | | | 2,393 | | | | 2,393 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss and prior service credit included in net periodic benefit cost (net of $158 income taxes) | | | | | | | | | | | | | | | (242 | ) | | | (242 | ) | | | | | | | | | | | | | | | | | | | | | | | | Increase in SERP Liability (net of $108 income taxes) | | | | | | | | | | | | | | | (165 | ) | | | (165 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Pension and Other Postretirement Benefit to Regulatory Asset (net of $5,401 income taxes) | | | | | | | | | | | | | | | 8,239 | | | | 8,239 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 18,831 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends | | | | | | | (20,017 | ) | | | (14,021 | ) | | | | | | | (34,038 | ) | | Shares Issued for Stock Options | | | 120 | | | | 1,969 | | | | | | | | | | | | 1,969 | | | Shares Issued Under Share-Based Compensation Plans | | | 23 | | | | — | | | | | | | | | | | | — | | | Tax Benefit Realized from Share-Based Compensation Plans | | | | | | | 633 | | | | | | | | | | | | 633 | | | Other | | | | | | | 2,407 | | | | | | | | | | | | 2,407 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2008 | | | 35,458 | | | | 687,360 | | | | (1,231 | ) | | | (6,855 | ) | | | 679,274 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | 2009 Net Income | | | | | | | | | | | 104,258 | | | | | | | | 104,258 | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges (net of $33 income taxes) | | | | | | | | | | | | | | | 51 | | | | 51 | | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $690 income taxes) | | | | | | | | | | | | | | | 1,053 | | | | 1,053 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $33 income taxes) | | | | | | | | | | | | | | | (51 | ) | | | (51 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 105,311 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends | | | | | | | | | | | (42,566 | ) | | | | | | | (42,566 | ) | | Shares Issued under Deferred Compensation Plans | | | 10 | | | | 279 | | | | | | | | | | | | 279 | | | Shares Issued for Stock Options | | | 282 | | | | 4,077 | | | | | | | | | | | | 4,077 | | | Shares Issued Under Share-Based Compensation Plans | | | 101 | | | | — | | | | | | | | | | | | — | | | Tax Benefit Realized from Share-Based Compensation Plans | | | | | | | 3,256 | | | | | | | | | | | | 3,256 | | | Other Share-Based Compensation | | | | | | | 1,234 | | | | | | | | | | | | 1,234 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2009 | | | 35,851 | | | | 696,206 | | | | 60,461 | | | | (5,802 | ) | | | 750,865 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | 2010 Net Income | | | | | | | | | | | 111,477 | | | | | | | | 111,477 | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes) | | | | | | | | | | | | | | | (6,431 | ) | | | (6,431 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $2,140 income taxes) | | | | | | | | | | | | | | | 3,264 | | | | 3,264 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $523 income taxes) | | | | | | | | | | | | | | | (800 | ) | | | (800 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 107,510 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends | | | | | | | | | | | (57,071 | ) | | | | | | | (57,071 | ) | | Shares Issued under Deferred Compensation Plans | | | 16 | | | | 519 | | | | | | | | | | | | 519 | | | Shares Issued for Stock Options | | | 660 | | | | 12,756 | | | | | | | | | | | | 12,756 | | | Shares Issued Under Share-Based Compensation Plans | | | 15 | | | | — | | | | | | | | | | | | — | | | Tax Benefit Realized from Share-Based Compensation Plans | | | | | | | 3,338 | | | | | | | | | | | | 3,338 | | | Other Share-Based Compensation | | | | | | | 2,869 | | | | | | | | | | | | 2,869 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2010 | | | 36,542 | | | $ | 715,688 | | | $ | 114,867 | | | $ | (9,769 | ) | | $ | 820,786 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated | | | | | | | | Common | | | | | | | | | Other | | | Total | | | | | Shares | | | Common | | | Accumulated | | | Comprehensive | | | Stockholders’ | | | | | Outstanding* | | | Stock | | | Earnings | | | Loss | | | Equity | | | | | - Thousands of Dollars - | | Balances at December 31, 2009 | | | 35,851 | | | $ | 696,206 | | | $ | 68,925 | | | $ | (5,802 | ) | | $ | 759,329 | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2010 Net Income | | | | | | | | | | | 112,984 | | | | | | | | 112,984 | | Other Comprehensive Loss, net of $2,599 income taxes | | | | | | | | | | | | | | | (3,967 | ) | | | (3,967 | ) | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 109,017 | | | | | | | | Dividends, Including Non-Cash Dividend Equivalents | | | | | | | | | | | (57,071 | ) | | | | | | | (57,071 | ) | Shares Issued under Deferred Compensation Plans | | | 16 | | | | 519 | | | | | | | | | | | | 519 | | Shares Issued for Stock Options | | | 660 | | | | 12,756 | | | | | | | | | | | | 12,756 | | Shares Issued Under Performance Share Awards | | | 15 | | | | — | | | | | | | | | | | | — | | Other | | | | | | | 6,206 | | | | | | | | | | | | 6,206 | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2010 | | | 36,542 | | | | 715,687 | | | | 124,838 | | | | (9,769 | ) | | | 830,756 | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2011 Net Income | | | | | | | | | | | 109,975 | | | | | | | | 109,975 | | Other Comprehensive Loss, net of $160 income taxes | | | | | | | | | | | | | | | (315 | ) | | | (315 | ) | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 109,660 | | Dividends, Including Non-Cash Dividend Equivalents | | | | | | | | | | | (62,158 | ) | | | | | | | (62,158 | ) | Shares Issued for Stock Options | | | 319 | | | | 8,176 | | | | | | | | | | | | 8,176 | | Shares Issued Under Performance Share Awards | | | 57 | | | | — | | | | | | | | | | | | — | | Other | | | | | | | 2,040 | | | | | | | | | | | | 2,040 | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2011 | | | 36,918 | | | | 725,903 | | | | 172,655 | | | | (10,084 | ) | | | 888,474 | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2012 Net Income | | | | | | | | | | | 90,919 | | | | | | | | 90,919 | | | | | | | | Other Comprehensive Income, net of $(135) income taxes | | | | | | | | | | | | | | | 294 | | | | 294 | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 91,213 | | Dividends, Including Non-Cash Dividend Equivalents | | | | | | | | | | | (70,457 | ) | | | | | | | (70,457 | ) | Shares Issued on Conversion of Notes and Related Tax | | | | | | | | | | | | | | | | | | | | | Effect | | | 4,262 | | | | 149,805 | | | | | | | | | | | | 149,805 | | Shares Issued for Stock Options | | | 133 | | | | 3,511 | | | | | | | | | | | | 3,511 | | Shares Issued Under Performance Share Awards | | | 31 | | | | — | | | | | | | | | | | | — | | Other | | | | | | | 2,919 | | | | | | | | | | | | 2,919 | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2012 | | | 41,344 | | | $ | 882,138 | | | $ | 193,117 | | | $ | (9,790 | ) | | $ | 1,065,465 | | | | | | | | | | | | | | | | | | | | | | |
| | | | * | | UniSourceUNS Energy has 75 million authorized shares of Common Stock. |
We describe limitations on our ability to pay dividends in Note 7.
See Notes to Consolidated Financial Statements. K-91
TUCSON ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | - Thousands of Dollars - | | Operating Revenues | | | | | | | | | | | | | | Electric Retail Sales | | $ | 868,188 | | | $ | 867,516 | | | $ | 805,528 | | | Provision for Rate Refunds — CTC Revenue | | | — | | | | — | | | | (58,092 | ) | | | | | | | | | | | | | Net Electric Retail Sales | | | 868,188 | | | | 867,516 | | | | 747,436 | | | Electric Wholesale Sales | | | 140,815 | | | | 152,955 | | | | 272,411 | | | California Power Exchange (CPX) Provision for Wholesale Refunds | | | (2,970 | ) | | | (4,172 | ) | | | — | | | Other Revenues | | | 118,946 | | | | 82,688 | | | | 71,962 | | | | | | | | | | | | | Total Operating Revenues | | | 1,124,979 | | | | 1,098,987 | | | | 1,091,809 | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | Fuel | | | 286,071 | | | | 281,710 | | | | 289,985 | | | Purchased Power | | | 118,716 | | | | 144,528 | | | | 250,580 | | | Transmission | | | 3,254 | | | | 3,066 | | | | 10,515 | | | Decrease to Reflect PPFAC Recovery Treatment | | | (23,025 | ) | | | (20,724 | ) | | | — | | | | | | | | | | | | | Total Fuel and Purchased Energy | | | 385,016 | | | | 408,580 | | | | 551,080 | | | Other Operations and Maintenance | | | 323,537 | | | | 289,765 | | | | 256,584 | | | Depreciation | | | 99,510 | | | | 116,970 | | | | 105,859 | | | Amortization | | | 32,196 | | | | 35,931 | | | | 20,181 | | | Amortization of Transition Recovery Asset | | | — | | | | — | | | | 23,945 | | | Taxes Other Than Income Taxes | | | 37,953 | | | | 37,618 | | | | 31,650 | | | | | | | | | | | | | Total Operating Expenses | | | 878,212 | | | | 888,864 | | | | 989,299 | | | | | | | | | | | | | Operating Income | | | 246,767 | | | | 210,123 | | | | 102,510 | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Income (Deductions) | | | | | | | | | | | | | | Interest Income | | | 6,707 | | | | 11,471 | | | | 9,900 | | | Other Income | | | 6,615 | | | | 10,991 | | | | 5,708 | | | Other Expense | | | (4,389 | ) | | | (2,904 | ) | | | (6,249 | ) | | | | | | | | | | | | Total Other Income (Deductions) | | | 8,933 | | | | 19,558 | | | | 9,359 | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest Expense | | | | | | | | | | | | | | Long-Term Debt | | | 42,378 | | | | 36,226 | | | | 47,456 | | | Capital Leases | | | 46,734 | | | | 49,258 | | | | 52,491 | | | Other Interest Expense | | | 433 | | | | 1,571 | | | | 1,367 | | | Interest Capitalized | | | (1,880 | ) | | | (1,752 | ) | | | (4,675 | ) | | | | | | | | | | | | Total Interest Expense | | | 87,665 | | | | 85,303 | | | | 96,639 | | | | | | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 168,035 | | | | 144,378 | | | | 15,230 | | | Income Tax Expense | | | 61,057 | | | | 55,130 | | | | 10,867 | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Income | | $ | 106,978 | | | $ | 89,248 | | | $ | 4,363 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | - Thousands of Dollars - | | Operating Revenues | | | | | | | | | | | | | Electric Retail Sales | | $ | 915,879 | | | $ | 903,930 | | | $ | 868,188 | | Electric Wholesale Sales | | | 111,194 | | | | 129,861 | | | | 141,103 | | California Power Exchange (CPX) Provision for Wholesale Refunds | | | — | | | | — | | | | (2,970 | ) | Other Revenues | | | 134,587 | | | | 122,595 | | | | 118,946 | | | | | | | | | | | | | | | Total Operating Revenues | | | 1,161,660 | | | | 1,156,386 | | | | 1,125,267 | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | Fuel | | | 318,901 | | | | 318,268 | | | | 284,744 | | Purchased Power | | | 80,137 | | | | 105,766 | | | | 118,716 | | Transmission | | | 5,722 | | | | (1,435 | ) | | | 3,254 | | Increase (Decrease) to Reflect PPFAC Recovery Treatment | | | 31,113 | | | | (6,165 | ) | | | (21,541 | ) | | | | | | | | | | | | | | Total Fuel and Purchased Energy | | | 435,873 | | | | 416,434 | | | | 385,173 | | Operations and Maintenance | | | 334,553 | | | | 330,801 | | | | 316,625 | | Depreciation | | | 110,931 | | | | 104,894 | | | | 99,510 | | Amortization | | | 39,493 | | | | 34,650 | | | | 32,196 | | Taxes Other Than Income Taxes | | | 40,323 | | | | 40,199 | | | | 37,732 | | | | | | | | | | | | | | | Total Operating Expenses | | | 961,173 | | | | 926,978 | | | | 871,236 | | | | | | | | | | | | | | | Operating Income | | | 200,487 | | | | 229,408 | | | | 254,031 | | | | | | | | | | | | | | | Other Income (Deductions) | | | | | | | | | | | | | Interest Income | | | 136 | | | | 3,567 | | | | 6,707 | | Other Income | | | 6,043 | | | | 5,693 | | | | 6,629 | | Other Expense | | | (13,772 | ) | | | (12,064 | ) | | | (11,506 | ) | | | | | | | | | | | | | | Total Other Income (Deductions) | | | (7,593 | ) | | | (2,804 | ) | | | 1,830 | | | | | | | | | | | | | | | Interest Expense | | | | | | | | | | | | | Long-Term Debt | | | 55,038 | | | | 49,858 | | | | 42,378 | | Capital Leases | | | 33,613 | | | | 40,358 | | | | 46,734 | | Other Interest Expense | | | 1,446 | | | | 1,127 | | | | 433 | | Interest Capitalized | | | (1,782 | ) | | | (2,073 | ) | | | (1,880 | ) | | | | | | | | | | | | | | Total Interest Expense | | | 88,315 | | | | 89,270 | | | | 87,665 | | | | | | | | | | | | | | | Income Before Income Taxes | | | 104,579 | | | | 137,334 | | | | 168,196 | | Income Tax Expense | | | 39,109 | | | | 52,000 | | | | 59,936 | | | | | | | | | | | | | | | Net Income | | $ | 65,470 | | | $ | 85,334 | | | $ | 108,260 | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements. K-92
TUCSON ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | Comprehensive Income | | | | | | | | | | | | | Net Income | | $ | 65,470 | | | $ | 85,334 | | | $ | 108,260 | | | | | | | | | | | | | | | Other Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges, net of $913, $2,331, and $4,216 income taxes | | | (1,396 | ) | | | (3,555 | ) | | | (6,431 | ) | | | | | Reclassification of Realized Losses on Cash Flow Hedges to Net Income, net of $(1,800), $(1,390), and $(2,140) income taxes | | | 2,750 | | | | 2,122 | | | | 3,264 | | | | | | SERP Benefit Adjustments, net of $608, $(804) and $523 income taxes | | | (840 | ) | | | 1,158 | | | | (800 | ) | | | | | | | | | | | | | | Total Other Comprehensive Income (Loss), Net of Income Taxes | | | 514 | | | | (275 | ) | | | (3,967 | ) | | | | | | | | | | | | | | Total Comprehensive Income | | $ | 65,984 | | | $ | 85,059 | | | $ | 104,293 | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements. TUCSON ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | - Thousands of Dollars - | | | | | | | | | | | | | | | | Cash Flows from Operating Activities | | | | | | | | | | | | | | Cash Receipts from Electric Retail Sales | | $ | 947,498 | | | $ | 944,873 | | | $ | 883,423 | | | Cash Receipts from Electric Wholesale Sales | | | 190,779 | | | | 199,918 | | | | 377,579 | | | Cash Receipts from Operating Springerville Unit 3 & 4 | | | 102,563 | | | | 68,951 | | | | 57,657 | | | Reimbursement of Affiliate Charges | | | 18,356 | | | | 19,998 | | | | 16,534 | | | Interest Received | | | 8,998 | | | | 12,768 | | | | 15,849 | | | Income Tax Refunds Received | | | 3,369 | | | | 14,462 | | | | 20,902 | | | Performance Deposits Received | | | 5,040 | | | | 14,000 | | | | 10,150 | | | Refund of Disputed Transmission Costs | | | — | | | | — | | | | 10,665 | | | Other Cash Receipts | | | 11,252 | | | | 10,125 | | | | 9,268 | | | Fuel Costs Paid | | | (236,436 | ) | | | (282,653 | ) | | | (284,830 | ) | | Purchased Power Costs Paid | | | (169,658 | ) | | | (185,129 | ) | | | (364,356 | ) | | Payment of Other Operations and Maintenance Costs | | | (239,074 | ) | | | (223,760 | ) | | | (185,206 | ) | | Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | | | (134,540 | ) | | | (124,053 | ) | | | (117,611 | ) | | Wages Paid, Net of Amounts Capitalized | | | (101,815 | ) | | | (97,289 | ) | | | (84,857 | ) | | Capital Lease Interest Paid | | | (38,640 | ) | | | (38,586 | ) | | | (43,807 | ) | | Interest Paid, Net of Amounts Capitalized | | | (38,232 | ) | | | (33,128 | ) | | | (38,467 | ) | | Income Taxes Paid | | | (19,663 | ) | | | (14,606 | ) | | | — | | | Performance Deposits Paid | | | (5,040 | ) | | | (14,000 | ) | | | (10,150 | ) | | Allowance for Equity Funds Used During Construction | | | (3,567 | ) | | | (3,516 | ) | | | (2,950 | ) | | Other Cash Payments | | | (3,435 | ) | | | (3,827 | ) | | | (4,037 | ) | | | | | | | | | | | | Net Cash Flows — Operating Activities | | | 297,755 | | | | 264,548 | | | | 265,756 | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | | Capital Expenditures | | | (215,697 | ) | | | (231,969 | ) | | | (291,990 | ) | | Purchase of Sundt Unit 4 Lease Asset | | | (51,389 | ) | | | — | | | | — | | | Purchase of Springerville Lease Debt | | | — | | | | (31,375 | ) | | | — | | | Purchase of Renewable Energy Credits | | | (6,742 | ) | | | — | | | | — | | | Deposit — Collateral Trust Bond Trustee | | | — | | | | — | | | | (133,111 | ) | | Other Cash Payments | | | (1,483 | ) | | | (411 | ) | | | (711 | ) | | Return of Investments in Springerville Lease Debt | | | 25,615 | | | | 12,736 | | | | 24,918 | | | Insurance Proceeds for Replacement Assets | | | 1,041 | | | | 4,928 | | | | 8,035 | | | Other Cash Receipts | | | 347 | | | | 6 | | | | 5,055 | | | | | | | | | | | | | Net Cash Flows — Investing Activities | | | (248,308 | ) | | | (246,085 | ) | | | (387,804 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | | Proceeds from Borrowings Under Revolving Credit Facility | | | 177,000 | | | | 171,000 | | | | 170,000 | | | Proceeds from Issuance of Long-Term Debt | | | 118,245 | | | | — | | | | 220,745 | | | Equity Investment from UniSource Energy | | | 15,000 | | | | 30,000 | | | | — | | | Other Cash Receipts | | | 3,241 | | | | 2,447 | | | | 1,237 | | | Repayments of Borrowings Under Revolving Credit Facility | | | (212,000 | ) | | | (146,000 | ) | | | (170,000 | ) | | Dividends Paid to UniSource Energy | | | (60,000 | ) | | | (60,000 | ) | | | (2,500 | ) | | Payments of Capital Lease Obligations | | | (55,889 | ) | | | (24,091 | ) | | | (74,228 | ) | | Repayments of Long-Term Debt | | | (30,000 | ) | | | — | | | | (10,000 | ) | | Payments of Debt Issue/Retirement Costs | | | (5,988 | ) | | | (1,329 | ) | | | (3,120 | ) | | Other Cash Payments | | | (1,491 | ) | | | (1,347 | ) | | | (3,421 | ) | | | | | | | | | | | | Net Cash Flows — Financing Activities | | | (51,882 | ) | | | (29,320 | ) | | | 128,713 | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Increase (Decrease) in Cash and Cash Equivalents | | | (2,435 | ) | | | (10,857 | ) | | | 6,665 | | Cash and Cash Equivalents, Beginning of Year | | | 22,418 | | | | 33,275 | | | | 26,610 | | | | | | | | | | | | | Cash and Cash Equivalents, End of Year | | $ | 19,983 | | | $ | 22,418 | | | $ | 33,275 | | | | | | | | | | | | | | | | | | | | | | | | | | | Non-Cash Financing Activity — Repayment of Collateral Trust Bonds | | $ | — | | | $ | — | | | $ | (128,300 | ) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | - Thousands of Dollars - | | Cash Flows from Operating Activities | | | | | | | | | | | | | Cash Receipts from Electric Retail Sales | | $ | 1,006,926 | | | $ | 963,247 | | | $ | 947,498 | | Cash Receipts from Electric Wholesale Sales | | | 124,594 | | | | 152,618 | | | | 190,779 | | Cash Receipts from Operating Springerville Units 3 & 4 | | | 107,927 | | | | 104,754 | | | | 102,563 | | Reimbursement of Affiliate Charges | | | 20,926 | | | | 18,448 | | | | 18,356 | | Cash Receipts from Wholesale Gas Sales | | | 4,652 | | | | 11,825 | | | | — | | Interest Received | | | 2,025 | | | | 5,367 | | | | 8,998 | | Income Tax Refunds Received | | | 493 | | | | 7,492 | | | | 3,369 | | Other Cash Receipts | | | 18,850 | | | | 19,611 | | | | 23,429 | | Fuel Costs Paid | | | (313,742 | ) | | | (271,975 | ) | | | (232,591 | ) | Payment of Operations and Maintenance Costs | | | (282,752 | ) | | | (287,615 | ) | | | (248,895 | ) | Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | | | (147,859 | ) | | | (139,728 | ) | | | (134,540 | ) | Wages Paid, Net of Amounts Capitalized | | | (104,955 | ) | | | (100,942 | ) | | | (101,815 | ) | Purchased Power Costs Paid | | | (81,328 | ) | | | (117,224 | ) | | | (169,658 | ) | Interest Paid, Net of Amounts Capitalized | | | (52,125 | ) | | | (45,433 | ) | | | (38,232 | ) | Capital Lease Interest Paid | | | (28,786 | ) | | | (32,103 | ) | | | (38,640 | ) | Income Taxes Paid | | | (1,796 | ) | | | (2,346 | ) | | | (19,663 | ) | Wholesale Gas Costs Paid | | | — | | | | (11,822 | ) | | | — | | Other Cash Payments | | | (5,131 | ) | | | (5,880 | ) | | | (8,475 | ) | | | | | | | | | | | | | | Net Cash Flows—Operating Activities | | | 267,919 | | | | 268,294 | | | | 302,483 | | | | | | | | | | | | | | | Cash Flows from Investing Activities | | | | | | | | | | | | | Return of Investments in Springerville Lease Debt | | | 19,278 | | | | 38,353 | | | | 25,615 | | Other Cash Receipts | | | 15,957 | | | | 7,195 | | | | 8,044 | | Capital Expenditures | | | (252,782 | ) | | | (351,890 | ) | | | (225,920 | ) | Purchase of Intangibles—Renewable Energy Credits | | | (8,889 | ) | | | (5,111 | ) | | | (7,903 | ) | Deposit—San Juan Mine Reclamation Trust | | | (1,445 | ) | | | — | | | | — | | Purchase of Sundt Unit 4 Lease Asset | | | — | | | | — | | | | (51,389 | ) | Other Cash Payments | | | — | | | | (558 | ) | | | (1,483 | ) | | | | | | | | | | | | | | Net Cash Flows—Investing Activities | | | (227,881 | ) | | | (312,011 | ) | | | (253,036 | ) | | | | | | | | | | | | | | Cash Flows from Financing Activities | | | | | | | | | | | | | Proceeds from Borrowings Under Revolving Credit Facility | | | 189,000 | | | | 220,000 | | | | 177,000 | | Proceeds from Issuance of Long-Term Debt | | | 149,513 | | | | 260,285 | | | | 118,245 | | Equity Investment from UNS Energy | | | — | | | | 30,000 | | | | 15,000 | | Other Cash Receipts | | | 3,132 | | | | 2,458 | | | | 3,241 | | Repayments of Borrowings Under Revolving Credit Facility | | | (199,000 | ) | | | (210,000 | ) | | | (212,000 | ) | Payments of Capital Lease Obligations | | | (89,452 | ) | | | (74,343 | ) | | | (55,889 | ) | Dividends Paid to UNS Energy | | | (30,000 | ) | | | — | | | | (60,000 | ) | Repayments of Long-Term Debt | | | (6,535 | ) | | | (172,460 | ) | | | (30,000 | ) | Payments of Debt Issue/Retirement Costs | | | (3,547 | ) | | | (3,594 | ) | | | (5,988 | ) | Other Cash Payments | | | (1,124 | ) | | | (894 | ) | | | (1,491 | ) | | | | | | | | | | | | | | Net Cash Flows—Financing Activities | | | 11,987 | | | | 51,452 | | | | (51,882 | ) | | | | | | | | | | | | | | Net Increase (Decrease) in Cash and Cash Equivalents | | | 52,025 | | | | 7,735 | | | | (2,435 | ) | Cash and Cash Equivalents, Beginning of Year | | | 27,718 | | | | 19,983 | | | | 22,418 | | | | | | | | | | | | | | | Cash and Cash Equivalents, End of Year | | $ | 79,743 | | | $ | 27,718 | | | $ | 19,983 | | | | | | | | | | | | | | |
See Note 15 for supplemental cash flow information. See Notes to Consolidated Financial Statements. K-93
TUCSON ELECTRIC POWER COMPANY CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | - Thousands of Dollars - | | ASSETS | | | | | | | | | Utility Plant | | | | | | | | | | Plant in Service | | $ | 3,863,431 | | | $ | 3,584,308 | | | Utility Plant Under Capital Leases | | | 582,669 | | | | 719,922 | | | Construction Work in Progress | | | 153,981 | | | | 113,390 | | | | | | | | | | Total Utility Plant | | | 4,600,081 | | | | 4,417,620 | | | Less Accumulated Depreciation and Amortization | | | (1,729,747 | ) | | | (1,582,442 | ) | | Less Accumulated Amortization of Capital Lease Assets | | | (460,257 | ) | | | (573,853 | ) | | | | | | | | | Total Utility Plant — Net | | | 2,410,077 | | | | 2,261,325 | | | | | | | | | | | | | | | | | | | | Investments and Other Property | | | | | | | | | | Investments in Lease Debt and Equity | | | 103,844 | | | | 132,168 | | | Other | | | 43,588 | | | | 31,813 | | | | | | | | | | Total Investments and Other Property | | | 147,432 | | | | 163,981 | | | | | | | | | | | | | | | | | | | | Current Assets | | | | | | | | | | Cash and Cash Equivalents | | | 19,983 | | | | 22,418 | | | Accounts Receivable — Customer | | | 63,916 | | | | 62,508 | | | Unbilled Accounts Receivable | | | 32,217 | | | | 32,368 | | | Allowance for Doubtful Accounts | | | (4,106 | ) | | | (3,806 | ) | | Accounts Receivable — Due from Affiliates | | | 5,442 | | | | 5,218 | | | Fuel Inventory | | | 29,209 | | | | 48,149 | | | Materials and Supplies | | | 54,732 | | | | 56,712 | | | Derivative Instruments | | | 1,318 | | | | 5,043 | | | Regulatory Assets — Current | | | 34,023 | | | | 27,026 | | | Deferred Income Taxes — Current | | | 36,283 | | | | 50,789 | | | Investments in Lease Debt | | | 1,433 | | | | — | | | Other | | | 25,034 | | | | 24,362 | | | | | | | | | | Total Current Assets | | | 299,484 | | | | 330,787 | | | | | | | | | | | | | | | | | | | | Regulatory and Other Assets | | | | | | | | | | Regulatory Assets — Noncurrent | | | 182,514 | | | | 137,147 | | | Derivative Instruments | | | 1,834 | | | | 1,075 | | | Other Assets | | | 24,767 | | | | 19,984 | | | | | | | | | | Total Regulatory and Other Assets | | | 209,115 | | | | 158,206 | | | | | | | | | | | | | | | | | | | | Total Assets | | $ | 3,066,108 | | | $ | 2,914,299 | | | | | | | | | |
| | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | - Thousands of Dollars - | | ASSETS | | | | | | | | | Utility Plant | | | | | | | | | Plant in Service | | $ | 4,348,041 | | | $ | 4,222,236 | | Utility Plant Under Capital Leases | | | 582,669 | | | | 582,669 | | Construction Work in Progress | | | 98,460 | | | | 76,517 | | | | | | | | | | | Total Utility Plant | | | 5,029,170 | | | | 4,881,422 | | Less Accumulated Depreciation and Amortization | | | (1,783,787 | ) | | | (1,753,807 | ) | Less Accumulated Amortization of Capital Lease Assets | | | (494,962 | ) | | | (476,963 | ) | | | | | | | | | | Total Utility Plant—Net | | | 2,750,421 | | | | 2,650,652 | | | | | | | | | | | | | | Investments and Other Property | | | | | | | | | Investments in Lease Debt and Equity | | | 36,339 | | | | 65,829 | | Other | | | 35,091 | | | | 32,313 | | | | | | | | | | | Total Investments and Other Property | | | 71,430 | | | | 98,142 | | | | | | | | | | | Current Assets | | | | | | | | | Cash and Cash Equivalents | | | 79,743 | | | | 27,718 | | Accounts Receivable—Customer | | | 71,813 | | | | 73,612 | | Unbilled Accounts Receivable | | | 33,782 | | | | 32,386 | | Allowance for Doubtful Accounts | | | (4,598 | ) | | | (3,766 | ) | Accounts Receivable—Due from Affiliates | | | 5,720 | | | | 4,049 | | Materials and Supplies | | | 80,377 | | | | 70,749 | | Fuel Inventory | | | 61,737 | | | | 32,981 | | Deferred Income Taxes—Current | | | 37,212 | | | | 21,678 | | Regulatory Assets—Current | | | 34,345 | | | | 71,747 | | Investments in Lease Debt | | | 9,118 | | | | — | | Other | | | 34,393 | | | | 15,192 | | | | | | | | | | | Total Current Assets | | | 443,642 | | | | 346,346 | | | | | | | | | | | Regulatory and Other Assets | | | | | | | | | Regulatory Assets—Noncurrent | | | 178,330 | | | | 157,386 | | Other Assets | | | 17,223 | | | | 25,135 | | | | | | | | | | | Total Regulatory and Other Assets | | | 195,553 | | | | 182,521 | | | | | | | | | | | Total Assets | | $ | 3,461,046 | | | $ | 3,277,661 | | | | | | | | | | |
See Notes to Consolidated Financial Statements. (Consolidated Balance Sheets Continued) K-94
TUCSON ENERGY CORPORATION TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | - Thousands of Dollars - | | CAPITALIZATION AND OTHER LIABILITIES | | | | | | | | | Capitalization | | | | | | | | | | Common Stock Equity | | $ | 701,155 | | | $ | 643,144 | | | Capital Lease Obligations | | | 429,074 | | | | 488,311 | | | Long-Term Debt | | | 1,003,615 | | | | 903,615 | | | | | | | | | | Total Capitalization | | | 2,133,844 | | | | 2,035,070 | | | | | | | | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | Current Obligations Under Capital Leases | | | 60,309 | | | | 40,332 | | | Borrowing Under Revolving Credit Facility | | | — | | | | 35,000 | | | Accounts Payable — Trade | | | 77,389 | | | | 71,328 | | | Accounts Payable — Due to Affiliates | | | 3,989 | | | | 3,695 | | | Interest Accrued | | | 31,771 | | | | 33,970 | | | Accrued Taxes Other than Income Taxes | | | 29,873 | | | | 28,404 | | | Accrued Employee Expenses | | | 23,710 | | | | 24,409 | | | Customer Deposits | | | 21,191 | | | | 18,125 | | | Derivative Instruments | | | 7,288 | | | | 9,434 | | | Regulatory Liabilities — Current | | | 58,936 | | | | 26,639 | | | Other | | | 3,379 | | | | 1,444 | | | | | | | | | | Total Current Liabilities | | | 317,835 | | | | 292,780 | | | | | | | | | | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | | Deferred Income Taxes — Noncurrent | | | 226,107 | | | | 217,316 | | | Regulatory Liabilities — Noncurrent | | | 170,223 | | | | 179,478 | | | Derivative Instruments | | | 11,650 | | | | 11,195 | | | Pension and Other Postretirement Benefits | | | 120,590 | | | | 116,991 | | | Other | | | 85,859 | | | | 61,469 | | | | | | | | | | Total Deferred Credits and Other Liabilities | | | 614,429 | | | | 586,449 | | | | | | | | | | | | | | | | | | | | Commitments and Contingencies (Note 4) | | | | | | | | | | | | | | | | | | | Total Capitalization and Other Liabilities | | $ | 3,066,108 | | | $ | 2,914,299 | | | | | | | | | |
| | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | - Thousands of Dollars - | | CAPITALIZATION AND OTHER LIABILITIES | | | | | | | | | Capitalization | | | | | | | | | Common Stock Equity | | $ | 860,927 | | | $ | 824,943 | | Capital Lease Obligations | | | 262,138 | | | | 352,720 | | Long-Term Debt | | | 1,223,442 | | | | 1,080,373 | | | | | | | | | | | Total Capitalization | | | 2,346,507 | | | | 2,258,036 | | | | | | | | | | | Current Liabilities | | | | | | | | | Current Obligations Under Capital Leases | | | 90,583 | | | | 77,482 | | Borrowing Under Revolving Credit Facility | | | — | | | | 10,000 | | Accounts Payable—Trade | | | 82,122 | | | | 84,509 | | Accounts Payable—Due to Affiliates | | | 3,134 | | | | 4,827 | | Accrued Taxes Other than Income Taxes | | | 33,060 | | | | 32,155 | | Interest Accrued | | | 26,965 | | | | 30,877 | | Accrued Employee Expenses | | | 20,715 | | | | 22,099 | | Customer Deposits | | | 24,846 | | | | 23,743 | | Regulatory Liabilities—Current | | | 20,822 | | | | 23,702 | | Derivative Instruments | | | 4,899 | | | | 9,040 | | Other | | | 7,085 | | | | 5,957 | | | | | | | | | | | Total Current Liabilities | | | 314,231 | | | | 324,391 | | | | | | | | | | | Deferred Credits and Other Liabilities | | | | | | | | | Deferred Income Taxes—Noncurrent | | | 319,216 | | | | 263,225 | | Regulatory Liabilities—Noncurrent | | | 241,189 | | | | 200,599 | | Pension and Other Retiree Benefits | | | 149,718 | | | | 130,660 | | Derivative Instruments | | | 10,565 | | | | 14,142 | | Other | | | 79,620 | | | | 86,608 | | | | | | | | | | | Total Deferred Credits and Other Liabilities | | | 800,308 | | | | 695,234 | | | | | | | | | | | Commitments, Contingencies, and Environmental Matters (Note 4) | | | | | | | | | Total Capitalization and Other Liabilities | | $ | 3,461,046 | | | $ | 3,277,661 | | | | | | | | | | |
See Notes to Consolidated Financial Statements. (Consolidated Balance Sheets Concluded) K-95
TUCSON ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, | | | | | | | | | | | | | 2010 | | | 2009 | | | | | | | | | | | | | - Thousands of Dollars - | | COMMON STOCK EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock-No Par Value | | | | | | | | | | $ | 858,971 | | | $ | 843,971 | | | | | | | | 2010 | | | | 2009 | | | | | | | | | | | | | | | | | | | | | | | | | | | Shares Authorized | | | 75,000,000 | | | | 75,000,000 | | | | | | | | | | | Shares Outstanding | | | 32,139,434 | | | | 32,139,434 | | | | | | | | | | | Capital Stock Expense | | | | | | | | | | | (6,357 | ) | | | (6,357 | ) | | Accumulated Deficit | | | | | | | | | | | (141,690 | ) | | | (188,668 | ) | | Accumulated Other Comprehensive Loss | | | | | | | | | | | (9,769 | ) | | | (5,802 | ) | | | | | | | | | | | | | | | | | Total Common Stock Equity | | | | | | | | | | | 701,155 | | | | 643,144 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PREFERRED STOCK | | | | | | | | | | | | | | | | | | No Par Value, 1,000,000 Shares Authorized, None Outstanding | | | | | | | | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CAPITAL LEASE OBLIGATIONS | | | | | | | | | | | | | | | | | | Springerville Unit 1 | | | | | | | | | | | 302,229 | | | | 320,843 | | | Springerville Coal Handling Facilities | | | | | | | | | | | 76,583 | | | | 85,224 | | | Springerville Common Facilities | | | | | | | | | | | 110,571 | | | | 109,499 | | | Sundt Unit 4 | | | | | | | | | | | — | | | | 13,077 | | | | | | | | | | | | | | | | | | | Total Capital Lease Obligations | | | | | | | | | | | 489,383 | | | | 528,643 | | | Less Current Maturities | | | | | | | | | | | (60,309 | ) | | | (40,332 | ) | | | | | | | | | | | | | | | | | Total Long-Term Capital Lease Obligations | | | | | | | | | | | 429,074 | | | | 488,311 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | LONG-TERM DEBT | | | | | | | | | | | | | | | | | | | Issue | | Maturity | | | Interest Rate | | | | | | | | | | | | | | | | | | | | | | | | | | | Variable Rate IDBs | | | 2014 | | | | Variable | | | | 365,300 | | | | 458,600 | | | Unsecured IDBs | | | 2020 - 2040 | | | | 4.95% to 6.375% | | | | 638,315 | | | | 445,015 | | | | | | | | | | | | | | | | | | Total Long-Term Debt | | | | | | | | | | | 1,003,615 | | | | 903,615 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Capitalization | | | | | | | | | | $ | 2,133,844 | | | $ | 2,035,070 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, | | | | | | | | | | | 2012 | | | 2011 | | | | | | | | | | | - Thousands of Dollars - | | COMMON STOCK EQUITY | | | | | | | | | | | | | | | | | Common Stock-No Par Value | | | | | | | | | | $ | 888,971 | | | $ | 888,971 | | | | | | | | | | 2012 | | | 2011 | | | | | | | | Shares Authorized | | | 75,000,000 | | | | 75,000,000 | | | | | | | | | | Shares Outstanding | | | 32,139,434 | | | | 32,139,434 | | | | | | | | | | Capital Stock Expense | | | | | | | | | | | (6,357 | ) | | | (6,357 | ) | Accumulated Deficit | | | | | | | | | | | (12,157 | ) | | | (47,627 | ) | Accumulated Other Comprehensive Loss | | | | | | | | | | | (9,530 | ) | | | (10,044 | ) | | | | | | | | | | | | | | | | | | Total Common Stock Equity | | | | | | | | | | | 860,927 | | | | 824,943 | | | | | | | | | | | | | | | | | | | PREFERRED STOCK | | | | | | | | | | | | | | | | | No Par Value, 1,000,000 Shares Authorized, None Outstanding | | | | — | | | | — | | | | | | | | | | | | | | | | | | | CAPITAL LEASE OBLIGATIONS | | | | | | | | | | | | | | | | | Springerville Unit 1 | | | | | | | | | | | 196,843 | | | | 253,481 | | Springerville Coal Handling Facilities | | | | | | | | | | | 48,038 | | | | 65,022 | | Springerville Common Facilities | | | | | | | | | | | 107,840 | | | | 111,699 | | | | | | | | | | | | | | | | | | | Total Capital Lease Obligations | | | | | | | | | | | 352,721 | | | | 430,202 | | Less Current Maturities | | | | | | | | | | | (90,583 | ) | | | (77,482 | ) | | | | | | | | | | | | | | | | | | Total Long-Term Capital Lease Obligations | | | | | | | | | | | 262,138 | | | | 352,720 | | | | | | | | | | | | | | | | | | | LONG-TERM DEBT | | | | | | | | | | | | | | | | | | | | | | Issue | | Maturity | | | Interest Rate | | | | | | | | Variable Rate Tax-Exempt Bonds | | | 2014 – 2016 | | | | Variable | | | | 215,300 | | | | 215,300 | | Unsecured Fixed Rate Bonds | | | 2020 – 2040 | | | | 4.50% – 6.38% | | | | 609,320 | | | | 615,855 | | Unsecured Notes | | | 2021 – 2023 | | | | 3.85% – 5.15% | | | | 398,822 | | | | 249,218 | | | | | | | | | | | | | | | | | | | Total Long-Term Debt | | | | | | | | | | | 1,223,442 | | | | 1,080,373 | | | | | | | | | | | | | | | | | | | Total Capitalization | | | | | | | | | | $ | 2,346,507 | | | $ | 2,258,036 | | | | | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements. K-96
TUCSON ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated | | | | | | | | | | | | Capital | | | | | | | Other | | | Total | | | | | Common | | | Stock | | | Accumulated | | | Comprehensive | | | Stockholder’s | | | | | Stock | | | Expense | | | Deficit | | | Loss | | | Equity | | | | | - Thousands of Dollars - | | | | Balances at December 31, 2007 | | $ | 813,971 | | | $ | (6,357 | ) | | $ | (218,488 | ) | | $ | (11,777 | ) | | $ | 577,349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Impact of Change in Pension Plan Measurement Date | | | | | | | | | | | (528 | ) | | | | | | | (528 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income (Loss): | | | | | | | | | | | | | | | | | | | | | | 2008 Net Income | | | | | | | | | | | 4,363 | | | | | | | | 4,363 | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Loss on Interest Rate Swap (net of $2,181 income taxes) | | | | | | | | | | | | | | | (3,326 | ) | | | (3,326 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Gain on Cash Flow Hedges to Regulatory Asset (net of $1,337 income taxes) | | | | | | | | | | | | | | | (2,039 | ) | | | (2,039 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Loss on Cash Flow Hedges to Net Income (net of $1,569 income taxes) | | | | | | | | | | | | | | | 2,393 | | | | 2,393 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss and prior service credit included in net periodic benefit cost (net of $157 income taxes) | | | | | | | | | | | | | | | (240 | ) | | | (240 | ) | | | | | | | | | | | | | | | | | | | | | | | | Increase in SERP Liability (net of $108 income taxes) | | | | | | | | | | | | | | | (165 | ) | | | (165 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Pension and Other Postretirement Benefit to Regulatory Asset (net of $5,441 income taxes) | | | | | | | | | | | | | | | 8,299 | | | | 8,299 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 9,285 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends Paid | | | | | | | | | | | (2,500 | ) | | | | | | | (2,500 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2008 | | | 813,971 | | | | (6,357 | ) | | | (217,153 | ) | | | (6,855 | ) | | | 583,606 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | 2009 Net Income | | | | | | | | | | | 89,248 | | | | | | | | 89,248 | | | | | | | | | | | | �� | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges (net of $33 income taxes) | | | | | | | | | | | | | | | 51 | | | | 51 | | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $690 income taxes) | | | | | | | | | | | | | | | 1,053 | | | | 1,053 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $33 income taxes) | | | | | | | | | | | | | | | (51 | ) | | | (51 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 90,301 | | | | | | | | | | | | | | | | | | | | | | | | | Capital Contribution from UniSource Energy | | | 30,000 | | | | | | | | | | | | | | | | 30,000 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends | | | | | | | | | | | (60,763 | ) | | | | | | | (60,763 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2009 | | | 843,971 | | | | (6,357 | ) | | | (188,668 | ) | | | (5,802 | ) | | | 643,144 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | 2010 Net Income | | | | | | | | | | | 106,978 | | | | | | | | 106,978 | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes) | | | | | | | | | | | | | | | (6,431 | ) | | | (6,431 | ) | | | | | | | | | | | | | | | | | | | | | | | | Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income (net of $2,140 income taxes) | | | | | | | | | | | | | | | 3,264 | | | | 3,264 | | | | | | | | | | | | | | | | | | | | | | | | | Employee Benefit Obligations | | | | | | | | | | | | | | | | | | | | | | Amortization of SERP Net Prior Service Cost Included in Net Periodic Benefit Cost (net of $523 income taxes) | | | | | | | | | | | | | | | (800 | ) | | | (800 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 103,011 | | | | | | | | | | | | | | | | | | | | | | | | | Capital Contribution from UniSource Energy | | | 15,000 | | | | | | | | | | | | | | | | 15,000 | | | | | | | | | | | | | | | | | | | | | | | | | Dividends Paid | | | | | | | | | | | (60,000 | ) | | | | | | | (60,000 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2010 | | $ | 858,971 | | | $ | (6,357 | ) | | $ | (141,690 | ) | | $ | (9,769 | ) | | $ | 701,155 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Accumulated | | | | | | | | | | | Capital | | | | | | Other | | | Total | | | | | Common | | | Stock | | | Accumulated | | | Comprehensive | | | Stockholder’s | | | | | Stock | | | Expense | | | Deficit | | | Loss | | | Equity | | Balances at December 31, 2009 | | $ | 843,971 | | | $ | (6,357 | ) | | $ | (181,221 | ) | | $ | (5,802 | ) | | $ | 650,591 | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2010 Net Income | | | | | | | | | | | 108,260 | | | | | | | | 108,260 | | | | | | | | Other Comprehensive Loss, net of $2,599 income taxes | | | | | | | | | | | | | | | (3,967 | ) | | | (3,967 | ) | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 104,293 | | Capital Contribution from UNS Energy | | | 15,000 | | | | | | | | | | | | | | | | 15,000 | | | | | | | | Dividends Paid | | | | | | | | | | | (60,000 | ) | | | | | | | (60,000 | ) | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2010 | | | 858,971 | | | | (6,357 | ) | | | (132,961 | ) | | | (9,769 | ) | | | 709,884 | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2011 Net Income | | | | | | | | | | | 85,334 | | | | | | | | 85,334 | | | | | | | | Other Comprehensive Loss, net of $137 income taxes | | | | | | | | | | | | | | | (275 | ) | | | (275 | ) | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 85,059 | | | | | | | | Capital Contribution from UNS Energy | | | 30,000 | | | | | | | | | | | | | | | | 30,000 | | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2011 | | | 888,971 | | | | (6,357 | ) | | | (47,627 | ) | | | (10,044 | ) | | | 824,943 | | | | | | | | | | | | | | | | | | | | | | | Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | 2012 Net Income | | | | | | | | | | | 65,470 | | | | | | | | 65,470 | | Other Comprehensive Income, net of $(279) income taxes | | | | | | | | | | | | | | | 514 | | | | 514 | | | | | | | | | | | | | | | | | | | | | | | Total Comprehensive Income | | | | | | | | | | | | | | | | | | | 65,984 | | | | | | | | Dividends Paid | | | | | | | | | | | (30,000 | ) | | | | | | | (30,000 | ) | | | | | | | | | | | | | | | | | | | | | | Balances at December 31, 2012 | | $ | 888,971 | | | $ | (6,357 | ) | | $ | (12,157 | ) | | $ | (9,530 | ) | | $ | 860,927 | | | | | | | | | | | | | | | | | | | | | | |
We describe limitations on our ability to pay dividends in Note 7.
See Notes to Consolidated Financial Statements. K-97
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES UNS Energy Corporation (UNS Energy), formerly UniSource Energy Corporation, (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Operations are conducted by UniSourceEach of UNS Energy’s subsidiaries each of which is a separate legal entity with its own assets and liabilities. UniSourceUNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED). TEP is a regulated public utility and UniSourceUNS Energy’s largest operating subsidiary, representing approximately 81%84% of UniSourceUNS Energy’s total assets as of December 31, 2010.2012. TEP generates, transmits and distributes electricity to approximately 403,000406,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily located in the western U.S.United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and beginning in December 2009, Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP). UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, with 147,000which services approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is an electric transmissiona regulated public utility, which generates, transmits and distribution company withdistributes electricity to approximately 91,00092,000 retail customers in Mohave and Santa Cruz counties. UED owns Black Mountain Generating Station (BMGS), a natural gas-fired combustion turbine in northwestern Arizona, that, through a power purchase agreement, provides electricity to UNS Electric. Millennium has existingand Millennium’s investments in unregulated businesses that representedrepresent less than 1% of UniSourceUNS Energy’s assets as of December 31, 2010. Millennium2012.Our business is in the processcomprised of exiting its investments, except for Southwest Energy Solutions (SES), which may yield gains or losses. See Note 13. SES, a wholly-owned subsidiary of Millennium, provides supplemental labor and meter reading services tothree reporting segments – TEP, UNS Gas, and UNS Electric. Our business is comprised of four reporting segments — TEP, UNS Gas, UNS Electric, and Millennium.
References to “we” and “our” are to UniSourceUNS Energy and its subsidiaries, collectively. REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS In the fourth quarter of 2012, we identified that we had incorrectly reported UNS Electric’s sales and purchase contracts, which did not result in the physical delivery of energy. The transactions were reported on a gross basis rather than on a net basis during the first three quarters of 2012 as well as the calendar years 2011 and 2010. This error resulted in an equal and offsetting overstatement of Electric Wholesale Sales and Purchased Energy in the income statements of $31 million in 2011 and $28 million in 2010. This error had no impact to operating income, net income, retained earnings, or cash flows. We assessed the impact of these errors on prior period financial statements and concluded they were not material to any period. However, the errors were significant to the individual line items. As a result, in accordance with Staff Accounting Bulletin 108, we have revised the 2011 and 2010 financial statements included herein to correct these errors. See Note 17 for the quarterly impact of the revisions on the years presented. The interim financial data is unaudited. The revisions noted above impacted UNS Energy’s statements of income as shown in the tables below: | | | | | | | | | | | | | | | | | | | | UNS Energy | | | | | Year Ended | | | Year Ended | | | | | December 31, 2011 | | | December 31, 2010 | | | | | As Reported | | | As Revised | | | As Reported | | | As Revised | | | | | -Thousands of Dollars- | | Income Statement | | | | | | | | | | | | | | | | | Electric Wholesale Sales | | $ | 163,159 | | | $ | 132,346 | | | $ | 151,962 | | | $ | 123,943 | | Total Operating Revenues | | | 1,509,515 | | | | 1,478,702 | | | | 1,453,966 | | | | 1,425,947 | | Purchased Energy | | | 307,423 | | | | 276,610 | | | | 307,288 | | | | 279,269 | | Total Fuel and Purchased Energy | | | 634,345 | | | | 603,532 | | | | 584,263 | | | | 556,244 | | Total Operating Expenses | | | 1,227,843 | | | | 1,196,995 | | | | 1,156,852 | | | | 1,128,833 | |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy
2012
Three Months Ended | | | | | March 31, | | | June 30, | | | September 30, | | | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | | | -Thousands of Dollars | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | Electric Wholesale Sales | | $ | 37,104 | | | $ | 33,538 | | | $ | 28,684 | | | $ | 24,381 | | | $ | 32,494 | | | $ | 28,836 | | Purchased Energy | | | 63,276 | | | | 59,790 | | | | 51,376 | | | | 48,203 | | | | 60,238 | | | | 57,085 | | Total Fuel and Purchased Energy | | | 134,276 | | | | 130,790 | | | | 151,328 | | | | 148,155 | | | | 175,687 | | | | 172,534 | | Total Operating Expenses | | | 284,479 | | | | 280,984 | | | | 299,112 | | | | 295,932 | | | | 330,852 | | | | 327,700 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy
2011
Three Months Ended | | | | | March 31, | | | June 30, | | | September 30, | | | December 31, | | | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | | | -Thousands of Dollars | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Wholesale Sales | | $ | 40,914 | | | $ | 35,438 | | | $ | 38,744 | | | $ | 35,331 | | | $ | 41,847 | | | $ | 32,818 | | | $ | 41,654 | | | $ | 28,759 | | Purchased Energy | | | 78,274 | | | | 71,685 | | | | 66,336 | | | | 61,804 | | | | 88,734 | | | | 79,343 | | | | 74,079 | | | | 63,778 | | Total Fuel and Purchased Energy | | | 146,579 | | | | 139,990 | | | | 155,539 | | | | 151,007 | | | | 182,766 | | | | 173,376 | | | | 149,461 | | | | 139,159 | | Total Operating Expenses | | | 299,946 | | | | 293,357 | | | | 298,383 | | | | 293,852 | | | | 327,187 | | | | 317,796 | | | | 302,327 | | | | 291,990 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | | | Six Month Period Ended | | | Nine Month Period Ended | | | | | June 30, 2012 | | | June 30, 2011 | | | September 30, 2012 | | | September 30, 2011 | | | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | | | -Thousands of Dollars | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Wholesale Sales | | $ | 65,787 | | | $ | 57,919 | | | $ | 79,658 | | | $ | 70,769 | | | $ | 98,282 | | | $ | 86,755 | | | $ | 121,506 | | | $ | 103,587 | | Total Operating Revenues | | | 686,044 | | | | 679,384 | | | | 714,439 | | | | 703,318 | | | | 1,123,305 | | | | 1,113,492 | | | | 1,165,387 | | | | 1,144,875 | | Purchased Energy | | | 114,653 | | | | 107,993 | | | | 144,610 | | | | 133,489 | | | | 174,891 | | | | 165,078 | | | | 233,344 | | | | 212,832 | | Total Fuel and Purchased Energy | | | 285,605 | | | | 278,945 | | | | 302,118 | | | | 290,997 | | | | 461,292 | | | | 451,479 | | | | 484,885 | | | | 464,373 | | Total Operating Expenses | | | 583,590 | | | | 576,916 | | | | 598,330 | | | | 587,209 | | | | 914,428 | | | | 904,616 | | | | 925,518 | | | | 905,005 | | Operating Income(1) | | | 102,454 | | | | 102,468 | | | | 116,109 | | | | 116,109 | | | | 208,877 | | | | 208,876 | | | | 239,869 | | | | 239,869 | |
(1) Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board issued authoritative guidance that eliminated the option to report other comprehensive income in the statement of changes in equity. Rather, an entity must elect to present items of net income and other comprehensive income in one continuous statement or in two separate but consecutive statements. In 2012, we elected to include two separate but consecutive statements. We implemented accounting guidance in 2012 which enhances our disclosures regarding unobservable inputs in calculating the fair market value of certain assets and liabilities. The guidance requires additional quantitative analysis of inputs when we use significant unobservable inputs to measure the fair value of our derivatives and financial instruments. See Note 11. BASIS OF PRESENTATION We account forconsolidate our investments in subsidiaries or other companies using one of three methods, consolidation, equity or cost. We consolidate when we hold a majority of the voting stock and we can exercise control over the operations and policies of the company. Consolidation means accounts of the parent and subsidiary are combined and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated. We use the equity method to report partnerships and affiliated companies when we can demonstrate the ability to exercise significant influence over the operating and financial policies of an investee company. Equity method investments are recorded as investments on the balance sheet and net income (loss)eliminated if recovery from the entityratepayers is reflected in Other Income on the income statements. We evaluate our equity method investments for “other than temporary” decline in value at least quarterly. If the decline in value is other than temporary, we recognize the adjustment in earnings.
probable. See Note 2. K-98
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) We use the cost method if we do not exercise significant influence in an investment and record income only to the extent we receive dividends or distributions. We evaluate our cost method investments for potential decline in value at least quarterly. If we determine the decline in value is other than temporary we recognize the adjustment in earnings.
(Continued)USE OF ACCOUNTING ESTIMATES Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles (GAAP) in the U.S.United States. These estimates and assumptions affect: Assets and liabilities inon our balance sheets at the dates of the financial statements; Our disclosures about contingent assets and liabilities at the dates of the financial statements; and Our revenues and expenses in our income statements during the periods presented. Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual amountsresults may differ from the estimates. ACCOUNTING FOR RATE REGULATION TEP, UNS Gas and UNS ElectricWe generally use the same accounting policies and practices used by unregulated companies. However, sometimes regulatory accountingGAAP requires that rate-regulated companies apply special accounting treatment to show the effect of rate regulation. For example, the ACC can determinewe capitalize certain costs that TEP, UNS Gas or UNS Electric are allowed to recover certain expenses at a designated timewould be included as expense in the future. In this situation, TEP, UNS Gas or UNS Electric defer these items as regulatorycurrent period by unregulated companies. Regulatory assets on the balance sheet and then reflect therepresent incurred costs as expenses whenthat have been deferred because they are allowedprobable of future recovery in the rates charged to recover them from ratepayers. Similarly, certain revenue items may be deferred as regulatory liabilities and not reflected as revenue until ratesretail customers. Our Retail Rates are designed to customers are reduced.allow TEP, UNS Gas, and UNS Electric an opportunity to recover reasonable operating and capital costs and earn a return on utility plant in service. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through billing reductions. We evaluate regulatory assets each period and believe recovery is probable. Beginning in December 2008, If future recovery of costs ceases to be probable, the assets would be written off as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accountingcharge to its generation operations. See Note 2. current period earnings.TEP, Transmission and Distribution Operations, UNS Gas, and UNS Electric apply regulatory accounting. A rate-regulated company can apply regulatory accounting policies and practices only underas the following conditions:
conditions exist:An independent regulator sets rates; The regulator sets the rates to recover the specific enterprise’s costs of providing service; and Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers. CASH AND CASH EQUIVALENTS We define Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with an original maturity of three months or less. As of December 31, 2012, we include $7 million of restricted cash in Investments and Other Property—Other on the balance sheets, of which $2 million has been legally restricted as to its use. At December 31, 2011, we included $9 million of restricted cash in Investments and Other Property – Other on the balance sheets, of which $3 million had been legally restricted as to its use. UTILITY PLANT Utility Plant is a term we use to describeincludes the business property and equipment that supports electric and gas services, consisting primarily of generation, transmission, and distribution facilities. TEP, UNS Gas and UNS ElectricWe report utility plant at original cost. Original costs included in utility plant arecost includes materials and labor, contractor services, construction overhead (where(when applicable), and an Allowance for Funds Used During Construction (AFUDC). K-99
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Costs to replace major units of property are included in utility plant. TheWe record the cost of repairs and maintenance, including planned major overhauls, at TEP’s generation plants, are recorded to Other Operations and Maintenance Expense on(O&M) expense in the income statementstatements as the costs are incurred.
When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage valuevalue. There is credited or charged to accumulated depreciation. no income statement impact.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) AFUDC and Capitalized Interest AFUDC reflects the cost of debt or equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC applies to all regulated operations that follow regulatory accounting. AFUDC amounts capitalized are included in rate base for establishing utility rates.Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt is capitalized as a cost of construction. The capitalized interest capitalized that relates to debt reduces Other Interest Expense onin the income statement.statements. The capitalized cost capitalized for equity funds is recorded as Other Income. | | | | | | | | | | | | | | | Average AFUDC Rate on Regulated Construction Expenditures | | 2010 | | | 2009 | | | 2008 | | TEP(1) | | | 6.65 | % | | | 6.40 | % | | | 7.50 | % | | UNS Gas | | | 8.19 | % | | | 7.05 | % | | | 8.37 | % | | UNS Electric | | | 8.22 | % | | | 7.62 | % | | | 8.84 | % |
| | | (1) | | Prior to December 2008, TEP also had an average capitalized interest rate on generation-related construction expenditures of 5.02%. |
Depreciation
TEP, Income in the income statements.The average AFUDC rates on regulated construction expenditures are included in the table below: | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | 2010 | | TEP | | | 7.22 | % | | | 6.72 | % | | | 6.65 | % | UNS Gas | | | 7.95 | % | | | 8.32 | % | | | 8.19 | % | UNS Electric | | | 7.89 | % | | | 8.18 | % | | | 8.22 | % |
UNS Gas,Energy did not capitalize interest in 2012. UNS ElectricEnergy capitalized interest at a rate of 3.30% for 2011 and UED1.96% for 2010. Depreciation We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. Further detail regarding types of assets and the period over which they are depreciated can be found inSee Note 5. The ACCArizona Corporation Commission (ACC) approves depreciation rates for all utility plant, except that of UEDgeneration and the transmissiondistribution assets. Transmission assets of TEP which are subject to FERC jurisdiction.the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and reflect estimated removal costs, net of estimated salvage value for interim retirements. Prior to December 2008, before TEP reapplied regulatory accounting to its generation operations, the depreciable lives for TEP’s generation assets were based on remaining useful lives. Below are the summarized average annual depreciation rates for all utility plants. | | | | | | | | | | | | | | | | | | | | | TEP | | | UNS Gas | | | UNS Electric | | | UED | | 2010 | | | 3.14 | % | | | 2.83 | % | | | 4.35 | % | | | 2.57 | % | | 2009 | | | 3.64 | % | | | 2.76 | % | | | 4.33 | % | | | 2.57 | % | | 2008 | | | 3.33 | % | | | 2.77 | % | | | 4.47 | % | | | 2.57 | % |
plant, which reflect immaterial adjustments in the calculation of rates in the years presented to exclude allocated depreciation (the adjustment did not affect Depreciation Expense recorded in the income statements). | | | | | | | | | | | | | | | | TEP | | | UNS Gas | | | UNS Electric | | 2012 | | | 3.22 | % | | | 2.69 | % | | | 3.99 | % | 2011 | | | 3.14 | % | | | 2.84 | % | | | 4.02 | % | 2010 | | | 3.16 | % | | | 2.83 | % | | | 4.35 | % |
Computer Software Costs TEP, UNS Gas and UNS ElectricWe capitalize costs incurred to purchase and develop internal use computer software for internal use and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense. TEP Utility Plant underUnder Capital Leases TEP financed the following generation assets with capital leases: Springerville Common Facilities,Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The amount ofcapital lease expense incurred for TEP’s generation-related capital leases consists of amortization expense as described inAmortization Expense (see Note 55) and Interest Expense on Expense—Capital Leases as reflected on the Consolidated Statements of Income.Leases. The lease terms are described in TEP Capital Lease Obligations in Note 6. K-100
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
INVESTMENTS IN LEASE DEBT AND EQUITY TEP holds investmentsheld an investment in lease debt relating to Springerville Unit 1 through its maturity date in two of TEP’s capital leases:January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a one-half interest in certain Springerville Coal Handling Facilities. These holdings are considered to be held-to-maturity investments because TEP has the ability and intent to hold them until maturity. TEP recordsCommon Facilities (Springerville Unit 1 Leases). The fair value of these investments at amortized cost and recognizes interest income. Seeis described in Note 11 for information on financial instruments not carried at fair value.11. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to debt andthe equity holders. In January 2011, TEP received the final maturity payment of $1 million on the investment in Springerville Coal Handling Facilities debt. TEP accounts for its 14% equity interest in the Springerville Unit 1 leaseLease trust using the equity method. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) JOINTLY-OWNED FACILITIES TEP has investments in several plantsgeneration and transmission facilities jointly-owned with other companies. These projects are accounted for on a proportionate consolidation basis. Further discussionbasis based on jointly-owned facilities can be found inour ownership percentage. See Note 5. ASSET RETIREMENT OBLIGATIONS TEP recordsand UNS Electric record a liability for the estimated present value of a conditional asset retirement obligationAsset Retirement Obligation (ARO) as follows: When it is able to reasonably estimate the fair value of any future obligation to retire as a result of an existing or enacted law, statute, ordinance, or contract; or If it can reasonably estimate the fair value. When the liability is initially recorded at net present value, TEP capitalizesand UNS Electric capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, TEP adjustsand UNS Electric adjust the liability to its present value by recognizing accretion expense each period in Other Operations and MaintenanceO&M expense, and the capitalized cost is depreciated in Depreciation and Amortization expense over the useful life of the related asset. Beginning in December 2008,asset or when TEP reapplied regulatory accountingapplicable, the terms of the lease subject to its generation operations, TEP began recording costARO requirements.Based on the decommissioning studies to estimate timing and amount of removal for itsfuture retirement of certain generation assets, that is recoverable through rates chargedboth TEP and UNS Electric record legal AROs for these assets. Additionally, TEP and UNS Electric incurred AROs related to customers. See Note 2. their photovoltaic assets as a result of entering into various ground leases. TEP UNS Gas and UNS Electric record cost of removal for theirgeneration assets that are recoverable through the rates charged to retail customers. See Note 2. We record cost of removal for transmission and distribution assets through depreciation rates and recover those amounts in the rates charged to theirretail customers. There are no legal obligations associated with thesetransmission and distribution assets. TEP, UNS Gas and UNS ElectricWe have recorded theiran obligation for estimated costs of removal as regulatory liabilities. EVALUATION OF ASSETS FOR IMPAIRMENT We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If undiscounted expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the asset is written down to the fair value of the asset. Additionally, Millennium reviews its investments for impairment indicators at the end of each quarter. If the decline in fair value is judged to be other-than-temporary, an impairment loss is recorded.
not recoverable through rates. K-101
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
DEFERRED FINANCING COSTS TheWe defer the costs related to the issuance ofissue debt are deferred and amortizedamortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP, UNS Gas and UNS ElectricWe defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt. Prior to December 2008, when TEP reapplied regulatory accounting to its generation operations, TEP recognized gains and losses on reacquired debt, including unamortized debt issuance costs, associated with its generation operations as incurred. UTILITY OPERATING REVENUES TEP, UNS Gas and UNS ElectricWe record utility operating revenues when services or commodities are delivered to customers. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. AmountsWe determine amounts delivered are determined through systematic monthlyperiodic readings of customer meters. At the end of the month, the usage since the last meter reading is estimated and the corresponding unbilled revenue is calculated. Unbilled revenue is estimated based on daily generation or purchased volumes, estimated customer usage by customer class, estimated line losses, and estimated average customer rates.Retail Rates. Accrued unbilled revenues are reversed the following month when actual billings occur. The accuracy of the unbilled revenue estimate is affected by factors that include fluctuations in energy demands, weather, line losses, customer ratesRetail Rates, and changes in the composition of customer classes. Effective in January 2009, as a result of the 2008UNS ENERGY, TEP, Rate Order, TEP wasAND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The ACC authorized a rate-adjustment mechanism for TEP, UNS Gas, and UNS Electric that provides for the recovery of actual fuel, transmission, and purchased power/energy cost, similar to mechanisms already in place at UNS Gas and UNS Electric.cost. The revenue surcharge or surcredit adjusts the customers’ retail rate for delivered electricity or gas to collect or return under- or over- recoveredover-recovered energy costs. TheseThe ACC revises these rate-adjustment mechanisms are revised periodically (annually for TEP and UNS Electric; monthly for UNS Gas) and may increase or decrease the level of costs recovered through base ratesRetail Rates for any difference between the total amount collected under the clausesmechanisms and the recoverable costs incurred. See Note 2. TEP’s wholesale revenueArizona’s mandatory Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy and allows recovery of compliance costs through a RES surcharge to customers. We charge customers a Demand Side Management (DSM) surcharge to recover the cost of ACC-approved Electric Energy Efficiency Programs (Electric EE Programs) or Gas Energy Efficiency Programs (Gas EE Programs). We defer differences between actual RES or DSM qualified costs incurred and the recovery of such costs from retail customers through the RES and DSM surcharges. Cost over-recoveries (the excess of cost recoveries through the RES and DSM surcharges over actual qualified costs incurred) are deferred as regulatory liabilities and cost under-recoveries (the excess of actual qualified costs incurred over cost recoveries through the RES and DSM surcharges) are deferred as regulatory assets. The surcharges typically reset annually and incorporate an adjustor mechanism that, upon approval of the ACC, allows us to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s RES or DSM surcharge. See Note 2. For purchased power costs from settled energyand wholesale sales contracts that are not physically delivered aresettled with energy, TEP and UNS Electric net settledthe sales contracts with the purchase power contracts and reported on areflect the net basis inamount as Electric Wholesale Sales. The corresponding cash receipts and payments are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales, andwhile cash payments are recorded as Purchased EnergyEnergy/Power Costs Paid, respectively. Paid.We record an Allowance for Doubtful Accounts to reduce accounts receivable for revenue amounts that are estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. TEP, UNS Gas and UNS ElectricWe refer uncollected accounts to external collection agencies after a period of 90 days. TEP earns and recognizes revenue from operatingOther Revenues monthly as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of Tri-State and SRP as Other Revenues. Effective with commercial operation of Springerville Unit 3 in July 2006 and Springerville Unit 4 in December 2009,SRP. Tri-State and SRP reimburse TEP for various operating costs related to the common facilities on an ongoing basis, including 14% each of theexpenses at Springerville, Common Lease payments and 17% each of the Springerville Coal Handling Facilities Lease payments as Other Revenues. Expenseswhich are recorded in the respective line item of the income statementstatements based on the nature of service or materials provided. Tri-State and SRP also pay TEP for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities which are recorded as Other Revenues. K-102
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
INVENTORY
Materials and suppliesSupplies consist of transmission, distribution, and generatinggeneration construction and repair materials. TEP, UNS Gas and UNS ElectricWe record fuel, materials, and supply inventories at the lower of weighted average cost or market prices with cost being determined on a weighted average basis. TEP, UNS Gas and UNS Electric use full absorption costing, under which allprices. We capitalize handling and procurement costs are included in the cost of the inventory. Examples of these costs include direct material, direct(such as materials, labor, overhead costs, and transportation costs. See Note 4 regarding TEP’s fuel purchase contracts. costs) as part of the cost of the inventory.RECOVERY OF FUEL AND PURCHASED ENERGY COSTS TEP and UNS Electric Purchased Power and Fuel Adjustment Clause (PPFAC) As a result ofTEP and UNS Electric record the 2008 TEP Rate Order, TEP began deferring differences betweenactual fuel, transmission, and purchased energypower costs incurred on a monthly basis. Retail customers are billed monthly for the cost of fuel, transmission, and purchased power in Base Rates and via the recovery of suchcurrent Purchased Power and Fuel Adjustment Clause (PPFAC) rate. The difference between the costs in rates effective January 1, 2009. UNS Electric also defers differences between purchased energybilled to customers (recoveries) and actual fuel costs incurred and the recovery of such costs in rates. Fuel and purchased energy costto provide retail electric service is deferred. Cost over-recoveries (the excess(excess of fuel costs recovered in base rates over fuel costs incurred)cost recoveries) are deferred as regulatory liabilities and cost under-recoveries (the excess(excess of fuelactual costs incurred over fuel costs recovered in base rates)recovered) are deferred as regulatory assets. See Note 2. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) UNS Gas Purchased Gas Adjustor (PGA) UNS Gas defers the difference between actual gas costs incurred and the recovery of such costs in base rates under a Purchased Gas Adjustor (PGA) mechanism. Gas cost over-recoveries (the excess of gas costs recovered in base ratesunder the PGA mechanism over actual gas costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of actual gas costs incurred over gas costs recovered in base rates)via the PGA mechanism) are deferred as regulatory assets. See Note 2. RENEWABLE ENERGY STANDARDS (RES) AND RENEWABLE ENERGY CREDITS (RECs) Arizona adopted a mandatory Renewable Energy Standard (RES) that requires TEP and UNS Electric to increase their use of renewable energy and allows recovery of RES compliance costs through a surcharge to customers. TEP and UNS Electric defer the difference between RES qualified costs when incurred and the recovery of such costs through the RES surcharge. When RES qualified costs incurred exceed the amount recovered through the RES surcharge, the deferred costs are reflected as a regulatory asset. When RES qualified costs incurred are less than the amount recovered through the RES surcharge, the deferred revenue is reflected as a regulatory liability.
The ACC uses Renewable Energy Credits (RECs) to measure compliance with the RES requirements. A REC equals one kWh generated from renewable resources. The cost of REC purchases are qualified renewable expenditures recoverable through the RES surcharge. When TEP or UNS Electric purchasepurchases renewable energy, the premium paid above the market cost of conventional power is the REC cost a qualified cost recoverable through the RES surcharge, and the remaining cost is recoverable through the PPFAC. Also, when theWhen RECs are purchased, TEP and UNS Electric record the cost of the unretired RECs (an indefinite-lived intangible asset) as an intangible asset,Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. RECs are expensed to the income statement when theWhen RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount, in the RES requirements. income statements. See Note 2.INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in thefor financial statements.statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We record a valuation allowance to reduce deferred tax assets by a valuation allowance when, we believein the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. K-103
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Tax benefits are recognized in the financial statementsas reductions to Deferred Income Taxes – Noncurrent/Other Current Liabilities when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest Expense includes interest accrued by UniSource Energy and TEP on tax positionsTax benefits taken on tax returns which havedo not been reflectedmeet these requirements are recorded in the financial statements. Deferred Income Taxes – Noncurrent/Other Liabilities – Noncurrent. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets —– Noncurrent includes Income Taxes Recoverable Through Future Rates,income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 2. We account for Federal Energy Creditsfederal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. This benefit is offset byFederal energy credits generated in 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax expenselife of the underlying asset. Income Tax Expense attributable to the reduction in tax basis required to be recognized.is accounted for in the year the federal energy credit is generated. All other federal and state income tax credits are treated as a reduction to income tax expenseIncome Tax Expense in the year the credit arises. Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) TAXES OTHER THAN INCOME TAXES TEP, UNS Gas and UNS ElectricWe act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. WeAs we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable, on the balance sheet, to governmental agencies as customers are billed for these taxes and assessments. These amounts are not reflected in the income statement. statements.DERIVATIVE FINANCIAL INSTRUMENTS TEP, UNS Gas and UNS ElectricWe are exposed to energy price risk associated with their gas and purchased power requirements, volumetric risk associated with their seasonal load, and operational risk associated with their power plants, transmission, and transportation systems. TEP, UNS Gas and UNS ElectricWe reduce theirour energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability;stability, ensuring the companieswe can meet their load and reserve requirements;requirements, and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2 for further information regarding regulatory matters. 2.We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. We present cash collateral and derivative assets and liabilities associated with the same counterparty separately in our financial statements, and we bifurcateseparate all derivatives into their current and long-term portions on the balance sheet. K-104
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Cash Flow Hedges TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements relating to the Springerville Common Facilities LeaseUnit 1 Leases and variable rate industrial development bonds.revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a six-year power supply agreement using a six-year power purchase swap agreement. UNS Electric entered into a cash flow hedge in August 2011 to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP accountsand UNS Electric account for cash flow hedges as follows: The effective portion of the changes in the fair value of TEP’sthe interest rate swaps and TEP’s six-year power purchase swap agreement are recorded in Accumulated Other Comprehensive Income (AOCI) and the ineffective portion, if any, is recognized in earnings; and When TEP determinesand UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizesand UNS Electric recognize the changes in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs. We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items. We discontinue hedge accounting when: (1) the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (2) the derivative expires or is sold, terminated, or exercised; (3) it is no longer probable that the forecasted transaction will occur; or (4) we determine that designating the derivative as a hedging instrument is no longer appropriate. Mark-to-Market
| • | | TEP | | | | | TEP’s non-trading hedges, such as forward power purchase contracts indexed to gas, short-term forward power sales contracts, or call and put options (gas collars), that did not qualify for either cash flow hedge accounting treatment or the normal scope exception are considered mark-to-market transactions. TEP hedges a portion of its monthly natural gas exposure for plant fuel, gas-indexed purchased power and spot market purchases with fixed price contracts for a maximum of three years. Beginning in December 2008, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC under terms of the 2008 TEP Rate Order. | | | | | In 2008, TEP entered into energy-related derivatives for trading purposes. However, the net trading activities represented less than 1% of TEP’s revenue from wholesale sales in 2008. In 2009 and 2010, TEP had no trading activity. | | | • | | UNS Gas | | | | | UNS Gas enters into derivatives such as forward gas purchases and gas swaps, creating price stability and reducing exposure to natural gas price volatility that may result in delayed recovery under the PGA. Beginning in December 2008, unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the UNS Gas PGA mechanism permits the recovery of the cost of hedging contracts. | | | • | | UNS Electric | | | | | UNS Electric hedges a portion of its purchased power exposure to fixed price and natural gas-indexed contracts with forward power purchases, financial gas swaps, and call and put options. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the UNS Electric PPFAC mechanism allows recovery of the prudent costs of contracts for hedging fuel and purchased power costs. |
K-105
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)(Continued) Subsequent Measurement at Fair Value TEP’s hedges, such as forward power purchase contracts indexed to gas, short-term forward power sales contracts, or call and put options (gas collars), that did not qualify for either cash flow hedge accounting treatment or the normal scope exception are considered transactions subsequently measured at fair value. TEP hedges a portion of its monthly natural gas exposure for plant fuel, gas-indexed purchased power, and spot market purchases with fixed price contracts for a maximum of three years. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC. UNS Gas enters into derivative contracts such as forward gas purchases and gas swaps, creating price stability and reducing exposure to natural gas price volatility that may result in delayed recovery under the PGA. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the PGA mechanism permits the recovery of the cost of hedging contracts. UNS Electric hedges a portion of its purchased power exposure to fixed price and natural gas-indexed contracts with forward power purchases, financial gas swaps, and call and put options. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability, as the PPFAC mechanism allows recovery of the prudent costs of contracts for hedging fuel and purchased power costs. Normal PurchasePurchases and Normal Sale TEP, UNS Gas and UNS ElectricSalesWe enter into forward energy purchase and sales contracts, including call options, to support their current load forecasts and enter into contracts with counterparties for load serving requirements or counterparties with generating capacity.capacity to support our current load forecasts. These contracts are not required to be marked-to-marketmeasured at fair value and are accounted for on an accrual basis. We evaluate our counterparties on an ongoing basis for non-performance risk to ensure it does not impact our ability to obtain the normal purchases and normal sales scope exception. 2008 Accounting Summary
Prior to December 2008, we recorded unrealized gains and losses on derivative instruments as follows:
TEP’s interest rate swaps, TEP’s forward contracts to sell excess capacity, and TEP’s and UNS Gas’ forward gas swaps were recorded in AOCI;
TEP’s non-trading hedges such as forward power purchase contracts indexed to gas, and TEP’s forward purchase and sale trading contracts were recorded in the income statement; and
All other commodity contracts were reflected on the balance sheet as either regulatory assets or regulatory liabilities.
PENSION AND OTHER POSTRETIREMENTRETIREE BENEFITS TEP, UNS Gas and UNS ElectricWe sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on employees’ years of service and average compensation. TEP, UNS Gas and UNS ElectricWe also maintain a Supplemental Executive Retirement Plan (SERP) for upper management. TEP also provides limited health care and life insurance benefits for retirees. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers, and expect to recover these costs over the estimated service lives of employees. Additionally, we provide supplemental retirement benefits to certain employees whose benefits are subject to IRS benefit or compensation limitations. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirementretiree benefit expense are determined by actuarial valuations, based on assumptions that are evaluatedwe evaluate annually. See Note 9 for additional information on pension and other postretirement benefits. SHARE-BASED COMPENSATION
UniSource Energy has a share-based long-term incentive plan. UniSource Energy grants awards to officers and directors on the grant-date at fair value of the award (with some limited exceptions). Generally, compensation costs are recognized over the service period (vesting period). Compensation cost is not recognized for anticipated forfeitures of equity instruments prior to vesting. Our share-based compensation plans are described more fully in Note 10.
RECLASSIFICATIONS
In an effort to more closely match GAAP taxonomies in extensible business reporting language, more commonly known as XBRL, UniSource Energy and TEP made the following balance sheet presentation changes from previously issued financial statements to conform to the current presentation:
Accounts Receivable — Retail and Other, and Accounts Receivable Wholesale are no longer shown separately; instead they are reported as Accounts Receivable — Customer, or Accounts Receivable — Non-customers reported in Other Assets;
Fuel Inventory is reported separately; previously, it was combined with Materials Inventory;
Rather than being shown separately, all regulatory balances are reported in either Regulatory Assets — Current, Regulatory Assets — Noncurrent, Regulatory Liabilities - Current, or Regulatory Liabilities — Noncurrent;
Accounts Payable and Accounts Payable — Purchased Power are reported in the aggregate as Accounts Payable — Trade; and
Customer Advances for Construction are no longer shown separately; instead, they are reported as Other within Deferred Credits and Other Liabilities.
9. K-106
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) To(Continued)RECLASSIFICATIONS UNS Energy and TEP reclassified the following items in the 2011 and 2010 financial statements to be comparable to the presentation in the 2012 financial statements: UNS Energy reclassified $4 million of 2011 trade receivables with the 2010 presentation, UniSource Energy’s 2009 balance sheet incorporated immaterial reclassifications that mainly impactedcredit balances from Accounts Receivable – Customer to Other Current Assets,Liabilities; UNS Energy and TEP reclassified $4 million of 2011 and 2010 O&M costs paid from Fuel Costs Paid to Payment of Operations and Maintenance Costs in the statements of cash flows; TEP reclassified $2 million of 2011 trade receivables with credit balances from Accounts Receivable – Customer to Other Current Liabilities; UNS Energy and TEP reclassified $1 million of 2011 payroll withholding taxes from Other Current Liabilities Other Long-Term Liabilitiesto Accrued Employee Expenses; and Regulatory Liabilities — Noncurrent. On the cash flow statement UniSource UNS Energy and TEP now classifyreclassified $35 thousand from Taxes Other Than Income Taxes to Other Expense in the Equity portion of AFUDC as an Operating cash outflow, and a gross reduction of Capital Expenditures. UniSource Energy also had immaterial reclassifications impacting Electric Wholesale Sales and Purchased Energy on its 2009 and 20082011 income statements.statement to conform to current year presentation. NOTE 2. REGULATORY MATTERS ACCOUNTING FOR RATERATES AND REGULATION The Arizona Corporation Commission (ACC)ACC and the Federal Energy Regulatory Commission (FERC)FERC each regulate portions of the utility accounting practices and rates used by TEP, UNS Gas, and UNS Electric utility accounting practices.Electric. The ACC has authority overregulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, and transactions with affiliated parties. The FERC regulates the terms and prices of transmission services and wholesale electricity sales, wholesale transport and purchases of natural gas. sales.TEP RATES AND REGULATION 1999 Settlement Agreement
We believe that the 1999 Settlement Agreement that established the rates TEP charged before the 2008 TEP Rate Order contemplated the use of market-based retail rates for generation service that would have been market-based beginning January 1, 2009. As part of the 2008 TEP Rate Order, TEP and other parties to the order relinquished all claims related to the 1999 Settlement Agreement.
1999 Transition Recovery Asset
TEP’s Transition Recovery Asset consisted of generation-related regulatory assets and a portion of TEP’s generation plant asset costs. Transition costs that were recovered through the Fixed Competition Transition Charge (CTC) included: (1) the Transition Recovery Regulatory Asset; (2) a small portion of 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 that were amortized as an off-balance sheet regulatory asset through 2003. In 2008, TEP fully amortized the remaining $24 million Transition Recovery Asset balance, to the income statement as costs were fully recovered through rates.
By December 1, 2008, when new rates went into effect, TEP had collected $58 million of true-up revenues and recorded a $58 million reserve for Fixed CTC revenue to be refunded against its Electric Retail Sales in 2008. The 2008 TEP Rate Order requires TEP to return the Fixed CTC true-up revenues to customers by reducing the PPFAC balance.
The 2008 TEP Rate Order, issued by the ACC and effective December 1, 2008, provided for a cost of service rate methodology for TEP’s generation assets; an average base rate increase of 6% over TEP’s previous retail rates;Base Rates; an 8% authorized rate of return on Original Cost Rate Base (OCRB) of approximately $1 billion; a 5.6% rate of return on Fair Value Rate Base (FVRB) of approximately $1.5 billion, which did not include a return on the fair value increment of rate base (the fair value increment of rate base represents the difference between the OCRB and FVRB). The ACC authorized a fuel rate included in base ratesBase Rates of 2.9 cents per kilowatt-hour (kWh); a PPFAC effective January 1, 2009; and a base rate increase moratorium through January 1, 2013; and a waiver of any claims under the 1999 Settlement Agreement. As a result of the 20082013.Pending TEP Rate Order,Case In July 2012, TEP reapplied regulatory accounting to its generation operations. In addition, in December 2008, TEP began deferring its mark-to-market adjustments for derivative instruments that are expected to be recovered through the PPFAC as either regulatory assets or regulatory liabilities. K-107
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
On December 1, 2008, TEP implemented new depreciation rates that included a component for net negative salvage value for all generation assets except Luna and new depreciation rates for distribution and general plant assets that extended the depreciable lives of these assets.
Rates for generation service are based on a cost-of-service methodology. All generation assets acquired by TEP between December 31, 2006 and December 31, 2012 — from the end of test year used in TEP’s latest rate case filing through the end of the base rate freeze established by the 2008 TEP Rate Order — shall be included in TEP’s rate base at their respective original depreciated cost, subject to subsequent review and approval by the ACC in future rate cases. Luna Energy Facility is included in TEP’s original cost rate base at its net book value of $48 million as of December 31, 2006.
The non-fuel costs for Unit 1 of Springerville Generating Station (Springerville Unit 1) are recovered through base rates at $25.67 per kilowatt (kW) per month, which approximates the levelized cost of that unit through the remainder of the lease term.
Impact of Reapplying Regulatory Accounting to TEP’s Generation Operations
As a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations in December 2008, producing the following adjustments:
| | | | | | | | | Income Statement | | | | | (Gain)/Loss | | | | | -Millions of Dollars- | | | Recorded in Fuel: | | | | | | San Juan Coal Contract Amendment | | $ | (9 | ) | | Retiree Health Care and Final Mine Reclamation Costs | | | (15 | ) | | Unrealized Losses on Derivative Contracts (PPFAC) | | | (8 | ) | | Deregulation Costs Recorded in O&M | | | (1 | ) | | Property Taxes | | | (7 | ) | | | | | | Pre-Tax Impact of Reapplying Regulatory Accounting | | $ | (40 | ) | | | | | |
K-108
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Income Statement Impact of Applying Regulatory Accounting
Regulatory accounting had the following effects on TEP’s net income, in addition to the impact of reapplying regulatory accounting to its generation operations for 2008:
| | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | Operating Revenues | | | | | | | | | | | | | | Amortization of the Fixed CTC Revenue to be Refunded | | $ | (10 | ) | | $ | (12 | ) | | $ | — | | Operating Expenses | | | | | | | | | | | | | | Depreciation (related to Net Cost of Removal for Interim Retirements) | | | 30 | | | | 41 | | | | 10 | | | Deferral of PPFAC Costs | | | (23 | ) | | | (21 | ) | | | — | | | Amortization of 1999 Transition Recovery Asset | | | — | | | | — | | | | 24 | | | Other | | | 4 | | | | 13 | | | | — | | Non-Operating Income/Expenses | | | | | | | | | | | | | | Long-Term Debt (Amortization of Loss on Reacquired Debt Costs) | | | (1 | ) | | | — | | | | 1 | | | AFUDC — Equity | | | (4 | ) | | | (4 | ) | | | (3 | ) | | Income Taxes — Deferral | | | — | | | | — | | | | 4 | | | Offset by the Tax Effect of the Above Adjustments | | | 2 | | | | (7 | ) | | | (14 | ) | | | | | | | | | | | | Net (Decrease)/Increase to Net Income | | $ | (2 | ) | | $ | 10 | | | $ | 22 | | | | | | | | | | | | |
K-109
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The following table summarizes TEP’s regulatory assets and liabilities:
| | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | Regulatory Assets — Current | | | | | | | | | Property Tax Deferrals(1) | | $ | 16 | | | $ | 16 | | Deregulation Costs(2) | | | 4 | | | | 4 | | Other Current Regulatory Assets(5) | | | 14 | | | | 7 | | | | | | | | | | Total Regulatory Assets — Current | | | 34 | | | | 27 | | | | | | | | | | | | | | | | | | | | Regulatory Assets — Noncurrent | | | | | | | | | Pension and Other Postretirement Benefits(4) | | | 90 | | | | 80 | | Income Taxes Recoverable through Future Revenues(3) | | | 18 | | | | 18 | | | PPFAC | | | 41 | | | | — | | PPFAC — Final Mine Reclamation and Retiree Health Care Costs(6) | | | 17 | | | | 15 | | Deregulation Costs(2) | | | 3 | | | | 7 | | Other Regulatory Assets(5) | | | 14 | | | | 17 | | | | | | | | | | Total Regulatory Assets — Noncurrent | | | 183 | | | | 137 | | | | | | | | | | | | | | | | | | | | Regulatory Liabilities — Current | | | | | | | | | | PPFAC — Fixed CTC Revenue to be Refunded | | | (36 | ) | | | (9 | ) | RES(7) | | | (22 | ) | | | (17 | ) | | Other Current Regulatory Liabilities | | | (1 | ) | | | (1 | ) | | | | | | | | | Total Regulatory Liabilities — Current | | | (59 | ) | | | (27 | ) | | | | | | | | | | | | | | | | | | | Regulatory Liabilities — Noncurrent | | | | | | | | | Net Cost of Removal for Interim Retirements(8) | | | (169 | ) | | | (162 | ) | | PPFAC | | | — | | | | 20 | | | PPFAC — Fixed CTC Revenue to be Refunded | | | — | | | | (37 | ) | | Other Regulatory Liabilities | | | (1 | ) | | | — | | | | | | | | | | Total Regulatory Liabilities — Noncurrent | | | (170 | ) | | | (179 | ) | | | | | | | | | Total Net Regulatory Liabilities | | $ | (12 | ) | | $ | (42 | ) | | | | | | | | |
Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:
| | | (1) | | Property Tax is recorded based on historical ratemaking treatment allowing recovery as costs are paid, rather than as costs are accrued. While these assets do not earn a return, the costs are fully recovered in rates over an approximately six-month period. | | (2) | | Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, the recovery of which was authorized by the ACC in the 2008 TEP Rate Order. These assets are included in rate base and consequently earn a return. TEP is recovering these costs through rates over a four-year period, beginning in December 2008. | | (3) | | Income Taxes Recoverable Through Future Revenues, while not included in rate base, are amortized over the life of the assets. TEP does not earn a return on these assets. | | (4) | | TEP records a regulatory pension and postretirement benefit asset related to its employees. Based on past regulatory actions, TEP expects to recover these costs in rates over the estimated service lives of employees. TEP does not earn a return on these assets. | | (5) | | Other assets includes unamortized loss on reacquired debt (recovery over next 21 years); coal contract amendment (recovery over next 8 years); and other assets (recovery by 2014). TEP does not earn a return on these assets. | | (6) | | Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at San Juan, Four Corners and Navajo. TEP is required to recognize the present value of its liability associated with final reclamation and retiree health care obligations. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the life of the mines, which is estimated to be between 17 and 34 years. TEP does not earn a return on these assets. |
K-110
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Regulatory liabilities represent items that TEP either expects 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:
| | | (7) | | RES tariff proceeds in excess of authorized renewable expenditures. | | (8) | | Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, general and intangible plant which are not yet expended. TEP collects through revenue the net cost of removal of interim retirements for generation plant, which it has not yet expended. |
Purchased Power and Fuel Adjustment Clause (PPFAC)
The TEP PPFAC became effective January 1, 2009. The PPFAC allows recovery of fuel and purchased power costs, including demand charges, transmission costs and the prudent costs of contracts for hedging fuel and purchased power costs. The PPFAC consists of a forward component and a true-up component.
The forward component of 0.18 cents per kWh became effective on April 1, 2009, and is updated each year. The forward component is based on the forecasted fuel and purchased power costs for the twelve-month period from April 1 to March 31 of the following year, less the average base cost of fuel and purchased power of approximately 2.9 cents per kWh, which is embedded in base rates.
The true-up component will reconcile any over/under collected amounts from the preceding 12 month period and will be credited to or recovered from customers in the subsequent year.
The PPFAC mechanism provides for the annual adjustment of retail rates to reflect variations in retail fuel and purchased power costs from the base power supply rate currently included in base rates. The current PPFAC rate of 0.09 cents per kWh, effective April 2010, includes a forward component credit of (0.08) cents and a true-up component of 0.17 cents.
TEP credited Fixed CTC revenue to be refunded ($58 million collected from May 2008 to November 30, 2008) to customers as an offset to the PPFAC rate. This credit will offset the forward and true-up components of the PPFAC, resulting in a PPFAC charge of zero to customers until the Fixed CTC revenue to be refunded is fully credited, which is expected to occur by the end of 2011.
The following table shows the changes in PPFAC related accounts and the impacts on revenue and expense for the year ended December 31, 2010:
| | | | | | | | | | | | | | | | | | | | | Assets (Liability) at | | | Year Ended | | | | | December 31, | | | December 31, 2010 | | | | | | | | | | | | | | | | Reduction to Fuel | | | | | | | | | | | | | Impact on | | | and Purchased | | | | | 2010 | | | 2009 | | | Revenue | | | Power Expense | | | | | -Millions of Dollars- | | PPFAC — Fixed CTC Revenue to be Refunded(current and noncurrent) | | $ | (36 | ) | | $ | (46 | ) | | $ | 10 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PPFAC(current and noncurrent) | | $ | 58 | | | $ | 35 | | | | | | | $ | 23 | | | | | | | | | | | | | | | | |
K-111
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
UNS GAS RATES AND REGULATION
2010 UNS Gas Rate Order
In November 2008, UNS Gas filed a general rate case, (onon a cost of service basis)cost-of-service basis, with the ACC requesting a total rateBase Rate increase of 6%approximately 15% to cover a revenue deficiency of $10$128 million. Effective April 2010, the ACC approvedTEP requested a rate increase of 2% ($3 million), including an 8%7.74% return on originalan OCRB of $1.5 billion and a 5.68% return on FVRB of $2.3 billion. The return on FVRB includes a 1.56% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million).TEP requested a Lost Fixed Cost Recovery (LFCR) mechanism to recover non-fuel costs that would go unrecovered due to lost kilowatt-hour (kWh) sales as a result of implementing the ACC’s Electric Energy Efficiency Standards (Electric EE Standards) and the RES. TEP also requested a mechanism, which would be adjusted annually, to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. TEP proposed a three-year pilot program allowing for investment in Electric EE Programs to meet the Electric EE Standards in the most cost rate base. UNS Gas haseffective manner. Under TEP’s proposal, energy efficiency investments would be considered regulatory assets and amortized over a four-year period. TEP would earn a return on investment and recover the following Regulatory Assetsreturn and Liabilities:
| | | | | | | | | | | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | Current Assets | | | | | | | | | Derivative Instruments(1) | | $ | 8 | | | $ | 5 | | Other Regulatory Assets | | | | | | | | | Pension Assets(2) | | | 2 | | | | 2 | | Derivative Instruments(1) | | | 2 | | | | 3 | | Other Regulatory Assets(3) | | | 1 | | | | 1 | | Regulatory Liabilities | | | | | | | | | | PGA — Over-Recovered Purchased Energy Costs | | | (10 | ) | | | (10 | ) | Net Cost of Removal for Interim Retirements(4) | | | (22 | ) | | | (21 | ) | | | | | | | | | Total Net Regulatory Assets (Liabilities) | | $ | (19 | ) | | $ | (20 | ) | | | | | | | | |
Regulatory assets are either being collected in rates or are expected to be collectedamortization expense through rates in a future period, as described below:
| | | (1) | | Derivative instruments represent the unrealized gains or losses on hedge contracts that are expected to be recovered through the PGA. UNS Gas does not earn a return on these costs. | | (2) | | Pension assets represent the unfunded status of UNS Gas’ share of the UES pension and other postretirement benefit plans that it expects, based on past regulatory actions, to recover through rates. UNS Gas does not earn a return on these costs and expects to recover them in rates over the estimated service lives of its employees. | | (3) | | Other Regulatory Assets consist of UNS Gas’ 2007 and 2008 rate case costs, which are recoverable over 3 years and the costs of its low income assistance program. UNS Gas does not earn a return on these costs. |
Regulatory liabilities represent items that UNS Gas expects either to pay to customers through billing reductions in future periods or to use for the purpose for which they were collected from customers, as described below:
| | | (4) | | Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations. These are amounts collected through revenue for the net cost of removal of interim retirements for which removal costs have not yet been expended. |
existing DSM surcharge. K-112
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) Purchase(Continued)In February 2013, TEP, ACC Staff, and other parties to TEP’s pending rate case proceeding entered into a proposed settlement agreement. The proposed settlement agreement requires the approval of the ACC before new rates can become effective. UNS Gas Adjustor (PGA) Mechanism Rates2012 UNS Gas’ retail rates includeGas Rate Order In April 2012, the ACC approved a PGABase Rate increase of $2.7 million, or 1.8%, and a mechanism that mitigates the volatility of natural gas prices while allowingto enable UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor on a per-therm basis. The PGA mechanism includes the following two components: | (1) | | The PGA Factor reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceeding 12 months. The PGA Factor automatically adjusts monthly, but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. The cumulative difference between UNS Gas’ actual gas costs and those recovered through the PGA Factor are tracked through the PGA Bank, a balancing account. |
| (2) | | A PGA Surcharge or Surcredit can, upon approval by the ACC, be used to reduce the over- or under-collected balance in the PGA Bank over a certain period. UNS Gas is required to request such a credit if its PGA Bank balance reflects an overcollection of $10 million or more on a billed basis. |
A PGA Surcredit of $0.04 cents per therm was applied to UNS Gas’ bills from October 2007 through April 2008. From May 2008 through October 2009, there was no surcharge or surcredit in effect. An $0.08 cent per therm PGA Surcredit was in place from November 2009 through October 2010. Since then, UNS Gas has not employed a PGA Surcharge or Surcredit. See table above for the total balance of Over-Recovered Purchased Energy Costs.
Income Statement Impact of Applying Regulatory Accounting
If UNS Gas had not applied regulatory accounting its net income would have been $1 million lower in 2010, and $4��million lower in 2008lost fixed cost revenues as UNS Gas would have recognized under-recovered purchased energy costs and unrealized losses on its commodity derivative instruments as an expense to its income statement rather than as a reduction to its regulatory liability. Net income would have been $6 million higher in 2009 as UNS Gas could have recognized over-recovered purchased energy costs and unrealized gains on its commodity derivative instruments as a reduction to its expenses in the income statement rather than recording them as a regulatory liability.
UNS ELECTRIC RATES AND REGULATION
2008 UNS Electric Rate Order
In the May 2008 rate order, the ACC approved a rate increase of 2.5% ($4 million) effective June 2008. As a result of implementing the ACC’s Gas Energy Efficiency Standards (Gas EE Standards). UNS Gas recognized less than $0.1 million of revenue under the LFCR in 2012.The ACC approved an authorized rate of return of 8.3% on an OCRB of $183 million, and a 1.0% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million). The new rates became effective in May 2008 rate order limiting recovery of deferred rate case costs, 2012. UNS Electric expensed $0.3 million of the $0.6 million deferred costs in May 2008. Rates K-113
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
2010 UNS Electric Rate Order In April 2009, UNS Electric filed a general rate case with the ACC (on a cost of service basis) requesting a rate increase of 7% to cover a revenue deficiency of $14 million. In September 2010, the ACC approved a base rate increase of $7 million, or 4% ($7 million), including an 8%8.3% authorized rate of return on original costan OCRB of $169 million, and a 1.3% return on the fair value increment of rate base effective October 1, 2010.(the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $73 million). The ACC approvedorder also authorized new depreciation rates, effective October 1, 2010, resulting in an expected $1 million annual reduction of depreciation expense. The2010.In July 2011, UNS Electric completed the ACC rate order also authorizedand the FERC approved purchase by UNS Electric of BMGS from UED at its netfor $63 million, UED’s book value of approximately $62 million. Upon purchase of this facility, subject to FERC approval and other conditionsfor the assets. BMGS will be placed into rate basewas included in UNS Electric’s Rate Base through a revenue-neutral rate reclassification of approximately 0.7 cents per kWh from base power supply rate to non-fuel Base Rates. Pending UNS Electric Rate Case In December 2012, as required in the 2010 UNS Electric Rate Order, UNS Electric filed with the ACC a general rate case, on a cost-of-service basis, requesting a non-fuel Base Rate increase of $7.5 million, or 4.6%. UNS Electric requested a rate of return of 8.4% on an OCRB of approximately $217 million and a 6.7% rate of return on a FVRB of $286 million. The return on FVRB includes a 1.6% return on the fair value increment of rate base rate. Regulatory Assets(the fair value increment of rate base represents the difference between OCRB and Liabilities
FVRB of approximately $69 million).UNS Electric requested a LFCR mechanism to recover non-fuel costs that would go unrecovered due to lost kWh sales as a result of implementing Electric EE Standards and the RES. In addition to the LFCR mechanism, UNS Electric requested a Transmission Cost Adjustor (TCA). The TCA is designed to track changes to UNS Electric’s regulatory assetsFERC approved Open Access Transmission Tariff (OATT) rate which is updated annually and liabilities were as follows: | | | | | | | | | | | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | Current Regulatory Assets | | | | | | | | | Derivative Instruments(1) | | $ | 12 | | | $ | 9 | | PPFAC — Under-Recovered Purchased Power Costs(5) | | | 2 | | | | — | | Other Regulatory Assets | | | | | | | | | Derivative Instruments(1) | | | 2 | | | | 2 | | Pension Assets(2) | | | 2 | | | | 2 | | Other(3) | | | — | | | | 1 | | Current Regulatory Liabilities | | | | | | | | | PPFAC — Over-Recovered Purchased Power Costs(5) | | | — | | | | (5 | ) | RES(4) | | | (1 | ) | | | — | | Other Regulatory Liabilities | | | | | | | | | Net Cost of Removal for Interim Retirements(6) | | | (9 | ) | | | (12 | ) | | | | | | | | | Total Net Regulatory Assets (Liabilities) | | $ | 8 | | | $ | (3 | ) | | | | | | | | |
Regulatory assets are either being collected in rates or are expectedwould allow UNS Electric to be collected through ratesrecover transmission costs in a future period, as described below:
| | | (1) | | Derivative instruments represent the unrealized gains or losses on hedge contracts that are expected to be recovered through the PPFAC. UNS Electric does not earn a return on these costs. | | (2) | | Pension assets represent the unfunded status of UNS Electric’s share of the UES pensiontimely manner.COST RECOVERY MECHANISMS TEP, UNS Gas, and other postretirement benefit plans that it expects, based on past regulatory actions, to recover through rates. UNS Electric does not earn a return on these costs. | | (3) | | Other Regulatory Assets are not included in rate base and do not earn a return. The recovery period is 3 years. |
Regulatory liabilities represent items that UNS Electric expects either to pay to customershave received regulatory decisions that allow for more timely recovery of certain costs through billing reductions in future periods or to use for the purpose for which they were collected from customers, asrecovery mechanisms described below:
| | | (4) | | RES tariff proceeds in excess of authorized renewable expenditures. The ACC approved a RES tariff for UNS Electric, effective June 1, 2008, to allow UNS Electric to recover the cost of authorized renewable expenditures, such as payments to customers who have renewable energy resources or the incremental cost of renewable power generated or purchased by UNS Electric. Any surcharge collected in excess of authorized renewable expenditures will be reflected in the financial statements as a current regulatory liability. Conversely, authorized renewable expenditures in excess of the RES collected will be reflected as a current regulatory asset. The amount of the surcharge is reset annually and incorporates an adjustor mechanism that, upon approval of the ACC, allows UNS Electric to apply any shortage or surplus in the prior year’s program expenses to the subsequent year’s RES tariff. |
below. K-114
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
| | | (5) | | 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 PPFAC approved by the ACC. The PPFAC incorporates a revenue surcharge or surcredit (that adjusts the customer’s rate for delivered purchased power) to collect or return under- or over-recovery of costs. | | (6) | | Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations. These are amounts collected through revenue for the net cost of removal of interim retirements for which removal costs have not yet been expended. |
Purchased Power and Fuel Adjustment Clause (PPFAC) 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 under-recovered or return over-recovered costs. The PPFAC passes alongprovides for the adjustment of Retail Rates to reflect variations in retail fuel, transmission, and purchased power costs, incurred to provide service to retail customers, including demand charges, and the prudent costs of contracts for hedging costs. fuel. TEP and UNS Electric record deferrals for recovery or refund to the extent actual retail fuel, transmission, and purchased power costs vary from the fuel rate and current PPFAC rates. The TEP PPFAC became effective in January 2009. A PPFAC rate adjustment is made annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period automatically unless suspended by the ACC. UNS Electric’s PPFAC rate adjustment is made annually each June 1st, effective for the subsequent 12-month period.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The PPFAC mechanism hasrate includes: 1) a forward component, under which TEP and UNS Electric recover or refund differences between, a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and, b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component. The forward component, reflects the differencewhich reconciles differences between forecastedactual fuel, transmission, and purchased power costs and those recovered through the base costcombination of the fuel rate and purchased power included in base rates. the forward component for the preceding 12-month period. The true-up component reconciles the previous year’s actual fuel and purchased power costs with the amounts collected through base and PPFAC rates to allow recovery of any difference in the subsequent PPFAC year. The PPFAC rate is updated on June 1 of each year, beginning June 1, 2009. The charttable below summarizes theTEP’s and UNS Electric’s PPFAC rates in cents per kWh for the prior three years:
| | | | | | | | | | | | | | | | | | | | | | | | | October 2010 | | | June 2010 to | | | June 2009 | | | June 2008 | | | Prior to June | | | | | to May 2011 | | | September 2010 | | | to May 2010 | | | to May 2009 | | | 2008 | | | Charge (Credit) | | | 0.08 | | | | (0.28 | ) | | | (1.06 | ) | | | 1.50 | | | | 1.80 | | | Base Rate | | | 6.77 | | | | 7.10 | | | | 7.10 | | | | 7.10 | | | | 5.20 | |
Income Statement Impact of Applying Regulatory Accounting
If UNS Electric had not applied regulatory accounting, net income would have been $7 million lower in 2010 and $16 million lower in 2008, as UNS Electric would have recognized higher purchased energy and unrealized losses on its commodity derivative instruments as an expensethat are compared against actual fuel cost to its income statement, rather than as eithercreate regulatory assets or liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2012 | | | 2011 | | | | | June -
December | | | April -
May | | | January -
March | | | June -
December | | | April -
May | | | January -
March | | TEP | | | | | | | | | | | | | | | | | | | | | | | | | PPFAC | | | 0.77 | | | | 0.77 | | | | 0.53 | | | | 0.53 | | | | 0.53 | | | | 0.09 | | CTC(1) | | | 0.00 | | | | 0.00 | | | | (0.53 | ) | | | (0.53 | ) | | | (0.53 | ) | | | (0.09 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Total PPFAC Rate | | | 0.77 | | | | 0.77 | | | | — | | | | — | | | | — | | | | — | | UNS Electric | | | (1.44 | ) | | | (0.88 | ) | | | (0.88 | ) | | | (0.88 | ) | | | 0.08 | | | | 0.08 | |
| (1) | Competition Transition Charge |
As part of the TEP 2008 Rate Order, TEP was required to credit previously collected revenues to customers through the PPFAC. As a reductionresult, the PPFAC charge had been zero since it became effective in January 2009. In November 2011, the Fixed CTC revenue was fully refunded to its regulatory liabilities. If customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate was approved by the ACC in April 2012. UNS Electric had not applied regulatory accounting, net income would have been $7Gas Purchased Gas Adjustor The PGA mechanism allows UNS Gas to adjust Retail Rates to reflect variations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million higher in 2009 as UNS Electric would have recognized lower purchased power costs and unrealized gainsor more on its commodity derivative instruments as a reduction to expense rather than recordingbilled-to-customer basis. In 2012, the ACC approved a PGA temporary surcredit of 4.5 cents per therm effective for the period from May 2012 through April 2014, or when the PGA balance reaches zero, whichever comes first. At December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis, an increase of $2 million from December 31, 2011. The PGA rate ranged from $0.5202 to regulatory liabilities. $0.6501 cents per therm in 2012, and ranged from $0.6593 to $0.7296 cents per therm in 2011. K-115
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
TEP, UNS Gas and UNS Electric RES and Energy Efficiency Standards (EE Standards)
The ACC has adopted a mandatory Renewable Energy Standard (RES)RES that requires TEP and UNS Electric to expand their use of renewable energy through efforts funded by customer surcharges. TEP and UNS Electric are required to file five-year implementation plans with the ACC and annually seek approval for the upcoming year’s RES funding amount. Similarly, TEP, UNS Gas, and UNS Electric recover the cost of ACC-approved energy efficiency programs through Demand Side Management (DSM)DSM surcharges established by the ACC. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table shows RES and DSM tariffs collected: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Electric | | | | | | | UNS Gas | | | UNS Electric | | | | | TEP RES | | | RES | | | TEP DSM | | | DSM | | | DSM | | | | | -Millions of Dollars- | | 2010 | | $ | 32 | | | $ | 7 | | | $ | 10 | | | $ | 1 | | | $ | 2 | | | 2009 | | | 29 | | | | 5 | | | | 7 | | | | 1 | | | | 1 | | | 2008 | | | 9 | | | | 2 | | | | — | | | | — | | | | 1 | |
In May 2010, the ACC approved a | | | | | | | | | | | | | | | | | | | | | | | | TEP RES | | | UNS Electric RES | | | TEP DSM | | | UNS Gas DSM | | | UNS Electric DSM | | | | | -Millions of Dollars- | | 2012 | | $ | 30 | | | $ | 7 | | | $ | 11 | | | $ | 1 | | | $ | 7 | | 2011 | | | 35 | | | | 7 | | | | 11 | | | | 1 | | | | 2 | | 2010 | | | 32 | | | | 7 | | | | 10 | | | | 1 | | | | 2 | |
Renewable Energy Standard The following table summarizes TEP’s authorized 2010-2012 RES programs: | | | | | | | | | | | | | | | | Years Ended
December 31, | | | | | 2012(2) | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Investment in Company-Owned Solar Projects | | $ | 28 | | | $ | 28 | | | $ | 14 | | Return on Investment for Company-Owned Solar Projects | | | 2 | | | | 1 | | | | — | | Program Budget(1) | | | 30 | | | | 36 | | | | 44 | |
| (1) | The authorized program budget for 2010 includes $12 million in carryforward of 2008 and 2009 RES funds. |
| (2) | TEP met the 2012 renewable energy target of 3.5%. |
The funding mechanism for approximately $14 million of TEP-owned renewable energy projects. The mechanism allows TEP to use RES funds to recover operating costs, depreciation, and property taxes, and to earn a return on its investmentcompany-owned solar projects until the projects can be incorporated in TEP’s base rates. These projects were completed in 2010 and TEP began recovering their costs through the RES tariff inBase Rates. In January 2011. In August 2010, the ACC approved new Electric EE Standards designed to require TEP, UNS Electric and other affected electric utilities to implement cost effective DSM programs. In 2011, the EE Standards target total retail kWh savings equal to 1.25% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail kWh sales of 22% by 2020. The EE Standards provide for the recovery of costs to implement the DSM programs.
In August 2010, the ACC approved new Gas EE Standards designed to require UNS Gas and other affected gas utilities to implement cost effective DSM programs. In 2011, the Gas EE Standards target total retail therm savings equal to 0.5% of 2010 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.
In September 2010, the ACC approved a proposal for UNS Electric to invest approximately $5 million in UNS Electric owned solar projects per year between 2011 and 2014. The plan allows UNS Electric to use RES funds to recover operating costs, depreciation, property taxes and provides UNS Electric with a return on its investment until these costs can be incorporated in UNS Electric’s base rates.
In December 2010,2013, the ACC approved TEP’s 20112013 RES implementation plan. Under the plan, with the ACC.TEP expects to collect approximately $36 million from retail customers during 2013. The plan includes a proposal for TEP to investan investment of $28 million in TEP owned2013 for company-owned solar projects, of which $8 million was previously approved by the ACC, as well as the continuation of the funding mechanism for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $4 million pre-tax in 2011. 2013 on solar investments made in 2010, 2011, and 2012.The plan allows TEPfollowing table summarizes UNS Electric’s authorized 2010-2012 RES programs: | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012(1) | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Investment in Company-Owned Solar Projects | | $ | 5 | | | $ | 5 | | | $ | — | | Return on Investment for Company-Owned Solar Projects | | | 1 | | | | — | | | | — | | Program Budget | | | 8 | | | | 8 | | | | 9 | |
| (1) | UNS Electric met the 2012 renewable energy target of 3.5%. |
UNS Electric will invest up to use RES funds$5 million per year in company-owned renewable assets (between 2013 and 2014) subject to an annual prudency review and approval by the ACC. UNS Electric will recover the associated operating costs, depreciation, and property taxes under the RES program until the next rate case is filed and provides TEP withthe assets are incorporated in the Base Rates. In January 2013, the ACC approved UNS Electric’s 2013 RES implementation plan. UNS Electric’s will collect approximately $7 million from retail customers during 2013, a portion of which is expected to provide recovery of operating costs and a return on its investment until these costs can be incorporated in TEP’s base rates. In December 2010, the ACC approved a policy statement regarding the need to adopt rate decoupling or another mechanism to make Arizona’s EE Standards viable.
UNS Electric for company-owned solar projects. K-116
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) Future Implications of Discontinuing Application of Regulatory Accounting
(Continued)TEP UNS Gas and UNS Electric regularly assess whether they can continue to apply regulatory accounting to regulated operations, and concluded regulatory accounting is applicable. If TEP, UNS Gas and UNS Electric stopped applying regulatory accounting to their regulated operations the following would occur: Regulatory pension assets would be reflected in AOCI;
We would write-off remaining regulatory assets as an expense and regulatory liabilities as income on the income statement;
At December 31, 2010, based on the regulatory assets balances, net of regulatory liabilities,
| o | | TEP would have recorded an extraordinary after-tax gain of $62 million and an after-tax loss in AOCI of $54 million; |
| o | | UNS Gas would have recorded an extraordinary after-tax gain of $13 million and an after-tax loss in AOCI of $1 million; and |
| o | | UNS Electric would have recorded an extraordinary after-tax loss of $4 million and an after-tax loss in AOCI of $1 million. |
While future regulatory orders and market conditions may affect cash flows, TEP, UNS Gas and UNS Electric’s cash flows would not be affected.
Renewable Energy Purchase Power Agreements
In 2010, UniSource Energy and TEP purchased $8 million and $7 million of RECs bundled with renewable energy and expensed $5 million and $5 million to purchased power, respectively. The cost of REC purchases are qualified renewable expenditures and are offset by customer collections through the RES tariff. At December 31, 2010, TEP had $2 million in RECs recorded as Other Assets on the balance sheet.
In 2009, TEP entered into three 20-yearmultiple ACC-approved long-term purchase power agreements with companies developing renewable energy generation facilities. The ACC approved the agreements in April 2010. The facilities are expected to begin commercial operation during the next few years. Expected capacities range from 1.4 MW to 25 MW.
In 2010, TEP entered into similar long-term renewable energy contracts for approximately 96 MW of solar energy, 50 MW of wind energy and 2.2 MW of landfill gas. The ACC approved these agreements in August 2010. These facilities are also expected to begin commercial operation during the next few years.
In 2009, UNS Electric entered into a 20-year long-term purchase power agreement with a company developing a wind farm and solar generation facility near Kingman, Arizona. The ACC approved the agreement in April 2010. The facility is expected to begin commercial operation in 2011. UNS Electric is required to purchase the full output of the facility for 20 years.
TEP and UNS Electric are required to purchase the full output of each facility for 20 years. Both utilities are authorized to recover a portion of the cost of renewable energy through the PPFAC, with the balance of costs recoverable through the RES tariff. K-117
In 2010, the ACC approved new Electric EE Standards designed to require TEP and UNS Electric to implement cost-effective DSM programs, effective in 2011. In 2011, the Electric EE Standards targeted total retail kWh savings equal to 1.25% of 2010 sales, increasing to 22% by 2020, and provide for a DSM surcharge to recover the costs to implement DSM programs.In May 2012, TEP filed a modification to its proposed 2011-2012 Energy Efficiency implementation plan with the ACC. The proposal included a request for a performance incentive for 2012 ranging from approximately $3 million to $4 million and the collection of the performance incentive over a period from October 1, 2012 to December 31, 2012. An administrative law judge issued a recommended opinion and order in August 2012. TEP did not record any income related to the proposed performance incentive in 2012. A proposed settlement agreement in TEP’s pending rate case proceeding includes a new mechanism for recovery of costs incurred to implement DSM programs. The proposed settlement agreement requires the ACC’s approval before it becomes effective. UNISOURCEThe ACC approved new Gas EE Standards which required UNS Gas to implement cost effective DSM programs to reduce total retail therm sales in 2011, by 701,113 therms, or 0.5% of 2010 sales and to reduce total retail therm sales in 2012 by 1,679,890 therms, or 1.2% of 2011 sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020.In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011 which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Gas Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Gas Energy Efficiency plan or the subsequent requests. In January 2012, the ACC granted UNS Electric a waiver from complying with the 2011 and 2012 Electric EE Standards. In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter. Lost Fixed Cost Recovery Mechanism In May 2012, the ACC authorized a mechanism for UNS Gas to recover therm sales lost as a result of implementing programs under the Gas EE Standards. The LFCR mechanism enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards. UNS Gas recorded less than $0.1 million of LFCR revenue in 2012. Renewable Energy Credits UNS Electric had $2 million of RECs on December 31, 2012, and $1 million of RECs on December 31, 2011, recorded in Other Assets on the balance sheets. TEP did not have RECs balances at the end of the periods presented since all RECs have been retired for compliance with the RES standard. UNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)(Continued) Regulatory Assets and Liabilities The following tables summarize regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | December 31, 2012 | | | | | TEP | | | UNS
Gas | | | UNS
Electric | | | UNS
Energy | | | | | -Millions of Dollars- | | Regulatory Assets—Current | | | | | | | | | | | | | | | | | Property Tax Deferrals(1) | | $ | 18 | | | $ | — | | | $ | — | | | $ | 18 | | Derivative Instruments (Notes 11 and 16) | | | 2 | | | | 3 | | | | 6 | | | | 11 | | PPFAC(3) | | | 7 | | | | — | | | | 8 | | | | 15 | | DSM(3) | | | 5 | | | | — | | | | — | | | | 5 | | Other Current Regulatory Assets(4) | | | 2 | | | | 1 | | | | — | | | | 3 | | | | | | | | | | | | | | | | | | | Total Regulatory Assets—Current | | | 34 | | | | 4 | | | | 14 | | | | 52 | | | | | | | | | | | | | | | | | | | Regulatory Assets—Noncurrent | | | | | | | | | | | | | | | | | Pension and Other Retiree Benefits (Note 9) | | | 130 | | | | 4 | | | | 5 | | | | 139 | | Income Taxes Recoverable through Future Revenues(5) | | | 8 | | | | — | | | | 2 | | | | 10 | | PPFAC—Final Mine Reclamation and Retiree Health Care Costs(6) | | | 22 | | | | — | | | | — | | | | 22 | | Tucson to Nogales Transmission Line(7) | | | 5 | | | | — | | | | — | | | | 5 | | Other Regulatory Assets(4) | | | 13 | | | | 1 | | | | 1 | | | | 15 | | | | | | | | | | | | | | | | | | | Total Regulatory Assets—Noncurrent | | | 178 | | | | 5 | | | | 8 | | | | 191 | | | | | | | | | | | | | | | | | | | Regulatory Liabilities—Current | | | | | | | | | | | | | | | | | PGA(8) | | | — | | | | (17 | ) | | | — | | | | (17 | ) | RES(8) | | | (19 | ) | | | — | | | | (4 | ) | | | (23 | ) | Other Current Regulatory Liabilities | | | (2 | ) | | | (1 | ) | | | (1 | ) | | | (4 | ) | | | | | | | | | | | | | | | | | | Total Regulatory Liabilities—Current | | | (21 | ) | | | (18 | ) | | | (5 | ) | | | (44 | ) | | | | | | | | | | | | | | | | | | Regulatory Liabilities—Noncurrent | | | | | | | | | | | | | | | | | Net Cost of Removal for Interim Retirements(9) | | | (231 | ) | | | (25 | ) | | | (11 | ) | | | (267 | ) | Income Taxes Payable through Future Rates | | | (5 | ) | | | (1 | ) | | | — | | | | (6 | ) | Deferred Investment Tax Credit(10) | | | (5 | ) | | | — | | | | — | | | | (5 | ) | Other Regulatory Liabilities | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | | | | | | | | | | | | | | | | Total Regulatory Liabilities—Noncurrent | | | (241 | ) | | | (26 | ) | | | (12 | ) | | | (279 | ) | | | | | | | | | | | | | | | | | | Total Net Regulatory Assets (Liabilities) | | $ | (50 | ) | | $ | (35 | ) | | $ | 5 | | | $ | (80 | ) | | | | | | | | | | | | | | | | | |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | | | | | | | | | | | | | | | | | | | | December 31, 2011 | | | | | TEP | | | UNS
Gas | | | UNS
Electric | | | UNS
Energy | | | | | -Millions of Dollars- | | Regulatory Assets—Current | | | | | | | | | | | | | | | | | Property Tax Deferrals(1) | | $ | 16 | | | $ | — | | | $ | — | | | $ | 16 | | Derivative Instruments (Notes 11 and 16) | | | 7 | | | | 7 | | | | 10 | | | | 24 | | Deregulation Costs(2) | | | 3 | | | | — | | | | — | | | | 3 | | PPFAC(3) | | | 34 | | | | — | | | | 7 | | | | 41 | | DSM(3) | | | 8 | | | | — | | | | 1 | | | | 9 | | Other Current Regulatory Assets(4) | | | 4 | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | Total Regulatory Assets—Current | | | 72 | | | | 7 | | | | 18 | | | | 97 | | | | | | | | | | | | | | | | | | | Regulatory Assets—Noncurrent | | | | | | | | | | | | | | | | | Pension and Other Retiree Benefits (Note 9) | | | 107 | | | | 3 | | | | 4 | | | | 114 | | Income Taxes Recoverable through Future Revenues(5) | | | 10 | | | | — | | | | 2 | | | | 12 | | PPFAC(3) | | | 6 | | | | — | | | | — | | | | 6 | | PPFAC—Final Mine Reclamation and Retiree Health Care Costs(6) | | | 20 | | | | — | | | | — | | | | 20 | | Derivative Instruments (Notes 11 and 16) | | | 2 | | | | 2 | | | | 3 | | | | 7 | | Other Regulatory Assets(4) | | | 12 | | | | 1 | | | | 1 | | | | 14 | | | | | | | | | | | | | | | | | | | Total Regulatory Assets—Noncurrent | | | 157 | | | | 6 | | | | 10 | | | | 173 | | | | | | | | | | | | | | | | | | | Regulatory Liabilities—Current | | | | | | | | | | | | | | | | | PGA(8) | | | — | | | | (15 | ) | | | — | | | | (15 | ) | RES(8) | | | (22 | ) | | | — | | | | (3 | ) | | | (25 | ) | Other Current Regulatory Liabilities | | | (2 | ) | | | — | | | | — | | | | (2 | ) | | | | | | | | | | | | | | | | | | Total Regulatory Liabilities—Current | | | (24 | ) | | | (15 | ) | | | (3 | ) | | | (42 | ) | | | | | | | | | | | | | | | | | | Regulatory Liabilities—Noncurrent | | | | | | | | | | | | | | | | | Net Cost of Removal for Interim Retirements(9) | | | (198 | ) | | | (23 | ) | | | (10 | ) | | | (231 | ) | Other Regulatory Liabilities | | | (3 | ) | | | (1 | ) | | | — | | | | (4 | ) | | | | | | | | | | | | | | | | | | Total Regulatory Liabilities—Noncurrent | | | (201 | ) | | | (24 | ) | | | (10 | ) | | | (235 | ) | | | | | | | | | | | | | | | | | | Total Net Regulatory Assets (Liabilities) | | $ | 4 | | | $ | (26 | ) | | $ | 15 | | | $ | (7 | ) | | | | | | | | | | | | | | | | | |
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets and state when we earn a return below: | (1) | Property Tax is recovered over an approximate six-month period as costs are paid, rather than as costs are accrued. |
| (2) | Deregulation costs represent deferred expenses that TEP incurred to comply with various ACC deregulation orders, as authorized by the ACC. TEP earned a return on this asset and recovered these costs through Retail Rates over a four-year period ended November 2012. |
| (3) | See Cost Recovery Mechanisms discussion above. |
| (4) | TEP’s other assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), and other assets (recovery through 2014). UNS Gas’ other assets consist of rate case costs (recovery over 3 years), and costs of the low income assistance program. |
| (5) | Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. |
| (6) | Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years. |
| (7) | The Tucson to Nogales Transmission Line regulatory asset does not earn a return. TEP and UNS Electric will request recovery from FERC for the prudent cost incurred to develop a high-voltage transmission line, which we expect to abandon. See Note 4. |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Regulatory liabilities represent items that we either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers, as described below: | (8) | See Cost Recovery Mechanisms discussion above. |
| (9) | Net Cost of Removal for Interim Retirements represents an estimate of the cost of future AROs net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, general, and intangible plant which are not yet expended. TEP and UNS Electric have also collected amounts for generation plant, which they have not yet expended. |
| (10) | The Deferred Investment Tax Credit is related to federal energy credits generated in 2012 and are deferred as Regulatory Liabilities – Noncurrent and amortized over the tax life of the underlying asset. |
Income Statement Impact of Applying Regulatory Accounting Regulatory accounting had the following effects on TEP’s net income: | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | TEP | | | | | Operating Revenues | | | | | | | | | | | | | Amortization of the Fixed CTC Revenue to be Refunded | | $ | — | | | $ | 36 | | | $ | 10 | | Operating Expenses | | | | | | | | | | | | | Depreciation (related to Net Cost of Removal for Interim Retirements) | | | (33 | ) | | | (29 | ) | | | (30 | ) | (Amortization)/Deferral of PPFAC Costs | | | (31 | ) | | | 6 | | | | 22 | | Other | | | (7 | ) | | | — | | | | (8 | ) | Non-Operating Income/Expenses | | | | | | | | | | | | | Long-Term Debt (Amortization of Loss on Reacquired Debt Costs) | | | 1 | | | | 1 | | | | 1 | | AFUDC—Equity | | | 3 | | | | 4 | | | | 4 | | Income Taxes—Deferral | | | (3 | ) | | | (8 | ) | | | 1 | | Offset by the Tax Effect of the Above Adjustments | | | 26 | | | | (4 | ) | | | — | | | | | | | | | | | | | | | Net (Decrease)/Increase to Net Income | | $ | (44 | ) | | $ | 6 | | | $ | — | | | | | | | | | | | | | | |
Had UNS Gas and UNS Electric not applied regulatory accounting each would have recognized the difference between expected and actual purchased energy costs and commodity derivative unrealized gains or losses as a change in income statement expense, rather than as a change in regulatory balances. Regulatory accounting had the following effects on UNS Gas’ and UNS Electric’s net income: | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | UNS Gas | | | | | | | | | | | | | Net (Decrease)/Increase to Net Income | | $ | (6 | ) | | $ | (5 | ) | | $ | (1 | ) | UNS Electric | | | | | | | | | | | | | Net (Decrease)/Increase to Net Income | | | (7 | ) | | | 3 | | | | (7 | ) |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Future Implications of Discontinuing Application of Regulatory Accounting We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and we have concluded regulatory accounting is applicable. If we stopped applying regulatory accounting to our regulated operations, the following would occur: Regulatory pension assets would be reflected in AOCI; We would write off remaining regulatory assets as an expense and regulatory liabilities as income in the income statements; At December 31, 2012, based on the regulatory assets balances, net of regulatory liabilities: TEP would have recorded an extraordinary after-tax gain of $48 million and an after-tax loss in AOCI of $78 million; UNS Gas would have recorded an extraordinary after-tax loss of $19 million and an after-tax loss in AOCI of $3 million; and UNS Electric would have recorded an extraordinary after-tax gain of $6 million and an after-tax loss in AOCI of $3 million. While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped applying regulatory accounting to our regulated operations.
NOTE 3. SEGMENT AND RELATED INFORMATION We have fourthree reportable segments that are determined based on the way we organize our operations and evaluate performance: | | (1) | | TEP, a vertically integratedregulated electric utility business, is our largest subsidiary; |
| | (2) | | UNS Gas is a regulated gas distribution utility business; and |
| | (3) | | UNS Electric is a regulated electric distribution utility business; andbusiness. |
| (4) | | Millennium has investments in unregulated businesses. |
The UniSourceResults for the UNS Energy and UES holding companies, Millennium, and UED are included in Other. Other below.We disclose selected financial data for our reportable segments in the following tables: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reportable Segments | | | | | | | | | | | | | | TEP | | | UNS
Gas | | | UNS
Electric | | | Other | | | Reconciling
Adjustments | | | UNS
Energy | | | | | -Millions of Dollars- | | 2012 | | | | | Income Statement | | | | | Operating Revenues-External | | $ | 1,145 | | | $ | 129 | | | $ | 189 | | | $ | — | | | $ | (1 | ) | | $ | 1,462 | | Operating Revenues- Intersegment | | | 17 | | | | 4 | | | | 1 | | | | 18 | | | | (40 | ) | | | — | | Depreciation and Amortization | | | 150 | | | | 9 | | | | 18 | | | | — | | | | — | | | | 177 | | Interest Income | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | Interest Expense | | | 88 | | | | 6 | | | | 8 | | | | 3 | | | | — | | | | 105 | | Income Tax Expense | | | 39 | | | | 6 | | | | 11 | | | | — | | | | — | | | | 56 | | Net Income | | | 65 | | | | 9 | | | | 17 | | | | — | | | | — | | | | 91 | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (253 | ) | | | (16 | ) | | | (38 | ) | | | — | | | | — | | | | (307 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | | 3,461 | | | | 310 | | | | 370 | | | | 1,121 | | | | (1,122 | ) | | | 4,140 | | | | | | | | | | | | | | | | | | | | | | | | | | |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reportable Segments | | | | | | | | | | | | | | TEP | | | UNS
Gas | | | UNS
Electric | | | Other | | | Reconciling
Adjustments | | | UNS
Energy | | | | | -Millions of Dollars- | | 2011 | | | | | Income Statement | | | | | Operating Revenues-External(1) | | $ | 1,141 | | | $ | 149 | | | $ | 188 | | | $ | — | | | $ | 1 | | | $ | 1,479 | | Operating Revenues-Intersegment | | | 15 | | | | 2 | | | | 2 | | | | 23 | | | | (42 | ) | | | — | | Depreciation and Amortization | | | 140 | | | | 8 | | | | 17 | | | | 1 | | | | (1 | ) | | | 165 | | Interest Income | | | 4 | | | | — | | | | — | | | | 1 | | | | — | | | | 5 | | Interest Expense | | | 89 | | | | 7 | | | | 7 | | | | 9 | | | | — | | | | 112 | | Income Tax Expense (Benefit) | | | 52 | | | | 7 | | | | 11 | | | | (1 | ) | | | (2 | ) | | | 67 | | Net Income | | | 85 | | | | 10 | | | | 18 | | | | — | | | | (3 | ) | | | 110 | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (352 | ) | | | (13 | ) | | | (96 | ) | | | (34 | ) | | | 121 | | | | (374 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | | 3,278 | | | | 320 | | | | 370 | | | | 1,172 | | | | (1,151 | ) | | | 3,989 | | | | | | | | | | | | | | | | | | | | | | | | | | | 2010 | | | | | | | | | | | | | | | | | | | | | | | | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenue-External(1) | | $ | 1,096 | | | $ | 144 | | | $ | 185 | | | $ | — | | | $ | 1 | | | $ | 1,426 | | Operating Revenue-Intersegment | | | 29 | | | | 6 | | | | 2 | | | | 28 | | | | (65 | ) | | | — | | Depreciation and Amortization | | | 132 | | | | 8 | | | | 16 | | | | 2 | | | | (2 | ) | | | 156 | | Interest Income | | | 7 | | | | — | | | | — | | | | 1 | | | | — | | | | 8 | | Interest Expense | | | 88 | | | | 7 | | | | 7 | | | | 9 | | | | — | | | | 111 | | Net Loss from Equity Method Investments | | | — | | | | — | | | | — | | | | (6 | ) | | | — | | | | (6 | ) | Income Tax Expense | | | 60 | | | | 6 | | | | 10 | | | | 4 | | | | (3 | ) | | | 77 | | Net Income (Loss) | | | 108 | | | | 9 | | | | 15 | | | | (14 | ) | | | (5 | ) | | | 113 | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (277 | ) | | | (12 | ) | | | (24 | ) | | | (18 | ) | | | — | | | | (331 | ) | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | The amounts previously reported have been revised. |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Reconciling adjustments consist of the elimination of intersegment revenue resulting from the following transactions, and theywhich are eliminated in consolidation: | | | | | | | | | | | | | | | | | | | | | | | | | Reportable Segments | | | | | | | | | UNS | | | | | | | | | | | | Intersegment Revenue | | TEP | | | Gas | | | UNS Electric | | | Millennium | | | Other | | | | | -Millions of Dollars- | | 2010: | | | | | | | | | | | | | | | | | | | | | Wholesale Sales — TEP to UNS Electric(4) | | $ | 18 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales — UNS Electric to TEP(4) | | | — | | | | — | | | | 2 | | | | — | | | | — | | | Wholesale Sales — UED to UNS Electric | | | — | | | | — | | | | — | | | | — | | | | 11 | | Wholesale Sales — UNS Gas to TEP(5) | | | — | | | | 1 | | | | — | | | | — | | | | — | | | Gas Revenue — UNS Gas to UNS Electric | | | — | | | | 5 | | | | — | | | | — | | | | — | | Other Revenue — TEP to Affiliates(1) | | | 8 | | | | — | | | | — | | | | — | | | | — | | Other Revenue — Millennium to TEP, UNS Electric, & UNS Gas(2) | | | — | | | | — | | | | — | | | | 17 | | | | — | | Other Revenue — TEP to UNS Electric(3) | | | 3 | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 29 | | | $ | 6 | | | $ | 2 | | | $ | 17 | | | $ | 11 | | | | | | | | | | | | | | | | | | | 2009: | | | | | | | | | | | | | | | | | | | | | Wholesale Sales — TEP to UNS Electric(4) | | $ | 23 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales — UNS Electric to TEP(4) | | | — | | | | — | | | | 4 | | | | — | | | | — | | | Wholesale Sales — UED to UNS Electric | | | — | | | | — | | | | — | | | | — | | | | 12 | | | Gas Revenue — UNS Gas to UNS Electric | | | — | | | | 5 | | | | — | | | | — | | | | — | | Other Revenue — TEP to Affiliates(1) | | | 8 | | | | — | | | | — | | | | — | | | | — | | Other Revenue — Millennium to TEP, UNS Electric, & UNS Gas(2) | | | — | | | | — | | | | — | | | | 16 | | | | — | | Other Revenue — TEP to UNS Electric(3) | | | 3 | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 34 | | | $ | 5 | | | $ | 4 | | | $ | 16 | | | $ | 12 | | | | | | | | | | | | | | | | | | | 2008: | | | | | | | | | | | | | | | | | | | | | Wholesale Sales — TEP to UNS Electric(4) | | $ | 24 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales — UNS Electric to TEP(4) | | | — | | | | — | | | | 9 | | | | — | | | | — | | | Wholesale Sales — UED to UNS Electric | | | — | | | | — | | | | — | | | | — | | | | 7 | | | Gas Revenue — UNS Gas to UNS Electric | | | — | | | | 8 | | | | — | | | | — | | | | — | | Other Revenue — TEP to Affiliates(1) | | | 8 | | | | — | | | | — | | | | — | | | | — | | Other Revenue — Millennium to TEP, UNS Electric & UNS Gas(2) | | | — | | | | — | | | | — | | | | 16 | | | | — | | Other Revenue — TEP to UNS Electric(3) | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 34 | | | $ | 8 | | | $ | 9 | | | $ | 16 | | | $ | 7 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Reportable Segments | | | | | TEP | | | UNS
Gas | | | UNS
Electric | | | Other | | Intersegment Revenue | | -Millions of Dollars- | | 2012: | | | | | | | | | | | | | Wholesale Sales—TEP to UNS Electric(1) | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales—UNS Electric to TEP(1) | | | — | | | | — | | | | 1 | | | | — | | Wholesale Sales—UNS Gas to TEP(2) | | | — | | | | 1 | | | | — | | | | — | | Gas Revenue—UNS Gas to UNS Electric | | | — | | | | 3 | | | | — | | | | — | | Other Revenue—TEP to Affiliates(3) | | | 12 | | | | — | | | | — | | | | — | | Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas(4) | | | — | | | | — | | | | — | | | | 18 | | Other Revenue—TEP to UNS Electric(5) | | | 3 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 17 | | | $ | 4 | | | $ | 1 | | | $ | 18 | | | | | | | | | | | | | | | | | | | 2011: | | | | | | | | | | | | | | | | | Wholesale Sales—TEP to UNS Electric(1) | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales—UNS Electric to TEP(1) | | | — | | | | — | | | | 2 | | | | — | | Wholesale Sales—UED to UNS Electric | | | — | | | | — | | | | — | | | | 5 | | Gas Revenue—UNS Gas to UNS Electric | | | — | | | | 2 | | | | — | | | | — | | Other Revenue—TEP to Affiliates(3) | | | 10 | | | | — | | | | — | | | | — | | Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas(4) | | | — | | | | — | | | | — | | | | 18 | | Other Revenue—TEP to UNS Electric(5) | | | 3 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 15 | | | $ | 2 | | | $ | 2 | | | $ | 23 | | | | | | | | | | | | | | | | | | | 2010: | | | | | | | | | | | | | | | | | Wholesale Sales—TEP to UNS Electric(1) | | $ | 18 | | | $ | — | | | $ | — | | | $ | — | | Wholesale Sales—UNS Electric to TEP(1) | | | — | | | | — | | | | 2 | | | | — | | Wholesale Sales—UED to UNS Electric | | | — | | | | — | | | | — | | | | 11 | | Wholesale Sales—UNS Gas to TEP(2) | | | — | | | | 1 | | | | — | | | | — | | Gas Revenue—UNS Gas to UNS Electric | | | — | | | | 5 | | | | — | | | | — | | Other Revenue—TEP to Affiliates(3) | | | 8 | | | | — | | | | — | | | | — | | Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas(4) | | | — | | | | — | | | | — | | | | 17 | | Other Revenue—TEP to UNS Electric(5) | | | 3 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Total Intersegment Revenue | | $ | 29 | | | $ | 6 | | | $ | 2 | | | $ | 28 | | | | | | | | | | | | | | | | | | |
| | | | (1) | TEP and UNS Electric sell power to each other at third-party market prices. |
| (2) | UNS Gas provides gas to TEP for generation of power at third-party market prices. |
| (3) | Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable. |
| (2)(4) | | Millennium provides a supplemental workforce and meter readingmeter-reading services to TEP, UNS Gas, and UNS Electric. Amounts are based on costs of services performed and management believes that the charges for services are reasonable. Millennium charged TEP $17 million in 2012 and 2011, and $16 million in 2010 $15 million in 2009 and $15 million in 2008 for these services. |
K-118
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
| (5) | | | (3) | | TEP charged UNS Electric for control area services based on a FERC approvedFERC-approved tariff. | | (4) | | TEP and UNS Electric began selling power to each other in 2008 at prices based on the Dow Jones Four Corners Daily Index. | | (5) | | Starting in 2010, UNS Gas provided gas to TEP for generation of power based on third-party market quotes. |
TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UniSourceUNS Energy UNS Gas and UNS Electric as well as to UniSource Energy’s non-utility businesses.affiliated entities. Costs are directly assigned to the benefiting entity. Direct costs charged by TEP to affiliates were $10 million in 2010, 20092012, 2011, and 2008. UniSource2010.UNS Energy incurs corporate costs that are allocated to TEP and its other subsidiaries. Corporate costs are allocated based on a weighted-average of three factors: assets, payroll, and revenues. Management believes this method of allocation is reasonable and approximates the cost that TEP would have incurred as a standalone entity. Charges allocated to TEP were $2 million in 2012 and 2011, and $3 million in 2010, $2 million in 2009, and $4 million in 2008. 2010.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Other Other significant reconciling adjustments include intercompany interest between UniSource Energy and UED, the elimination of investments in subsidiaries held by UniSourceUNS Energy and reclassifications of deferred tax assets and liabilities. K-119
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
We disclose selected financial data for our reportable segments in the following tables:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reportable Segments | | | | | | | | | | | | | | | | | | | UNS | | | UNS | | | | | | | | | | | Reconciling | | | UniSource | | | | | TEP | | | Gas | | | Electric | | | Millennium | | | Other | | | Adjustments | | | Energy | | | | | -Millions of Dollars- | | 2010 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues — External | | $ | 1,096 | | | $ | 144 | | | $ | 214 | | | $ | 1 | | | $ | — | | | $ | (1 | ) | | $ | 1,454 | | | Operating Revenues — Intersegment | | | 29 | | | | 6 | | | | 2 | | | | 17 | | | | 11 | | | | (65 | ) | | | — | | | Depreciation and Amortization | | | 132 | | | | 8 | | | | 15 | | | | — | | | | 1 | | | | — | | | | 156 | | | Interest Income | | | 7 | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 8 | | | Net Loss from Equity Method Investments | | | — | | | | — | | | | — | | | | (6 | ) | | | — | | | | — | | | | (6 | ) | | Interest Expense | | | 88 | | | | 7 | | | | 7 | | | | — | | | | 9 | | | | — | | | | 111 | | | Income Tax Expense (Benefit) | | | 61 | | | | 6 | | | | 7 | | | | 6 | | | | (2 | ) | | | — | | | | 78 | | | Net Income (Loss) | | | 107 | | | | 9 | | | | 10 | | | | (13 | ) | | | (2 | ) | | | — | | | | 111 | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (216 | ) | | | (10 | ) | | | (22 | ) | | | — | | | | (17 | ) | | | — | | | | (265 | ) | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | | 3,066 | | | | 310 | | | | 291 | | | | 46 | | | | 1,096 | | | | (1,030 | ) | | | 3,779 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2009 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues — External | | $ | 1,065 | | | $ | 148 | | | $ | 183 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1,397 | | | Operating Revenues — Intersegment | | | 34 | | | | 5 | | | | 4 | | | | 16 | | | | 12 | | | | (71 | ) | | | — | | | Depreciation and Amortization | | | 153 | | | | 7 | | | | 14 | | | | — | | | | 2 | | | | — | | | | 176 | | | Interest Income | | | 11 | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | 12 | | | Net Gain from Equity Method Investments | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | — | | | | 5 | | | Interest Expense | | | 85 | | | | 6 | | | | 7 | | | | — | | | | 11 | | | | — | | | | 109 | | | Income Tax Expense (Benefit) | | | 55 | | | | 5 | | | | 4 | | | | 2 | | | | (1 | ) | | | (1 | ) | | | 64 | | | Net Income (Loss) | | | 89 | | | | 7 | | | | 6 | | | | 2 | | | | — | | | | — | | | | 104 | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (232 | ) | | | (13 | ) | | | (28 | ) | | | — | | | | (10 | ) | | | — | | | | (283 | ) | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | | 2,914 | | | | 307 | | | | 273 | | | | 62 | | | | 1,045 | | | | (1,000 | ) | | | 3,601 | | | Equity Method Investments | | | — | | | | — | | | | — | | | | 7 | | | | — | | | | — | | | | 7 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenues — External | | $ | 1,058 | | | $ | 166 | | | $ | 186 | | | $ | 1 | | | $ | — | | | $ | (1 | ) | | $ | 1,410 | | | Operating Revenues — Intersegment | | | 34 | | | | 8 | | | | 9 | | | | 16 | | | | 7 | | | | (74 | ) | | | — | | | Depreciation and Amortization | | | 126 | | | | 7 | | | | 14 | | | | — | | | | 1 | | | | — | | | | 148 | | | Amortization of Transition Recovery Asset | | | 24 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 24 | | | Interest Income | | | 10 | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 11 | | | Net Loss from Equity Method Investments | | | — | | | | — | | | | — | | | | (2 | ) | | | — | | | | — | | | | (2 | ) | | Interest Expense | | | 97 | | | | 7 | | | | 7 | | | | — | | | | 10 | | | | (2 | ) | | | 119 | | | Income Tax Expense (Benefit) | | | 11 | | | | 6 | | | | 2 | | | | — | | | | (2 | ) | | | — | | | | 17 | | | Net Income (Loss) | | | 4 | | | | 9 | | | | 4 | | | | — | | | | 16 | | | | (19 | ) | | | 14 | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital Expenditures | | | (292 | ) | | | (16 | ) | | | (30 | ) | | | — | | | | (16 | ) | | | — | | | | (354 | ) | | | | | | | | | | | | | | | | | | | | | | | | Balance Sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets | | | 2,842 | | | | 294 | | | | 285 | | | | 62 | | | | 999 | | | | (972 | ) | | | 3,510 | | | Equity Method Investments | | | — | | | | — | | | | — | | | | 25 | | | | — | | | | — | | | | 25 | |
K-120
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
NOTE 4. COMMITMENTS, CONTINGENCIES, AND CONTINGENCIESENVIRONMENTAL MATTERS Firm Purchase Commitments At December 31, 2010,2012, TEP had variousthe following firm non-cancelable purchase commitments (minimum purchase obligations) and operating leases as described in the table below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | | Fuel (including Transportation) | | $ | 52 | | | $ | 42 | | | $ | 36 | | | $ | 35 | | | $ | 35 | | | $ | 104 | | | $ | 304 | | | Purchased Power | | | 26 | | | | 15 | | | | 8 | | | | 4 | | | | — | | | | — | | | | 53 | | | Transmission | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 10 | | | | 20 | | | | | | | | | | | | | | | | | | | | | | | | | | Total Unrecognized Firm Commitments | | $ | 80 | | | $ | 59 | | | $ | 46 | | | $ | 41 | | | $ | 37 | | | $ | 114 | | | $ | 377 | | | | | | | | | | | | | | | | | | | | | | | | |
leases: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | Fuel (Including Transportation) | | $ | 65 | | | $ | 65 | | | $ | 50 | | | $ | 47 | | | $ | 39 | | | $ | 60 | | | $ | 326 | | Purchased Power | | | 50 | | | | 41 | | | | 29 | | | | 28 | | | | 28 | | | | 386 | | | | 562 | | RES Performance-Based Incentive Payments | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 4 | | | | 42 | | | | 62 | | Solar Equipment | | | 12 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 12 | | Transmission | | | 3 | | | | 3 | | | | 3 | | | | 3 | | | | 3 | | | | 22 | | | | 37 | | Operating Leases | | | 2 | | | | 2 | | | | 2 | | | | 1 | | | | 1 | | | | 10 | | | | 18 | | Service Agreement | | | 2 | | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Unrecognized Firm Commitments | | $ | 138 | | | $ | 117 | | | $ | 88 | | | $ | 83 | | | $ | 75 | | | $ | 520 | | | $ | 1,021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel, and Purchased Power, and Transmission Contracts TEP has long-term contracts for the purchase and delivery of coal and natural gas with various expiration dates from 2012 through 2020. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more to meet its fuel requirements than the minimum purchase obligations outlined above. to meet its fuel requirements.TEP has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in various years between 20112013 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2010. Starting January 1, 2009, fuel,2012.Additionally, Purchased Power includes six 20-year Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011 and 2012. TEP is obligated to purchase 100% of the output from these facilities. TEP has additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Fuel, purchased power, and transmission costs are recoverable from customers through athe PPFAC. Renewable Energy Purchase Power Agreements and Projects
TEP entered into various forward power purchase agreements with developing A portion of the cost of renewable energy generation facilities to meet compliance requirements underis recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. The facilities are expected to begin commercial operation in the next few years. Additionally, See Note 2.RES Performance-Based Incentives TEP has entered into contractsREC purchase agreements to develop TEP ownedpurchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy projects for $14 million of which $1 million remained an outstanding commitment at December 31, 2010.production. PBIs are recoverable through the RES tariff. See Note 2 for additional information on RES related contracts. Take-Or-Pay Accrual for Coal Transportation Agreement
2.Solar Equipment TEP is obligated under a coal transportation agreementcommitted to transport 75,000 tonspurchase 9 MW of coal to Tucson from specified sources or pay approximately $1 million per yearphotovoltaic equipment through December 2015. In 2010,2013. TEP satisfied the contract terms for the period. However, due to a mine closure and the inability to obtain suitable coal from alternative transportation points during the remaining term of the transportation agreement, TEP recognized a liability of $4spent $11 million in December 2010 for the minimum take-or-pay obligation to be paid2012 and $10 million in the future.2011 under this contract. The ACC approved this purchase under TEP’s RES implementation plan. TEP expects to recover the take-or-pay charges through the PPFAC as annual payments are made. Therefore, TEP recorded the $4 million asearns a regulatory asset.return on investment in company-owned solar projects. See Note 2. K-121
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Operating Leases TEP’s aggregate existing operating lease expense is primarily for rail cars, office facilities, and computer equipment, with varying terms, provisions, and expiration dates. This expense totaled $1$2 million in each of 2010, 20092012, 2011, and 2008. TEP’s estimated future minimum payments under existing non-cancelable operating leases are less than $12010. Service Agreement In February 2012, TEP entered into a long-term agreement for information technology services. TEP is obligated to pay $2 million per year for 2011 and thereafter. through December 2014.UNS GAS andAND UNS ELECTRIC COMMITMENTS At December 31, 2010,2012, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in the table below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | | Total Unrecognized Firm Commitments — Fuel | | $25 | | | $10 | | | $5 | | | $4 | | | $3 | | | $19 | | | $66 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | Total Unrecognized Firm Commitments – Fuel | | $ | 26 | | | $ | 13 | | | $ | 8 | | | $ | 6 | | | $ | 4 | | | $ | 17 | | | $ | 74 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
UNS Gas purchases gas from various suppliers at market prices. However, UNS Gas’ risk of loss due to increased costs (as a result of changes in market prices of fuel) is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas’ forward gas purchase agreements expire through 2015. Certain of these contracts are at a fixed price per mmbtuMillion British Thermal Units (MMBtu) and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2010.2012. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 20112013 and 2024. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) At December 31, 2010,2012, UNS Electric had various firm non-cancelable purchase commitments as described in the table below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | | Purchased Power | | $ | 47 | | | $ | 33 | | | $ | 35 | | | $ | — | | | $ | — | | | $ | — | | | $ | 115 | | | Transmission | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | — | | | | 10 | | | | | | | | | | | | | | | | | | | | | | | | | | Total Unrecognized Firm Commitments | | $ | 49 | | | $ | 35 | | | $ | 37 | | | $ | 2 | | | $ | 2 | | | $ | — | | | $ | 125 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Commitments | | | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | Thereafter | | | Total | | | | | -Millions of Dollars- | | Purchased Power | | $ | 55 | | | $ | 50 | | | $ | 14 | | | $ | 6 | | | $ | 5 | | | $ | 80 | | | $ | 210 | | Transmission | | | 4 | | | | 2 | | | | 2 | | | | 1 | | | | — | | | | — | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Unrecognized Firm Commitments | | $ | 59 | | | $ | 52 | | | $ | 16 | | | $ | 7 | | | $ | 5 | | | $ | 80 | | | $ | 219 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
UNS Electric enters into agreements with various energy suppliers for purchased power at market prices to meet its energy requirements. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts.taken. These contracts expire in various years through 2013.2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on market prices as of December 31, 2010. UNS Electric2012. Purchased power commitments also entered into a forward power purchase agreementinclude two 20-year PPAs with the developer of renewable energy generation facilities to meet compliance requirements under the RES program. The facilities are expected to beginthat achieved commercial operation in 2011. See Note 2 for additional information on RES related contracts. 2011 and 2012. UNS Electric is obligated to purchase 100% of the output from these facilities.UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. UNS Electric’s transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 20112013 and 2017.2016. However, the effects of both purchased power and transmission cost adjustments are mitigated through a purchased power rate-adjustment mechanism. Additionally, UNS Gas’Electric’s PPFAC.UNS Gas and UNS Electric’s combinedElectric have operating lease expenseleases, primarily for office facilities and computer equipment, with varying terms and expiration datesdates. The expense was less than $1 million in each of the years 2010, 2009,2012, 2011, and 2008.2010. UNS Gas’ and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are approximatelyless than $1 million per year for 2011 and $22013 through 2031. RES Performance-Based Incentives UNS Electric is contractually obligated to make RES PBI payments to retail customers with solar installations. UNS Electric’s total obligation for RES PBIs is about $6 million thereafter. with payments required over periods ranging from 10 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2. K-122
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
UNISOURCE ENERGY COMMITMENTS
In 2009, UniSource Energy purchased land to construct a new headquarters building in downtown Tucson. In April 2010, UniSource Energy signed a design-build contract committing to a payment of $54 millionDecember 2012, UNS Electric entered into an agreement for the construction of a 7.182 MW solar photovoltaic power plant that will be constructed in two phases. The first and second phasesphase will result in a 4.2 MW plant that UNS Electric expects to be operational in June of 2013. The balance of the construction project; $32 million of that commitment remained outstanding at December 31, 2010. UniSource Energy expects the building toproject will be completed in November 2011. ENVIRONMENTAL REGULATION
TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO2), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $182014. UNS Electric invested $5 million in 2010, $24this project in 2012. The contract requires additional investments of $4 million in 2009each of 2013 and $73 million in 2008 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan2014. This is an approved project under UNS Electric’s RES implementation plan. See Note 2.TEP CONTINGENCIES Springerville Generating Station (San Juan) described below. TEP expects to capitalize environmental compliance costs of $38 million in 2011 and $87 million in 2012. Unit 3 Outage In addition, TEP recorded operating expenses of $14 million in 2010, $13 million in 2009 and $14 million in 2008 related to environmental compliance. TEP expects environmental expenses to be $10 million in 2011. July 2012, Springerville Unit 3 experienced an unplanned outage. As a result of the outage, TEP recorded a 2005 settlement agreement among PNM, environmental activist groups, andpre-tax loss of $2 million in the New Mexico Environment Department (PNM Consent Decree), the co-ownersthird quarter of San Juan installed new pollution control equipment at the generating station to reduce mercury, particulate matter, NOx, and SO2emissions. The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan. In 2008, TEP’s share of stipulated penalties at San Juan was $1 million. TEP cannot deduct these penalties for income tax purposes.2012 as TEP did not incur any stipulated penalties at San Juan in 2009 or 2010. The installation of new pollution control equipment designed to remedy all emission violations was completed in 2008 for San Juan Unit 1 and in 2009 for San Juan Unit 2. TEP has sufficient emission allowances to comply with the Acid Rain SO2 regulations.
TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations and permitmeet certain availability requirements at existing electric generating facilities. Compliance with these changes may reduce operating efficiency.
TEP CONTINGENCIES
El Paso Electric Transmission
In 2006, El Paso filed a complaint with the FERC claiming that TEP must request service under El Paso’s Open Access Transmission Tariff (OATT) in order to transmit power from Luna to TEP’s system. TEP filed a counter complaint stating that TEP has existing rights under a 1982 Tucson-El Paso Transmission Agreement and, therefore, is not required to pay for transmission service under El Paso’s OATT. In November 2008, the FERC issued an order supporting TEP’s position.
In December 2008, pending resolution, El Paso refunded to TEP $10 million paid for transmission service from Luna to TEP’s system during the period 2006 to 2008 plus interest of $1 million. TEP is not currently paying or accruing for transmission service under El Paso’s OATT.
In July 2010, the FERC issued an order denying El Paso’s request for rehearing of FERC’s November 2008 order. Also in July 2010, El Paso filed an appeal in the United States Court of Appeals for the District of Columbia Circuit. TEP intervened in the appeal proceeding. TEP has not recognized income as a result of the July 2010 FERC decision. In January 2011, in response to a joint motion filed by El Paso and the FERC, the Court ordered the appeal proceeding to be held in abeyance to allow TEP and El Paso time to continue settlement negotiations in this matter.
K-123
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
If El Paso were to prevail in its appeal, TEP would be required to pay for transmission service under El Paso’s OATT from October 2008 through the date of the decision. For the period October 2008 to December 31, 2010, this additional transmission expense would approximate $10 million. However, under the PPFAC mechanism, TEP would be allowed to recover $8 millionterms of this additional transmission expense from its retail customers.
In December 2008, TEP filed a complaint in the United States Federal District Court against El Paso seeking a $2 million reimbursement from El Paso for transmission charges paid by TEP to Public Service Company of New Mexico (PNM) for transmission service in an attempt to mitigate TEP’s damages before FERC issued its decision in November 2008. In September 2009, the District Court denied El Paso’s motion to dismiss TEP’s complaint and stayed the proceeding pending a final resolution of the FERC proceedings and any appeal.
TEP cannot predict the timing or outcome of these matters.
Claims Related to Navajo Generating Station
In June 1999, the Navajo Nation filed suit against SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to Navajo Generating Station (Navajo); Southern California Edison Company; and other defendants in the U.S. District Court for the District of Columbia (D.C. Lawsuit). Although TEP is not a named defendant in the D.C. Lawsuit, TEP owns 7.5% of Navajo Units 1, 2 and 3. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate on the lease agreements under which Peabody mines coal by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease.
In July 2001, the District Court dismissed all claims against SRP. In March 2008, the District Court lifted a stay that had been in place since October 2004 and referred pending discovery related motions to a magistrate judge. In January 2010, the District Court extended the discovery deadline and set other procedural deadlines at various dates between March 2010 and February 2011. In April 2010, the Navajo Nation filed a Second Amended Complaint. In September 2010, the case was referred to the District Court’s mediation program to assistoperating agreement with settlement negotiations.
In 2004, Peabody filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs arising out of the D.C. Lawsuit. In July 2008, the parties entered into a joint stipulation of dismissal of these claims which was approved by the Circuit Court. TEP cannot predict whether the lawsuit will be refiled based upon the final outcome of the D.C. Lawsuit.
Tri-State.Claims Related to San Juan Generating Station In April 2010, the Sierra Club filed a citizens suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the U.S. District Court for the District of New Mexico against PNM, as operator of San Juan; PNM’s parent PNM Resources, Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent BHP Minerals International Inc. (BHP). The Sierra Club alleges in the suit that certain activities at San Juan and the San Juan mine associated with the treatment, storage and disposal of coal and coal combustion residuals (CCRs), primarily coal ash, are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCRs at the mine constitute “open dumping” in violation of RCRA. The RCRA claims are asserted against PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP. The suit seeks the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCRs at the mine or to cease placement of CCRs at the mine; the imposition of civil penalties; and, attorney’s fees and costs. With the agreement of the parties, the court entered a stay of the action in August 2010 to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM has indicated that it plans an aggressive defense of the RCRA claims in the suit. TEP cannot predict the outcome of this matter at this time. K-124
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
SJCC, 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 coal mine that supplies coal to San Juan. Certainin an area where 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.parties. These gas producers allege that SJCC’s underground coal mining operations have or will interferemine interferes with their gas production and will reduceoperations, reducing the amount of natural gas that they would otherwise be entitled tocan recover. SJCC has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity waswells deemed close enough to the mine to warrant plugging and abandoning the well.them. These settlements, however, do not resolve all potential claims by gas producers in the underground mine area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Claims Related to Four Corners Generating Station In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants, alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued, and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed Motions to Dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties filed a Joint Motion to Stay in November 2012 in furtherance of settlement talks. TEP owns 50%7% of San JuanFour Corners Units 14 and 2, which represents approximately 20% of the total generation capacity of the entire San Juan Generation Station,5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim.Mine Closure Reclamation at Generating Stations Not Operated by TEP TEP currently pays ongoing reclamation costs related to the coal mines that supply the generating stations in which TEP has an ownership interest but does not operate. ItTEP is probable that TEP will have to payliable for a portion of final reclamation costs upon closure of these mines.the mines servicing Navajo Generating Station (Navajo), San Juan, and Four Corners. TEP’s share of the reclamation costs at theis expected to be $27 million upon expiration dates of the coal supply agreements, inwhich expire between 2016 through 2019 is approximately $26 million. TEP recognizes thisand 2019. The reclamation liability over the remaining terms(present value of the coal supply agreements and had recorded liabilities of $11future liability) was $16 million at December 31, 20102012, and $10$13 million at December 31, 2009. 2011.Amounts recorded for final reclamation are subject to various assumptions, such as estimatingestimations of reclamation costs, the costs of reclamation,dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreement term.terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition occurswill occur over the remaining terms of its coal supply agreements. TEP’s PPFAC allows TEPus to pass-throughpass through most fuel costs including(including final reclamation costs,costs) to customers. Therefore, TEP classifies these costs as a regulatory asset. TEP will increaseasset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and will recoverrecovering the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers. K-125
Tucson to Nogales Transmission LineTEP and UNS Electric are parties to a project development agreement for the joint construction of a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP had previously capitalized $11 million related to the project, including $2 million to secure land and land rights. UNS Electric had previously capitalized $0.4 million related to the project. UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) California Energy Market Issues
In December 2009,(Continued)TEP and UNS Electric expect to abandon the project based on renewedthe cost of the proposed 345-kV line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting the elimination of this project. In TEP’s pending rate case proceeding before the ACC, TEP entered into a proposed settlement discussions with parties involvedagreement in various legal proceedings relatedwhich it agrees to seek recovery of the California energy crisis,project costs from FERC before seeking rate recovery from the ACC. In the fourth quarter of 2012, TEP and UNS Electric wrote off its remaining accounts receivablea portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of $2recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and accrued an additional liability$0.2 million, respectively, of $2 million. In March 2010, TEP and the California Attorney General, California Public Utilities Commission and various private entities (collectively California Parties) reached a settlement in principal of all remaining claims against TEP related to TEP’s transactions in the Western energy markets including the California Power Exchange and the California Independent System Operator during the California energy crisis of 2000 and 2001. As a result of this settlement, TEP recognized an additional liability of $4 million in March 2010, bringing TEP’s gross liability related to these claims to $6 million.
costs incurred through 2012.RESOLUTION OF CONTINGENCIES In April 2010, TEPthe Sierra Club filed a citizens’ suit under the Resource Conservation and Recovery Act (RCRA) and the California Parties entered into a written settlement agreement that FERC approvedSurface Mine Control and Reclamation Act (SMCRA) in June 2010 TEP paid the resulting liability in July 2010. Also, in association withUnited States District Court for the California Parties settlement, TEP recorded a receivable from SRP in March 2010 for approximately $1 million, that has since been settled, related to a long-term power sale agreement between TEP and SRP. The net $3 million is shown as California Power Exchange (CPX) Provision for Wholesale Refunds on TEP’s income statement. In addition, in March 2010, UNS Electric reached a related settlement with ArizonaDistrict of New Mexico against Public Service Company (APS)of New Mexico (PNM), as operator of San Juan, SJCC, and PNM’s and SJCC’s respective parent companies. The suit alleged that certain activities at San Juan and the San Juan mine associated with the treatment, storage, and disposal of coal and Coal Combustion Residuals (CCRs) violated RCRA and SMCRA. The suit sought an injunction with respect to the placement of CCRs at the mine, the imposition of civil penalties, and attorney’s fees and costs. In March 2012, the parties settled the case. The settlement was approved by the court. TEP is responsible for its share of the settlement of the San Juan claims. TEP recorded Other Incomeless than $1 million for its share of $3the costs to fund environmental projects and Sierra Club attorney and expert fees required by the settlement, substantially all of which was recorded in 2011. In addition, TEP paid $1 million for its share of construction costs for a new groundwater recovery system adjacent to San Juan and other environmental projects required by the settlement. San Juan Mine Fire In September 2011, a fire at the underground mine that has since been receivedprovides coal to San Juan caused mining operations to shut down. The mine resumed production in cash.June 2012. The settlements described above offset and had no net impactmine fire did not have a material effect on UniSource Energy’s consolidatedTEP’s financial condition, results of operations, or cash flows due to the use of on-hand inventory of previously mined coal and the low market price of wholesale power during the closure. TEP awaits final resolution in 2010. the matter pending an insurance settlement between the mine operator and its insurance company.ENVIRONMENTAL MATTERS Environmental Regulation The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $2 million in 2012, $8 million in 2011, and $18 million in 2010 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control equipment installed at San Juan. TEP expects to capitalize environmental compliance costs of $10 million in 2013 and $27 million in 2014. In addition, TEP recorded O&M expenses of $15 million in 2012, $12 million in 2011, and $14 million in 2010 related to environmental compliance. TEP expects environmental O&M expenses to be $16 million in 2013. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Hazardous Air Pollutant Requirements The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules called the Mercury and Air Toxics Standards setting limits for mercury emissions and other hazardous air pollutants from power plants. Navajo Based on the EPA’s final standards, Navajo may need mercury and particulate matter emission control equipment by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which include the regional haze final Best Available Retrofit Technology (BART) rules. San Juan TEP expects San Juan’s current emission controls to be adequate to comply with the EPA’s final standards. Four Corners Based on the EPA’s final standards, Four Corners may need mercury emission control equipment by 2015. The estimated capital cost of this equipment is less than $1 million. TEP expects the annual operating cost of the mercury emission control equipment to be less than $1 million. Springerville Based on the EPA’s final standards, Springerville may need mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million. Sundt Generating Station TEP expects the final EPA standards will have little effect on capital expenditures at Sundt Generating Station (Sundt). Regional Haze Rules The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART)BART for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areasareas. States must submit these goals and to submit a state implementation planstrategies to the EPA. San Juan
In December 2010,EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight. The EPA proposed a federal implementation plan under the Clean Air Act, addressing, among other things,oversees regional haze requirementsplanning for San Juan. The EPA plan proposes that the BART for nitrogen oxides at San Juan is a technology known as “selective catalytic reduction” (SCR). EPA’s proposal would give the San Juan participants three years from the date of the final rule to achieve compliance. A final federal implementation plan is expected in 2011.
In June 2010, the New Mexico Environment Department (NMED) filed its proposed implementation plan for regional haze with the New Mexico Environmental Improvement Board. That plan also identified SCRs as the BART for nitrogen oxides at San Juan. However, the NMED’s plan also required a technology known as sorbent injection, and it gave the San Juan participants five years to achieve compliance. The NMED withdrew its proposed implementation plan after the EPA filed its proposal.
PNM, the operator at San Juan, has concluded that SCR is not the BART and has indicated it intends to vigorously challenge the EPA’s proposal.
TEP’s share of capital expenditures related to the installation of SCRs is estimated to be $202 million. This estimate is based on a 2010 cost analysis of the installation of SCR technology over five years. The three-year installation proposed by the EPA could increase the cost of compliance. Adding this technology to San Juan would also increase operating costs at the generating station.
these power plants. K-126
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Four Corners
In October 2010, EPA issued a proposed federal implementation plan (FIP) for BART at the Four Corners, which was supplemented in February 2011. The revised FIP, if approved, would require the installation of SCRs on units 4 and 5. TEP’s estimated share of capital expenditures related to the installation of SCRs for units 4 and 5 is approximately $35 million. Once the EPA finalizes the BART rule for Four Corners, the Four Corners participants would have until 2018 to achieve compliance.
Navajo
SRP, on behalf of the owners, is currently participating in an EPA sanctioned stakeholder process designed to determine BART for Navajo. If SCR is determined by the EPA to be the BART at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCRs at Navajo could result in an increase in the level of particulate emissions from the plant requiring the installation of baghouses. TEP’s estimated share of capital expenditures related to the installation of baghouses at Navajo is $43 million. The exact level and cost of necessary pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes the BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.
The San Juan, Four Corners and Navajo Plant participants’ obligations to complyComplying with the EPA’s BART determinations, coupledfindings, and with the financial impact of future climate change legislation, other environmental regulationsrules, may make it economically impractical to continue operating the Navajo, San Juan, and other business considerations, could jeopardize the economic viability of theseFour Corners power plants or the ability offor individual participantsowners to meet their obligations and continue their participationto participate in these facilities.
power plants. TEP cannot predict the ultimate outcome of these matters. Tucson to Nogales Transmission Line
Navajo In January 2013, the EPA proposed an alternative BART determination that would require the installation of SCR technology on all three units at Navajo by 2023. If SCR technology is ultimately required at Navajo, TEP 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. UNS Electric’s participation in this project was initiated in response to an order by the ACC to improve the reliability of electric service in Nogales. That order was issued before UniSource Energy purchased the electric system in Nogales and surrounding Santa Cruz County from Citizens Utilities in August 2003. In 2002, the ACC approved the location and constructionestimates its share of the proposed 345-kV line along a route identified as the Western Corridor subject to a number of conditions, including the issuance of all required permits from state and federal agencies. The U.S. Forest Service subsequently expressed its preference for a different route in its final Environmental Impact Statement for the project. TEP and UNS Electric are considering options for the project including potential new routes. If a decision is made to pursue an alternative route, approvalscapital cost will be needed from$42 million. Also, the ACC,installation of SCR technology at Navajo could increase the U.S. Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of December 31, 2010 and December 31, 2009,power plant’s particulate emissions which may require that baghouses be installed. TEP had capitalized $11 million related to the project, including $2 million to secure land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequenceestimates that its share of the ACC’s requirementcapital expenditure for a second transmission line serving the Nogales, Arizona area.
GUARANTEES AND INDEMNITIES
In the normal coursebaghouses would be about $43 million. TEP’s share 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 standalone basis. The most significant of these guarantees are:
UES’ guarantee of senior unsecured notes issued by UNS Gas ($100 million) and UNS Electric ($100 million);
UES’ guaranteeannual operating costs is estimated at less than $1 million for each of the $100 million UNS Gas/UNS Electric Revolver;
UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas;control technologies (SCR and
UniSource Energy’s guarantee of the $30 million of outstanding loans under the UED Secured Term Loan.
baghouses). K-127
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) To(Continued)San Juan In August 2011, the extent liabilities exist under these contracts,EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the liabilities are includedState of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million. In 2011, PNM filed a petition for review of and a motion to stay the FIP with the Tenth Circuit United States Court of Appeals (Circuit Court). In addition, PNM filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA’s reconsideration and the review by the Circuit Court. The State of New Mexico filed similar motions with the Circuit Court and the EPA. Several environmental groups were granted permission to join in our balance sheets. opposition to PNM’s petition to review in the Circuit Court. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP’s five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2010,2012, the Circuit Court denied PNM’s and the State of New Mexico’s motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the Circuit Court’s decision.In February 2013, the State of New Mexico released a proposed plan that it presented to the EPA as an alternative to the FIP. The proposed plan includes: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement of those units with non-coal generation sources; and the installation of selective non-catalytic reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016. TEP purchased 100%estimates its share of the equity interestcost to install SNCR technology on San Juan Unit 1 would be approximately $25 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. At December 31, 2012, the book value of TEP’s share of San Juan Units 1 and 2 was $217 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. If the proposed plan is not accepted and agreed to by the EPA, the New Mexico Environmental Department, the San Juan participants, and various other regulatory entities, TEP may begin making capital expenditures to install SCRs on San Juan Units 1 and 2 in Sundt Unit 4.2013 to meet the FIP compliance deadline. TEP indemnifiedcannot predict the sellerultimate outcome of this matter. Four Corners In August 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly-owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. In either case, TEP’s estimated share of the capital costs to install SCR technology is about $35 million. TEP’s share of annual operating costs for SCR is estimated at $2 million. Springerville Regional haze regulations requiring emission control upgrades do not apply to Springerville currently and are not likely to impact Springerville operations until after 2018. Sundt In December 2012, the EPA issued a proposed rule on provisions, that had not been previously addressed, in the Arizona State Implementation Plan related to regional haze. Contrary to the Arizona plan the EPA disapproved, among other things, the determination that Sundt Unit 4 from any sales or use taxes, transfer fees or other such costs relatingis not subject to the purchase. The termsBART provisions of the indemnification do not includeregional haze rule and is therefore subject to BART requirements. If the BART eligibility determination stands, Sundt Unit 4 will be required to reduce certain emissions within five years of the final EPA BART rule which is likely to be completed in October 2013. The EPA is expected to release a limit on potential future payments; however,proposed BART requirement for Sundt Unit 4 in March 2013. UNS ENERGY, TEP, believes that the parties to the agreement have abided by all tax laws and that TEP does not have any additional tax obligations. TEP has not made any payments under the terms of this indemnification to date. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES The following table shows Utility Plant in Service by company and major class. | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | | | | | | | | | | UNS | | | | | | UniSource | | | | | TEP | | | UNS Gas | | | Electric | | | UED | | | Energy | | | Plant in Service: | | | | | | | | | | | | | | | | | | | | | | Electric Generation Plant | | $ | 1,709 | | | $ | — | | | $ | 18 | | | $ | 60 | | | $ | 1,787 | | | Electric Transmission Plant | | | 705 | | | | — | | | | 31 | | | | 5 | | | | 741 | | | Electric Distribution Plant | | | 1,168 | | | | — | | | | 200 | | | | — | | | | 1,368 | | | Gas Distribution Plant | | | — | | | | 224 | | | | — | | | | — | | | | 224 | | | Gas Transmission Plant | | | — | | | | 18 | | | | — | | | | — | | | | 18 | | | General Plant | | | 187 | | | | 16 | | | | 12 | | | | — | | | | 215 | | | Intangible Plant | | | 90 | | | | 1 | | | | 4 | | | | — | | | | 95 | | | Electric Plant Held for Future Use | | | 4 | | | | — | | | | 1 | | | | — | | | | 5 | | | | | | | | | | | | | | | | | | | | Total Plant in Service | | $ | 3,863 | | | $ | 259 | | | $ | 266 | | | $ | 65 | | | $ | 4,453 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Utility Plant under Capital Leases | | $ | 582 | | | $ | — | | | $ | 1 | | | $ | — | | | $ | 583 | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Plant in Service: | | | | | | | | | | | | | | | | | Electric Generation Plant | | $ | 1,932 | | | $ | 1,879 | | | $ | 1,847 | | | $ | 1,795 | | Electric Transmission Plant | | | 842 | | | | 810 | | | | 796 | | | | 766 | | Electric Distribution Plant | | | 1,495 | | | | 1,453 | | | | 1,271 | | | | 1,234 | | Gas Distribution Plant | | | 240 | | | | 233 | | | | — | | | | — | | Gas Transmission Plant | | | 18 | | | | 18 | | | | — | | | | — | | General Plant | | | 347 | | | | 331 | | | | 309 | | | | 302 | | Intangible Plant—Software Costs(1) (2) | | | 124 | | | | 122 | | | | 123 | | | | 121 | | Intangible Plant—Other | | | 5 | | | | 5 | | | | — | | | | — | | Electric Plant Held for Future Use | | | 3 | | | | 5 | | | | 2 | | | | 4 | | | | | | | | | | | | | | | | | | | Total Plant in Service | | $ | 5,006 | | | $ | 4,856 | | | $ | 4,348 | | | $ | 4,222 | | | | | | | | | | | | | | | | | | | Utility Plant under Capital Leases | | $ | 583 | | | $ | 583 | | | $ | 583 | | | $ | 583 | | | | | | | | | | | | | | | | | | |
K-128
| (1) | Unamortized computer software costs were $36 million for UNS Energy and $35 million for TEP as of December 31, 2012, and $43 million for UNS Energy and $42 million for TEP as of December 31, 2011. |
| (2) | The amortization of computer software costs in UNS Energy’s income statements was $13 million in 2012, $10 million in 2011, and $9 million in 2010. The amortization of computer software costs in TEP’s income statements before intercompany allocations was $13 million in 2012, $10 million in 2011, and $9 million in 2010. |
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
| | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | | | | | | | | | | UNS | | | | | | UniSource | | | | | TEP | | | UNS Gas | | | Electric | | | UED | | | Energy | | | Plant in Service: | | | | | | | | | | | | | | | | | | | | | | Electric Generation Plant | | $ | 1,527 | | | $ | — | | | $ | 17 | | | $ | 61 | | | $ | 1,605 | | | Electric Transmission Plant | | | 682 | | | | — | | | | 30 | | | | 4 | | | | 716 | | | Electric Distribution Plant | | | 1,110 | | | | — | | | | 185 | | | | — | | | | 1,295 | | | Gas Distribution Plant | | | — | | | | 216 | | | | — | | | | — | | | | 216 | | | Gas Transmission Plant | | | — | | | | 18 | | | | — | | | | — | | | | 18 | | | General Plant | | | 178 | | | | 15 | | | | 11 | | | | — | | | | 204 | | | Intangible Plant | | | 82 | | | | 1 | | | | 4 | | | | — | | | | 87 | | | Electric Plant Held for Future Use | | | 5 | | | | — | | | | 1 | | | | — | | | | 6 | | | | | | | | | | | | | | | | | | | | Total Plant in Service | | $ | 3,584 | | | $ | 250 | | | $ | 248 | | | $ | 65 | | | $ | 4,147 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Utility Plant under Capital Leases | | $ | 720 | | | $ | — | | | $ | 1 | | | $ | — | | | $ | 721 | | | | | | | | | | | | | | | | | | |
TEP’s unamortized computer software costs included in Intangible Plant above were $33 million as of December 31, 2010 and $31 million as of December 31, 2009. UNS Gas and UNS Electric had unamortized computer software costs of less than $1 million at both December 31, 2010 and December 31, 2009.
UniSource Energy’s total plant includes $65 million of non-regulated plant in service for 2010 and 2009, with $4 million of accumulated depreciation in 2010 and $3 million in 2009. Rates for utility operations appearing in this table, excluding those owned by UED, are set by the ACC or FERC on a cost-of-service basis, and they are accounted for under the provisions of regulatory accounting for all periods.
TEP Utility Plant under Capital Leases All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term as described interm. See Note 6. In April 2010 TEP terminated the capital lease of Sundt Unit 4 and purchased the related leased assets. At December 31, 2010,2012, the utility plant under capital leases includesincludes: 1) Springerville Unit 1; 2) Springerville Common Facilities, Springerville Unit 1,Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases. | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Lease Expense: | | | | | | | | | | | | | | Interest Expense — Included in: | | | | | | | | | | | | | | Capital Leases | | $ | 47 | | | $ | 49 | | | $ | 52 | | | Operating Expenses — Fuel | | | 4 | | | | 4 | | | | 5 | | | Other Expense | | | 2 | | | | 1 | | | | — | | | Amortization of Capital Lease Assets — Included in: | | | | | | | | | | | | | | Operating Expenses — Fuel | | | 3 | | | | 2 | | | | 4 | | | Operating Expenses — Depreciation and Amortization | | | 14 | | | | 26 | | | | 21 | | | | | | | | | | | | | | Total Lease Expense | | $ | 70 | | | $ | 82 | | | $ | 82 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Years Ended
December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Lease Expense: | | | | | | | | | | | | | Interest Expense – Included in: | | | | | | | | | | | | | Capital Leases | | $ | 34 | | | $ | 40 | | | $ | 47 | | Operating Expenses – Fuel | | | 3 | | | | 4 | | | | 4 | | Other Expense | | | — | | | | 1 | | | | 2 | | Amortization of Capital Lease Assets – Included in: | | | | | | | | | | | | | Operating Expenses – Fuel | | | 4 | | | | 3 | | | | 3 | | Operating Expenses – Amortization | | | 14 | | | | 14 | | | | 14 | | | | | | | | | | | | | | | Total Lease Expense | | $ | 55 | | | $ | 62 | | | $ | 70 | | | | | | | | | | | | | | |
K-129
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)The depreciable lives as of December 31, 20102012, were as follows: | | | | | | | | | | | | | | | UNS Gas, | | | | | | | | UNS Electric | | | Major Class of Utility Plant in Service | | TEP | | | & UED | UNS Gas and
UNS Electric | Electric Generation Plant | | | | | | | | | Electric Generation Plant | | 6-5911-57 years | | | 38-49 years | | Electric Transmission Plant | | 20-60 years | | | 20-50 years | | Electric Distribution Plant | | 28-60 years | | | 23-50 years | | Gas Distribution Plant | | | n/a | | | 30-55 years | | Gas Transmission Plant | | | n/a | | | 30-65 years | | General Plant | | 5-31 years | | 5-40 years | Intangible Plant | 5-40 | 3-19 years | | Intangible Plant | | 3-183-32 years | | | 5-32 years | |
SeeTEP Utility Plantin Note 1 andTEP Capital Lease Obligationsin Note 6. At December 31, 2010,2012, TEP’s interests in jointly-owned generating stations and transmission systems were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Plant | | | Construction | | | | | | | | Ownership | | | in | | | Work in | | | Accumulated | | | | | Percentage | | | Service | | | Progress | | | Depreciation | | | | | -Millions of Dollars- | | | San Juan Units 1 and 2 | | | 50.0 | % | | $ | 419 | | | $ | 8 | | | $ | 219 | | | Navajo Station Units 1, 2 and 3 | | | 7.5 | | | | 121 | | | | 6 | | | | 84 | | | Four Corners Units 4 and 5 | | | 7.0 | | | | 95 | | | | 1 | | | | 69 | | | Transmission Facilities | | | 7.5 to 95.0 | | | | 280 | | | | 12 | | | | 178 | | | Luna Energy Facility | | | 33.3 | | | | 51 | | | | 1 | | | | 1 | | | | | | | | | | | | | | | | | Total | | | | | | $ | 966 | | | $ | 28 | | | $ | 551 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Ownership
Percentage | | Plant
in
Service | | | Construction
Work in
Progress | | | Accumulated
Depreciation | | | Net Book
Value | | | | | -Millions of Dollars- | | San Juan Units 1 and 2 | | 50.0% | | $ | 443 | | | $ | 7 | | | $ | 220 | | | $ | 230 | | Navajo Units 1, 2, and 3 | | 7.5 | | | 148 | | | | 1 | | | | 106 | | | | 43 | | Four Corners Units 4 and 5 | | 7.0 | | | 97 | | | | 2 | | | | 73 | | | | 26 | | Luna Energy Facility | | 33.3 | | | 53 | | | | — | | | | — | | | | 53 | | Transmission Facilities | | 7.5 to 95.0 | | | 328 | | | | 22 | | | | 186 | | | | 164 | | | | | | | | | | | | | | | | | | | | | Total | | | | $ | 1,069 | | | $ | 32 | | | $ | 585 | | | $ | 516 | | | | | | | | | | | | | | | | | | | | |
TEP has financed or provided funds for the above facilities and TEP’s share of theirits operating expenses is reflected in the income statements. See Note 4 for commitmentsstatements based on the nature of the expense. ASSET RETIREMENT OBLIGATIONS The accrual of AROs is primarily related to TEP’s jointly-owned facilities. generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets: | | | | | | | | | | | | UNS Energy and TEP | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Beginning Balance | | $ | 13 | | | $ | 4 | | Liabilities Incurred | | | — | | | | 1 | | Liabilities Settled | | | — | | | | — | | Accretion Expense | | | 1 | | | | — | | Revision to Estimated Cash Flows | | | — | | | | 8 | | | | | | | | | | | Ending Balance | | $ | 14 | | | $ | 13 | | | | | | | | | | |
NOTE 6. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS Long-term debt matures more than one year from the date of the financial statements. We summarize UniSourceUNS Energy’s and TEP’s long-term debt in the statements of capitalization. UNISOURCEUNS ENERGY, DEBT- Convertible Senior Notes UniSourceTEP, AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) UNS ENERGY DEBT—CONVERTIBLE SENIOR NOTES In 2005, UNS Energy hasissued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. TheIn 2012, UNS Energy converted or redeemed the entire $150 million 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 28.1 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $35.59 per share of our Common Stock, subject to adjustment in certain circumstances. Beginning on March 5, 2010, UniSource Energy has 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.outstanding. Holders of the Convertible Senior Notes may require UniSource Energyhad the option of converting their interests to repurchaseCommon Stock at a conversion rate applicable at the time of each notice of redemption or receiving the redemption price of par plus accrued interest for the Convertible Senior Notes, in whole or in part, for cash on March 1Notes. In the first quarter of 2015, 2020, 2025 and 2030, or if certain change2012, holders 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 amountapproximately $73 million of the Convertible Senior Notes plus accrued interest.
converted their interests into approximately 2.1 million shares of Common Stock and $2 million were redeemed for cash. In the second quarter of 2012, holders of approximately $74 million of Convertible Senior Notes converted their interests into approximately 2.2 million shares of Common Stock and $1 million were redeemed for cash. K-130
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
TEP DEBT Tax-Exempt Variable Rate Tax-Exempt Bonds (IDBs) At December 31, 2010, and Interest Rate SwapTEP had $365$215 million in tax-exempt variable rate debt outstanding;outstanding at December 31, 2009, it had $459 million of such debt outstanding.2012 and December 31, 2011. Each series of bonds is supported by a letterLetter of creditCredit (LOC) issued under the TEP Credit Agreement or separate TEP Letter of Credit orand Reimbursement Agreements. The letters of creditLOCs are secured by mortgage bonds issued under TEP’s 1992 Mortgage. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest rate payable under the indentures for these bonds is 10% on the 2010 Coconino A Bonds and the 2008 Pima B Bonds and 20% on the other $329 million in IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.26% in 2010 and 0.41% in 2009. The average weekly interest rate ranged from 0.17% to 0.39% in 2010 and 0.25% to 0.79% during 2009. In addition to the variable interest rate,November 2011, TEP pays a letter of credit fee, a letter of credit fronting fee to the issuing bank and a remarketing fee on each series of bonds. As of December 31, 2010, the letter of credit fees payable ranged from 1.50% to 1.875%, the LOC fronting fees ranged from 0.20% to 0.25% and the remarketing fees averaged 7 basis points. In August 2009, TEP entered into an interest rate swap that had the effect of converting $50repurchased $150 million of variable rate IDBs to a fixed rate of 2.4% from September 2009 to September 2014.
2010 Coconino Series A Bonds
bonds. TEP did not cancel the repurchased bonds, which remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. See 2011 TEP Unsecured Notes below.In December 2010, the Coconino County, Arizona Pollution Control Corporation (Coconino PCC)TEP issued $37 million of Coconino County, Arizona, tax-exempt pollution control revenue bonds (2010 Coconino A Bonds) for TEP’s benefit.. The 2010 Coconino A Bonds are supported by a letter of credit (LOC) issued under the TEP Reimbursement Agreement. The LOC, which is secured by $37 million of 1992 Mortgage Bonds and expires December 14, 2014. The bonds accrue interest at a variable weekly rate and are due October 2032. These bonds are multi-modal bonds that allow TEP to change the interest feature of the bonds. They are callable at any time at par plus accrued interest to change the interest feature of the bonds. Additionally, the bondsand are subject to mandatory redemption under certain circumstances if the LOC is not extended. The average interest rate on TEP’s 2010 Coconino A Bonds was 0.38%0.22% in 2010. The2012 and 0.23% in 2011. TEP used the proceeds were deposited with a trustee and were used on December 30, 2010 to redeem a corresponding principal amount of bonds previously issued by PCC for TEP’s benefit. fixed rate Coconino pollution control bonds. TEP capitalized less than $1 million in costs related to the issuance of these bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statements through October 2032, the term of the bonds. 2010 Pima Series AThe following table shows interest rates on TEP’s variable rate bonds which are reset weekly by its remarketing agents: | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | Interest Rates on Bonds: | | | | | | | | | | | | | Average Interest Rate | | | 0.17 | % | | | 0.18 | % | | | 0.26 | % | Range of Average Weekly Rates | | | 0.06 | % | | | 0.05 | % | | | 0.17 | % | | | | to 0.26 | % | | | to 0.34 | % | | | to 0.39 | % |
In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014. Unsecured Fixed Rate Bonds Issuance At December 31, 2012, TEP had $609 million in unsecured fixed rate bonds. At December 31, 2011, TEP had $616 million outstanding. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) In October 2010,March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033. TEP’s $8 million payment to the trustee was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized approximately $2 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statements through March 2030, the term of the bonds. In June 2012, the Industrial Development Authority of Pima County, (Pima Authority)Arizona issued approximately $16 million of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds together with $0.4 million accrued interest provided by TEP, were deposited with a trustee to retire approximately $16 million of outstanding unsecured tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033. TEP’s payment of accrued interest was the only cash flow activity since proceeds from the newly-issued bonds were not received or disbursed by TEP. TEP capitalized less than $0.5 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statements through June 2030, the term of the bonds. In November 2011, TEP redeemed $22 million in unsecured fixed rate bonds. See 2011 TEP Unsecured Notes below. In October 2010, TEP issued $100 million of its 2010 Series APima County, Arizona tax-exempt IDBs for TEP’s benefit.IDBs. The 2010 Pima Series A IDBs are unsecured, bear interest at a rate of 5.25%, mature in October 2040, and are callable at par on or after October 1, 2020. Net of an underwriting discount, $99 million of proceeds were deposited in a construction fund with the bond trustee. The proceeds were applied to the construction of certain of TEP’s transmission and distribution facilities used to provide electric service in Pima County. TEP drew down $88 million of the proceeds from the construction fund by December 31,in 2010 with the remainingand $11 million expected to be drawn down by the end of the first quarter ofin 2011. TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs to Interest Expense-Long-Term Debt in the income statements through October 2040, the term of the bonds. K-131
UNISOURCE ENERGY,In September 2012, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
2009 Sale and Redemption of Bonds
In October 2009, the Pima Authority issued approximately $80$150 million of its 2009 Series A tax-exempt pollution control bonds (2009 Pima A San Juan Bonds) for TEP’s benefit. At3.85% unsecured notes due March 2023. TEP may call the same time, the Coconino PCC issued approximately $15 million of its 2009 Series A tax-exempt pollution control bonds (2009 Coconino A Bonds) for TEP’s benefit. The 2009 Pima A San Juan Bonds are unsecured, bear interest at a rate of 4.95%, mature on October 1, 2020, and are not callabledebt prior to maturity. The 2009 Coconino A Bonds are unsecured, bear interest at 5.125%, mature on October 1, 2032, and are callable in whole or in part for cashDecember 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, TEP may call the debt at par beginning October 1, 2019. Semi-annual interest paymentsplus accrued interest. The unsecured notes contain a limitation on both seriesthe amount of bonds are payable beginning April 1, 2010.secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the revolving credit facility, with the remaining proceeds used for general corporate purposes. TEP capitalized approximately $1 million in costs related to the issuance of these bondsunsecured notes and will amortize the costs for eachto Interest Expense – Long-Term Debt in the income statements through March 2023, the respective maturity dates.
Theterm of the unsecured notes.2011 TEP Unsecured Notes In November 2011, TEP issued $250 million of 5.15% unsecured notes due November 2021. TEP may call the debt any time before August 15, 2021, with a make-whole premium plus accrued interest. After August 15, 2021, the debt is callable at par plus accrued interest. TEP used the net proceeds from the issuancesale to: 1) repurchase $150 million of variable rate bonds; 2) redeem $22 million of 6.1% fixed rate bonds; and 3) repay $78 million of outstanding revolving credit facility balances, with the remaining proceeds applied to general corporate purposes. The variable rate bonds were supported by LOCs issued under TEP’s Credit Facility. As a result of the 2009 Pima A San Juan Bonds andrepurchase of the 2009 Coconino A Bonds were deposited with a trustee and were used on November 2, 2009, to redeem approximately $80variable rate bonds, TEP cancelled $155 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control BondsLOCs and approximately $15 million of 7.0% 1997 Series B Coconino County, Arizona Pollution Control Bonds. Collateral Trust Bonds
In 1998, TEP issued a total of $140 million, 7.5% Collateral Trust Bonds, due August, 2008. TEP retired thesereduced its mortgage bonds in 2008. See 2008 Pima A and 2008 Pima B Bonds below.
2008 Pima A Bonds
In March 2008,supporting the Pima Authority issued, forLOCs by the benefit of TEP, approximately $91 million of its 2008 Series A tax-exempt, unsecured, 6.375% bonds (2008 Pima A Bonds) due September 1, 2029.same amount. TEP capitalized $1$2 million ofin costs related to the issuance of the 2008 Pima A Bondsnotes and will amortize thesethe costs to Interest Expense-Long-Term Debt in the income statements through August 2029,November 2021, the term of the bonds. Beginning in March 2013, TEP will have the option to redeem the 2008 Pima A Bonds, in whole or in part, for cash, at a price equal to 100% of the principal amount plus accrued interest.
2008 Pima B Bonds
In June 2008, the Pima Authority issued for TEP’s benefit, $130 million of its 2008 Series B tax-exempt variable rate IDBs (2008 Pima B Bonds) due September 1, 2029. The 2008 Pima B Bonds were supported by a letter of credit (LOC) issued under the TEP 2008 Letter of Credit Facility.
In January 2010, TEP converted the interest on the $130 million of 2008 Pima B Bonds from a variable rate to a fixed rate. The Pima B Bonds were reoffered in January 2010, with a term rate of 5.75% through maturity in September 2029. Interest is payable semi-annually beginning June 1, 2010. The bonds are callable at par beginning January 2015. Accordingly, the associated letter of credit which supported the 2008 variable rate Pima B Bonds was terminated in January 2010, and the TEP mortgage bonds which collateralized the letter of credit were cancelled.
TEP capitalized $1 million of costs related to the issuance of the 2008 Pima B Bonds and will amortize these costs through August 2029. TEP capitalized approximately $2 million of costs related to the reoffering in January 2010 and will amortize these costs through September 2029.
TEP Term Loan Borrowing
In March 2010, TEP entered into an 18-month, $30 million term loan facility. In October 2010, TEP repaid the term loan.
unsecured notes. K-132
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) TEP’s 1992 Mortgage creates liens on and security interests in most of TEP’s utility plant assets, with the exception of Springerville Unit 2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2. Utility Plant under Capital Leases is not subject to such liens ornor is it available to TEP creditors, other than the lessors. The net book value of TEP’s utility plant subject to the lien of the indenture was approximately $2 billion at December 31, 2010. 2012, and December 31, 2011.TEP CAPITAL LEASE OBLIGATIONS Sundt Unit 4
In March 2010, TEP purchased 100% of the equity interest in Sundt Unit 4 from the owner participants for $52 million. In April 2010, TEP paid the final outstanding Sundt Unit 4 lease obligation of $5 million to terminate the lease and reclassified the capital lease asset and the related leasehold improvements to plant in service. TEP is depreciating the asset over its best estimate of remaining plant life at the time of purchase which is 25 years.
The terms of TEP’s other capital leases are as follows: The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. TEP has a fair market value purchase option for facilities under the Springerville Unit 1 Lease. In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal process to determine the fair market value purchase price, in accordance with the Springerville Unit 1 Leases agreements. Based on that appraisal, TEP would have to pay $159 million in 2015 for the 86% interest not already owned by TEP. In 2012, TEP initiated a proceeding seeking judicial confirmation of the results of the appraisal process in federal district court. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for the leased interest. In January 2013, the federal district court denied TEP’s petition on the grounds that the court lacks jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit. The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for fixed-rate lease renewal options if certain conditions are satisfied as well as a fixed-price purchase provision of $120 million. The lease provides for one renewal period of six years beginning in April 2015, with additional renewal periods of five or more years through 2035. The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods Instead 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.
extending the leases TEP agreed with the owners of Springerville Units 3 and 4 that, prior to expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will either renew these leases or acquire the leased interest in the facilities atmay exercise a fixed-price purchase provision. The fixed prices for the acquisition of $120 million in 2015,common facilities are $38 million in 2017 and $68 million in 2021. Upon such acquisitions by TEP eachagreed with Tri-State, the owner of the owners ofSpringerville Unit 3, and SRP, the owner of Springerville Unit 4, have the obligation to purchase or continue renting from TEP at 17% and 14% interest, respectively, in such facilities. On or beforethat if the Springerville Unit 1 Lease expiration date,Coal Handling Facilities and Common Facilities Leases are not renewed, TEP will determine if itexercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either: a) purchase1) buy a portion of these facilities; or 2) continue making payments to TEP for the assets at the fair market value; b) extend the lease term; or c) not continue with an interest in Springerville Unit 1. use of these facilities.In January 2011,2013, through scheduled lease payments, TEP reduced its capital lease obligations by $63$82 million. LEASE DEBT AND EQUITY Investments in Springerville Lease Debt and Equity In March 2009, TEP purchased $31 million of Springerville Unit 1 lease debt. That price included a premium that will be amortized over the remaining term of the lease debt. TEP’s investmentinvestments in Springerville Unit 1 lease debt totaled $67$9 million at December 31, 20102012, and $88$29 million at December 31, 2009.2011. In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 leaseLeases totaling $37 million at both of December 31, 2010 and December 31, 2009. TEP held an investment in Springerville Coal Handling Facilities lease debt totaling $1$36 million at December 31, 20102012, and $7$37 million at December 31, 2009. In January 2011, TEP received the final maturity payment of $1 million on the investment in Springerville Coal Handling Facilities debt. 2011. K-133
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)Interest Rate Swaps — Swaps—Springerville Common Facilities Lease Debt In June 2006 and in May 2009, TEP entered intoTEP’s interest rate swaps to hedge the floating interest rate risk associated with the Springerville Common Facilities Leaselease debt. Interest on the lease debt is payable at six-month LIBORLondon Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2012, and 1.625% at each of December 31, 2010 and December 31, 2009. 2011. The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows: | | | | | | | | | | | | | | | | | LIBOR | | | Outstanding at December 31, 2010 | | Fixed Ratio | | | Spread | | | $35 million | | | 5.77 | % | | | 1.625 | % | | $22 million | | | 3.18 | % | | | 1.625 | % | | $7 million | | | 3.32 | % | | | 1.625 | % |
These | | | | | | | | | Outstanding at December 31, 2012 | | Fixed
Ratio | | | LIBOR
Spread | | $ 34 million | | | 5.77 | % | | | 1.75 | % | $ 19 million | | | 3.18 | % | | | 1.75 | % | $ 6 million | | | 3.32 | % | | | 1.75 | % |
TEP recorded these interest rate swaps have been recorded by TEP as a cash flow hedge for financial reporting purposes. See Note 16. UNS ELECTRIC SENIOR UNSECURED DEBT NOTESUNS Electric has $100 million of senior unsecured debt;notes: $50 million at 6.5%, due 2015 and $50 million at 7.1%, due 2023. The UNS Electric long-term debt isnotes are guaranteed by UES. The notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity U.S.United States Treasury security yield plus 50 basis points. UNS Electric’s long-term debt containsnotes contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the $30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four-year period ending August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES. The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions on transactions with affiliates, restricted payments, additional indebtedness, liens, and mergers. UNS Electric must meet an interest coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement. UNS GAS SENIOR UNSECURED NOTES In August 2011, UNS Gas issued $50 million of senior guaranteed notes at 5.39% due August 2026. UNS Gas used the proceeds to pay in full the $50 million of UNS Gas 6.23% notes that matured in August 2011. UNS Gas has $100another $50 million of senior unsecured notes outstanding, consisting of $50 million at 6.23%, due August 2011, and $50 million at 6.23%, due August 2015. The notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity U.S.United States Treasury security yield plus 50 basis points. UES guarantees the notes. UNS Gas capitalized less than $0.5 million of costs related to the issuance of the notes and will amortize these costs over the life of the notes.UNS Gas’ long-term debt contains certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, and incurrence of indebtedness. UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) UNS ENERGY CREDIT AGREEMENT In November 2011, UNS Energy amended its existing credit agreement to extend the expiration date from November 2014 to November 2016. In November 2010, UniSourceUNS Energy amended and restated its existing credit agreement. The UniSource Energy Credit Agreement previously included a $30 million term loan facility and a $70 million revolving credit facility. As amended, the UniSource Energy Credit Agreementagreement consists of a $125 million revolving credit facility and revolving letter of credit facility that expire in November 2014. UniSourcefacility. UNS Energy’s obligations under the UniSource Energy Credit Agreementagreement are secured by a pledge of the capital stock of Millennium, UES, and UED. UniSource UNS Energy capitalized $1less than $0.5 million of costs related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement, and will amortize these costs over the termthrough November 2016. UNS Energy had $45 million of the agreement. K-134
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Atoutstanding borrowings at December 31, 20102012, and $57 million of outstanding borrowings at December 31, 2011, under its revolving credit facility. The weighted average interest rate on the following balances were outstanding:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current | | | Long-Term | | | | | | | Current | | | Long- | | | | | | | | Liabilities | | | Debt | | | Total | | | Liabilities | | | Term Debt | | | Total | | | | | - Millions of Dollars- | | | | | December 31, 2010 | | | December 31, 2009 | | | Revolver | | $ | — | | | $ | 27 | | | $ | 27 | | | $ | — | | | $ | 31 | | | $ | 31 | | | | | | | | | | | | | | | | | | | | | | | Term Loan | | $ | — | | | $ | — | | | $ | — | | | $ | 6 | | | $ | 3 | | | $ | 9 | | | | | | | | | | | | | | | | | | | | | | | Weighted Average Interest Rate on the Revolver and Term Loan | | | — | | | | — | | | | 3.26 | % | | | — | | | | — | | | | 1.48 | % | | | | | | | | | | | | | | | | | | | | |
We have includedrevolver was 1.96% at December 31, 2012, and 2.04% at December 31, 2011.We reflected the revolver borrowings in Long-Term Debt on the balance sheet as UniSourceUNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 15, 2011,13, 2013, outstanding borrowings under the UniSource EnergyUNS Credit Agreement were $31$45 million.
Interest rates and fees under the UniSourceUNS Energy Credit Agreement are based on a pricing grid tied to UniSourceUNS Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 3.0%1.75% for Eurodollar loans or Alternate Base Rate plus 2.0%0.75% for Alternate Base Rate loans. The UniSourceUNS Energy Credit Agreement contains a number of covenants which restrict UniSourceUNS Energy and its subsidiaries, including restrictions on additional indebtedness, liens, mergers, and sales of assets. The UniSourceUNS Energy Credit Agreement also requires UniSourceUNS Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSourceUNS Energy standalone basis and not to exceed a maximum leverage ratio determined on a consolidated basis. Under terms of the UniSourceUNS Energy Credit Agreement, UniSourceUNS Energy may pay dividends so long as it maintains compliance with the agreement. In December 2011, TEP reduced its letter of credit facility from $341 million to $186 million, following the repurchase of $150 million of variable rate bonds and the cancellation of $155 million of LOCs supporting those bonds. In November 2011, TEP amended its existing credit agreement to extend the expiration date from November 2014 to November 2016. In November 2010, TEP amended and restated its existing credit agreement. The TEP Credit Agreement had previously included a $150 million revolving credit facility and a $341 million letter of credit facility to support $329 million aggregate principal amount of tax-exempt variable rate bonds. As amended, the TEP Credit Agreement consistsagreement, consisting of a $200 million revolving credit, and revolving letter of creditLOC facility, and a $341 million letter of creditLOC facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2014 andcredit facility is secured by $541$386 million of mortgage bonds issued under the 1992 Mortgage, which creates a lien on and security interest in most of TEP’s utility plant assets. TEP capitalized $4$1 million of costs related to the 2011 credit agreement amendment and $4 million related to the 2010 credit agreement amendment and restatement, and will amortize these costs through the term of the agreement. November 2016.Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.875%1.125% for Eurodollar loans or Alternate Base Rate plus 0.875%0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $341$186 million letter of credit facility is 1.875%1.125%. The TEP Credit Agreement contains a number of covenants which restrict TEP and its subsidiaries, including restrictions on liens, mergers, and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. Under the terms of the TEP Credit Agreement, TEP may pay dividends to UniSourceUNS Energy so long as it maintains compliance with the agreement. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) As of December 31, 2010,2012, TEP had no borrowings outstanding and $1 million outstanding in letters of creditLOCs issued under its revolving credit facility. As of December 31, 2009,2011, TEP had $35$10 million in borrowings and $1 million outstanding in letters of creditLOCs under its revolving credit facility. The revolving loan balance was included in Current Liabilities in the UniSource Energyon UNS Energy’s and TEPTEP’s balance sheets. The outstanding letters of creditLOCs are off-balance sheet obligations of TEP. As of February 15, 2011,13, 2013, TEP had $35$30 million in borrowings and $1 million outstanding in letters of creditLOCs under its revolving credit facility. K-135
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
2010 TEP REIMBURSEMENT AGREEMENT In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million letter of credit was issued pursuant to the 2010 TEP Reimbursement Agreement. The letter of credit supports $37 million aggregate principal amount of variable rate tax-exempt IDBsbonds that were issued on behalf of TEP in December 2010, (See 2010 Coconino Series Asee Variable Rate Tax-Exempt Bonds, above). above.The 2010 TEP Reimbursement Agreement is secured by $37 million of mortgage bonds issued under TEP’s 1992 Mortgage. Fees are payable on the aggregate outstanding amount of the letter of credit at a rate of 1.50% per annum. The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. UNS GAS/UNS ELECTRIC CREDIT AGREEMENT REVOLVERIn November 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement to extend the expiration date from November 2014 to November 2016. In November 2010, UNS Gas and UNS Electric amended and restated their existing unsecured credit agreement. The UNS Gas/UNS Electric Credit Agreement had previously consisted of a $60 million revolving credit facility. As amended, the UNS Gas/UNS Electric Credit AgreementRevolver consists of a $100 million revolving credit and revolving letter of credit facility, and expires November 2014.facility. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Gas and UNS Electric each are each liable for only their own individual borrowings under the UNS Gas/UNS Electric Revolver. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Revolver may be used to issue letters of credit,LOCs, as well as for revolver borrowings. UNS Gas and UNS Electric issue letters of credit,LOCs, which are off-balance sheet obligations, to support power and gas purchases and hedges. UNS Gas and UNS Electric capitalized $1less than $0.5 million of costs related to the 2011 credit agreement amendment and $1 million related to the 2010 credit agreement amendment and restatement, and will continue to amortize these costs through November 2016 to Interest Expense – Long-Term Debt in the term of the agreement. income statements.Interest rates and fees under the UNS Electric/Gas/UNS Gas Credit AgreementElectric Revolver are based on a pricing grid tied to the Borrower’stheir credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 2.5%1.25% for Eurodollar loans or Alternate Base Rate plus 1.5%0.25% for Alternate Base Rate loans. The UNS Electric/Gas/UNS Gas Credit AgreementElectric Revolver contains a number of covenants which restrict the Borrowersimpose restrictions on UNS Gas, UNS Electric, and UES, including restrictions on additional indebtedness, liens, and mergers. The UNS Electric/Gas/UNS Gas Credit AgreementElectric Revolver also requires each Borrower not to exceedstipulates a maximum leverage ratio. Under the terms of the UNS Electric/Gas/UNS Electric Revolver, UNS Gas Credit Agreement, the Borrowersand UNS Electric may pay dividends so long as they maintain compliance with the agreement. UNS Electric had $13 million and $11less than $0.5 million in outstanding letters of creditLOCs under the UNS Gas/UNS Electric Revolver as of December 31, 20102012, and $6 million outstanding as of December 31, 2009, respectively, which2011. These balances are not shown on the balance sheet. UED SECURED TERM LOAN
In March 2009, UED entered into a 364-day, $30 million variable rate senior secured term loan facility. UED paid $1 million in debt issuance costs which were amortized to interest expense over the one year term of the loan. In February 2010, UED amended its senior secured term loan facility to extend the termination date by two years to March 2012, and to increase borrowings by $9 million bringing the outstanding balance to $35 million. UED capitalized less than $1 million in costs related to the transaction. The loan is guaranteed by UniSource Energy and is secured by a lien on substantially all the assets of UED, including the BMGS and an assignment of UED’s PPA with UNS Electric.
K-136
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Other
As ofAt December 31, 2010, UniSource2012, UNS Energy and its subsidiaries were in compliance with the terms of their respective loan, note purchase, and credit agreements.
No amounts of net income were subject to dividend restrictions.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) DEBT MATURITIES Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TEP | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Variable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rate IDBs | | | TEP | | | TEP | | | | | | | | | | | | | | | UniSource | | | | | | | | Supported | | | Scheduled | | | Capital | | | | | | | | | | | | | | | Energy | | | | | | | | by Letters | | | Debt | | | Lease | | | TEP | | | UNS | | | UNS | | | (includes | | | | | | | | of Credit(1) | | | Retirements | | | Obligations | | | Total | | | Gas | | | Electric | | | UED) | | | Total | | | | | - Millions of Dollars - | | | 2011 | | $ | — | | | $ | — | | | $ | 107 | | | $ | 107 | | | $ | 50 | | | $ | — | | | $ | 7 | | | $ | 164 | | | 2012 | | | — | | | | — | | | | 118 | | | | 118 | | | | — | | | | — | | | | 23 | | | | 141 | | | 2013 | | | — | | | | — | | | | 122 | | | | 122 | | | | — | | | | — | | | | — | | | | 122 | | | 2014 | | | 365 | | | | — | | | | 195 | | | | 560 | | | | — | | | | — | | | | 27 | | | | 587 | | | 2015 | | | — | | | | — | | | | 24 | | | | 24 | | | | 50 | | | | 50 | | | | — | | | | 124 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total 2011 — 2015 | | | 365 | | | | — | | | | 566 | | | | 931 | | | | 100 | | | | 50 | | | | 57 | | | | 1,138 | | | Thereafter | | | — | | | | 638 | | | | 79 | | | | 717 | | | | — | | | | 50 | | | | 150 | | | | 917 | | | Less: Imputed Interest | | | — | | | | — | | | | (156 | ) | | | (156 | ) | | | — | | | | — | | | | — | | | | (156 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 365 | | | $ | 638 | | | $ | 489 | | | $ | 1,492 | | | $ | 100 | | | $ | 100 | | | $ | 207 | | | $ | 1,899 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TEP
Variable
Rate Bonds
Supported
by Letters
of Credit(1) | | | TEP
Scheduled
Debt
Retirements(2) | | | TEP
Capital
Lease
Obligations | | | TEP
Total | | | UNS
Gas | | | UNS
Electric | | | UNS
Energy
Parent
Company | | | Total | | | | | —Millions of Dollars - | | 2013 | | $ | — | | | $ | — | | | $ | 121 | | | $ | 121 | | | $ | — | | | $ | — | | | $ | — | | | $ | 121 | | 2014 | | | 37 | | | | — | | | | 194 | | | | 231 | | | | — | | | | — | | | | — | | | | 231 | | 2015 | | | — | | | | — | | | | 23 | | | | 23 | | | | 50 | | | | 80 | | | | — | | | | 153 | | 2016 | | | 178 | | | | — | | | | 17 | | | | 195 | | | | — | | | | — | | | | 45 | | | | 240 | | 2017 | | | — | | | | — | | | | 18 | | | | 18 | | | | — | | | | — | | | | — | | | | 18 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total 2013 – 2017 | | | 215 | | | | — | | | | 373 | | | | 588 | | | | 50 | | | | 80 | | | | 45 | | | | 763 | | Thereafter | | | — | | | | 1,009 | | | | 42 | | | | 1,051 | | | | 50 | | | | 50 | | | | — | | | | 1,151 | | Less: Imputed Interest | | | — | | | | — | | | | (62 | ) | | | (62 | ) | | | — | | | | — | | | | — | | | | (62 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 215 | | | $ | 1,009 | | | $ | 353 | | | $ | 1,577 | | | $ | 100 | | | $ | 130 | | | $ | 45 | | | $ | 1,852 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (1) | | TEP’s Variable Rate IDBsvariable rate bonds are backed by a $341$186 million LOCin LOCs issued pursuant to TEP’s Credit Agreement which expires in November 20142016 and TEP’s $37 million Reimbursement Agreement which expires in December 2014. Although the Variable Rate IDBsvariable rate bonds mature between 2018 and 2032, the above table reflects a redemption or repurchase of such bonds in 2014 and 2016 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. |
| (2) | The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount. |
NOTE 7. STOCKHOLDERS’ EQUITY OurUNS Energy’s ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium, and UED, as well as compliance with various debt covenant requirements. Because UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2010, there2012; therefore, TEP and the other subsidiaries were no dividend restrictionsnot restricted from the debt covenants. paying dividends.In February 2011, UniSource2013, UNS Energy declared a first quarter dividend to shareholders of $0.42$0.435 per share of UniSourceUNS Energy Common Stock. The dividend, totaling approximately $15$18 million, will be paid on March 23, 201125, 2013, to common shareholders of record as of March 11, 2011. 13, 2013. In 2010, UniSource Energy paid quarterly dividends to the shareholdersfirst half of $0.39 per share, for a total of $1.56 per share, or $57 million for the year. In 2009, UniSource Energy paid quarterly dividends to the shareholders of $0.29 per share, for a total of $1.16 per share, or $41 million for the year. In 2008, UniSource Energy paid quarterly dividends to the shareholders of $0.24 per share, for a total of $0.96 per share, or $34 million, for the year. In 2008, UniSource Energy’s $34 million dividend to shareholders exceeded its retained earnings. As a result, we recorded dividends of $14 million against retained earnings and dividends of $20 million against common stock. UniSource Energy has no additional paid-in capital. Such dividends do not represent a return of capital dividend for income tax purposes.
K-137
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
TEP
TEP paid dividends to UniSource Energy of $60 million in both 2010 and 2009, and $3 million in 2008. In 2009, TEP recorded $0.82012, $147 million of dividend equivalents related to restrictedthe Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock units as dividends. UniSource Energy is the holder of TEP’s common stock. equity by $147 million.TEP The Federal Power Act states that an electric utility’s dividends shall not be paid out of funds properly included in capital accounts. TEP’s 2010, 2009, and 2008TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year earnings. TEP paid dividends to UNS Energy of $30 million in 2012; no dividends were paid from current year earnings. UniSource Energy contributed capital to TEP of $15in 2011; and $60 million were paid in 2010 and $30 million in 2009.
UNS Gas and UNS Electric
The terms of the senior unsecured note agreements entered into by both UNS Gas and UNS Electric contain dividend restrictions. See Note 6. In April 2010, UNS Gas paid dividends of $10 million to UES, UES then paid dividends of $10 million to UniSource Energy. UES did not pay any dividends to UniSource Energy in 2009 or 2008.
UES made capital contributions to UNS Electric of less than $0.5 million in 2008.
Millennium and UED
Millennium paid dividends of $8 million to UniSource Energy in 2010, $3 million in 2009, and $25 million in 2008, all of which represented return of capital distributions.
UED paid dividends to UniSource Energy of $9 million in February 2010, $4 million of which represented return of capital distributions; $30 million in 2009 which represented a return of capital distribution; and $0.5 million in 2008. Millennium and UED have no dividend restrictions.
In December 2008, UniSource Energy contributed $59 million in capital to UED by canceling an intercompany promissory note in the amount of $59 million.
2010. K-138
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)UNS Energy did not contribute capital to TEP in 2012 but made capital contributions of $30 million in 2011 and $15 million in 2010.
NOTE 8. INCOME TAXES A reconciliation of the federal statutory income tax rate to each company’s effective income tax rate follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Federal Income Tax Expense at Statutory Rate | | $ | 66 | | | $ | 59 | | | $ | 11 | | | $ | 58 | | | $ | 51 | | | $ | 5 | | | State Income Tax Expense, Net of Federal Benefit | | | 9 | | | | 7 | | | | 1 | | | | 8 | | | | 6 | | | | 1 | | | Deferred Tax Asset Valuation Allowance | | | 8 | | | | — | | | | — | | | | — | | | | — | | | | — | | | Deferred Tax Asset Write-Off Related to Unregulated Investment | | | 3 | | | | — | | | | — | | | | — | | | | — | | | | — | | | Depreciation Differences (Flow Through Basis) | | | — | | | | 1 | | | | 2 | | | | — | | | | 1 | | | | 2 | | | San Juan Generating Station Environmental Penalties | | | — | | | | — | | | | 3 | | | | — | | | | — | | | | 3 | | | Domestic Production Deduction | | | (3 | ) | | | (1 | ) | | | — | | | | (3 | ) | | | (1 | ) | | | — | | | Federal/State Tax Credits | | | (2 | ) | | | (1 | ) | | | (3 | ) | | | (2 | ) | | | (1 | ) | | | (3 | ) | | Other | | | (3 | ) | | | (1 | ) | | | 3 | | | | — | | | | (1 | ) | | | 3 | | | | | | | | | | | | | | | | | | | | | | Total Federal and State Income Tax Expense | | $ | 78 | | | $ | 64 | | | $ | 17 | | | $ | 61 | | | $ | 55 | | | $ | 11 | | | | | | | | | | | | | | | | | | | | | | | Effective Tax Rate | | | 41 | % | | | 38 | % | | | 55 | % | | | 36 | % | | | 38 | % | | | 71 | % | | | | | | | | | | | | | | | | | | | | |
In 2008, it was determined that the environmental penalties at San Juan Generating Station would not be deductible for income tax purposes. As a result, an additional $3 million of tax expense was recognized in 2008 for penalties incurred in the current and prior years.
In 2010, UniSource Energy recorded a $3 million out-of-period income tax expense. The out-of-period expense related to the write-off of a previously recorded deferred tax asset associated with the excess of tax over book basis difference in a consolidated unregulated investment. Management concluded that this out-of-period adjustment was not material to the current and prior period financial statements.
Income tax expense included in the income statements consists of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Current Tax Expense (Benefit) | | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | $ | 34 | | | $ | 5 | | | $ | (17 | ) | | $ | 28 | | | $ | 7 | | | $ | (12 | ) | | State | | | 7 | | | | — | | | | (2 | ) | | | 7 | | | | 1 | | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | Total | | | 41 | | | | 5 | | | | (19 | ) | | | 35 | | | | 8 | | | | (13 | ) | | | | | | | | | | | | | | | | | | | | | | Deferred Tax Expense (Benefit) | | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | | 33 | | | | 48 | | | | 34 | | | | 24 | | | | 38 | | | | 23 | | | Federal Investment Tax Credits | | | (1 | ) | | | — | | | | — | | | | (1 | ) | | | — | | | | — | | | State | | | 5 | | | | 11 | | | | 2 | | | | 3 | | | | 9 | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | Total | | | 37 | | | | 59 | | | | 36 | | | | 26 | | | | 47 | | | | 24 | | | | | | | | | | | | | | | | | | | | | | Total Federal and State Income Tax Expense | | $ | 78 | | | $ | 64 | | | $ | 17 | | | $ | 61 | | | $ | 55 | | | $ | 11 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Federal Income Tax Expense at Statutory Rate | | $ | 51 | | | $ | 62 | | | $ | 66 | | | $ | 37 | | | $ | 48 | | | $ | 58 | | State Income Tax Expense, Net of Federal Benefit | | | 7 | | | | 8 | | | | 9 | | | | 5 | | | | 6 | | | | 8 | | Deferred Tax Asset Valuation Allowance | | | — | | | | — | | | | 8 | | | | — | | | | — | | | | — | | Deferred Tax Asset Write-off Related to Unregulated Investment | | | — | | | | — | | | | 3 | | | | — | | | | — | | | | — | | AFUDC Equity | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | Domestic Production Deduction | | | — | | | | — | | | | (3 | ) | | | — | | | | — | | | | (3 | ) | Federal/State Tax Credits | | | (1 | ) | | | (3 | ) | | | (2 | ) | | | (1 | ) | | | (2 | ) | | | (2 | ) | Other | | | — | | | | 1 | | | | (3 | ) | | | (1 | ) | | | 1 | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Federal and State Income Tax Expense | | $ | 56 | | | $ | 67 | | | $ | 77 | | | $ | 39 | | | $ | 52 | | | $ | 60 | | | | | | | | | | | | | | | | | | | | | | | | | | | Effective Tax Rate | | | 38 | % | | | 38 | % | | | 41 | % | | | 37 | % | | | 38 | % | | | 36 | % | | | In 2010, UNS Energy recorded a $3 million out-of-period income tax expense. The out-of-period expense related to the write-off of a previously recorded deferred tax asset associated with the excess of tax over book basis difference in a consolidated unregulated investment. Management concluded that this out-of-period adjustment was not material to current and prior period financial statements. | | | | | | | | | | Income tax expense included in the income statements consists of the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Current Tax Expense (Benefit) | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | $ | (2 | ) | | $ | (7 | ) | | $ | 34 | | | $ | (4 | ) | | $ | (5 | ) | | $ | 28 | | State | | | (2 | ) | | | (2 | ) | | | 7 | | | | (2 | ) | | | (2 | ) | | | 7 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | (4 | ) | | | (9 | ) | | | 41 | | | | (6 | ) | | | (7 | ) | | | 35 | | | | | | | | | | | | | | | | | | | | | | | | | | | Deferred Tax Expense (Benefit) | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | | 51 | | | | 64 | | | | 32 | | | | 38 | | | | 50 | | | | 24 | | Federal Investment Tax Credits | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | (1 | ) | | | (1 | ) | State | | | 9 | | | | 13 | | | | 5 | | | | 7 | | | | 10 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | 60 | | | | 76 | | | | 36 | | | | 45 | | | | 59 | | | | 25 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Federal and State Income Tax Expense | | $ | 56 | | | $ | 67 | | | $ | 77 | | | $ | 39 | | | $ | 52 | | | $ | 60 | | | | | | | | | | | | | | | | | | | | | | | | | | |
K-139
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)The significant components of deferred income tax assets and liabilities consist of the following: | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | Gross Deferred Income Tax Assets | | | | | | | | | | | | | | | | | | Capital Lease Obligations | | $ | 192 | | | $ | 208 | | | $ | 192 | | | $ | 208 | | | Customer Advances and Contributions in Aid of Construction | | | 43 | | | | 43 | | | | 27 | | | | 26 | | | Alternative Minimum Tax Credit | | | 34 | | | | 43 | | | | 16 | | | | 28 | | | Accrued Postretirement Benefits | | | 24 | | | | 24 | | | | 24 | | | | 24 | | | Renewable Energy Credit Up-Front Incentive Payments | | | 14 | | | | — | | | | 11 | | | | — | | | Emission Allowance Inventory | | | 11 | | | | 13 | | | | 11 | | | | 12 | | | Unregulated Investment Losses | | | 9 | | | | 8 | | | | — | | | | — | | | Other | | | 29 | | | | 27 | | | | 26 | | | | 25 | | | | | | | | | | | | | | | | Gross Deferred Income Tax Assets | | | 356 | | | | 366 | | | | 307 | | | | 323 | | | | | | | | | | | | | | | | Deferred Tax Assets Valuation Allowance | | | (8 | ) | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gross Deferred Income Tax Liabilities | | | | | | | | | | | | | | | | | | Plant — Net | | | (463 | ) | | | (442 | ) | | | (411 | ) | | | (397 | ) | | Capital Lease Assets — Net | | | (48 | ) | | | (58 | ) | | | (48 | ) | | | (58 | ) | | Regulatory Asset — Income Taxes Recoverable Through Future Revenues | | | (7 | ) | | | (7 | ) | | | (7 | ) | | | (7 | ) | | Pensions | | | (12 | ) | | | (10 | ) | | | (13 | ) | | | (11 | ) | | Deferred Lease Payment | | | (5 | ) | | | (5 | ) | | | (5 | ) | | | (5 | ) | | Other | | | (22 | ) | | | (19 | ) | | | (13 | ) | | | (11 | ) | | | | | | | | | | | | | | | Gross Deferred Income Tax Liabilities | | | (557 | ) | | | (541 | ) | | | (497 | ) | | | (489 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Deferred Income Tax Liabilities | | $ | (209 | ) | | $ | (175 | ) | | $ | (190 | ) | | $ | (166 | ) | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Gross Deferred Income Tax Assets | | | | | | | | | | | | | | | | | Capital Lease Obligations | | $ | 141 | | | $ | 169 | | | $ | 141 | | | $ | 169 | | Net Operating Loss Carryforwards | | | 72 | | | | 81 | | | | 85 | | | | 76 | | Customer Advances and Contributions in Aid of Construction | | | 34 | | | | 30 | | | | 19 | | | | 17 | | Alternative Minimum Tax Credit | | | 43 | | | | 43 | | | | 24 | | | | 25 | | Accrued Postretirement Benefits | | | 23 | | | | 23 | | | | 23 | | | | 23 | | Renewable Energy Credit Up-Front Incentive Payments | | | 26 | | | | 22 | | | | 20 | | | | 18 | | Emission Allowance Inventory | | | 10 | | | | 10 | | | | 10 | | | | 10 | | Unregulated Investment Losses | | | 9 | | | | 9 | | | | — | | | | — | | Other | | | 44 | | | | 34 | | | | 43 | | | | 29 | | | | | | | | | | | | | | | | | | | Gross Deferred Income Tax Assets | | | 402 | | | | 421 | | | | 365 | | | | 367 | | | | | | | | | | | | | | | | | | | Deferred Tax Assets Valuation Allowance | | | (7 | ) | | | (7 | ) | | | — | | | | — | | | | | | | | | | | | | | | | | | | Gross Deferred Income Tax Liabilities | | | | | | | | | | | | | | | | | Plant – Net | | | (648 | ) | | | (585 | ) | | | (571 | ) | | | (516 | ) | Capital Lease Assets – Net | | | (34 | ) | | | (41 | ) | | | (34 | ) | | | (41 | ) | Pensions | | | (23 | ) | | | (17 | ) | | | (24 | ) | | | (18 | ) | PPFAC | | | (6 | ) | | | (19 | ) | | | (3 | ) | | | (16 | ) | Other | | | (15 | ) | | | (29 | ) | | | (15 | ) | | | (17 | ) | | | | | | | | | | | | | | | | | | Gross Deferred Income Tax Liabilities | | | (726 | ) | | | (691 | ) | | | (647 | ) | | | (608 | ) | | | | | | | | | | | | | | | | | | Net Deferred Income Tax Liabilities | | $ | (331 | ) | | $ | (277 | ) | | $ | (282 | ) | | $ | (241 | ) | | | | | | | | | | | | | | | | | |
K-140
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The balance sheets display the net deferred income tax liability on the balance sheet is as follows: | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | | Deferred Income Taxes — Current Assets | | $ | 35 | | | $ | 52 | | | $ | 36 | | | $ | 51 | | | Deferred Income Taxes — Noncurrent Liabilities | | | (244 | ) | | | (227 | ) | | | (226 | ) | | | (217 | ) | | | | | | | | | | | | | | | Net Deferred Income Tax Liability | | $ | (209 | ) | | $ | (175 | ) | | $ | (190 | ) | | $ | (166 | ) | | | | | | | | | | | | | | |
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Deferred Income Taxes – Current Assets | | $ | 34 | | | $ | 23 | | | $ | 37 | | | $ | 22 | | Deferred Income Taxes – Noncurrent Liabilities | | | (365 | ) | | | (300 | ) | | | (319 | ) | | | (263 | ) | | | | | | | | | | | | | | | | | | Net Deferred Income Tax Liability | | $ | (331 | ) | | $ | (277 | ) | | $ | (282 | ) | | $ | (241 | ) | | | | | | | | | | | | | | | | | |
The $9 million unregulated investment loss deferred tax asset includes $8$7 million of capital loss whichat December 31, 2012, and December 31, 2011. The deferred tax asset can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UniSourceUNS Energy recorded an $8a $7 million valuation allowance against the deferred tax asset as of December 31, 2010.2012, and December 31, 2011. Management believes that based on its historical pattern of taxable income, UniSourceUNS Energy will produce sufficient income in the future to realize all other deferred income tax assets. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Income Tax Position As of December 31, 2012, UNS Energy and TEP had the following carryforward amounts: | | | | | | | | | | | | | | | | UNS Energy | | TEP | | | | Amount | | | Expiring Year | | Amount | | | Expiring Year | | | | -Amounts in Millions of Dollars- | Capital Loss | | $ | 8 | | | 2015 | | $ | — | | | — | Federal Net Operating Loss | | | 202 | | | 2031-32 | | | 233 | | | 2031-32 | State Net Operating Loss | | | 14 | | | 2032 | | | 57 | | | 2016-32 | State Credits | | | 2 | | | 2016-17 | | | 4 | | | 2016-17 | AMT Credit | | | 43 | | | None | | | 24 | | | None |
State Tax Rate Change In the first quarter of 2011, the Arizona legislature passed a bill reducing the corporate income tax rate from the current rate of 6.968%. The tax rate reduction will be phased in beginning in 2014, with a reduction of approximately 0.5% per year until the income tax rate reaches 4.9% for 2017 and later years. As a result of these tax rate reductions, we reduced the net deferred tax liabilities at UNS Energy and TEP by $13 million, offset entirely by adjustments to regulatory assets and liabilities. The income tax rate change did not have an impact on UNS Energy’s and TEP’s effective tax rate for 2012 or 2011. Excess Tax Benefit Realized from Share-Based Compensation Plans UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2012, UNS Energy had $2 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $202 million are used. Uncertain Tax Positions Accounting guidance requires usIn accordance with accounting rules related to uncertain tax positions, we are required to determine whether it is “moremore likely than not”not that we will sustain an income tax position under examination. Each income tax position is measured to determine the amount of benefit to recognize in the financial statements. The following table shows the changes in unrecognized tax benefits of UniSourceUNS Energy and TEP: | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | | Unrecognized Tax Benefits, beginning of year | | $ | 19 | | | $ | 20 | | | $ | 19 | | | $ | 20 | | | Additions based on tax positions taken in the current year | | | 11 | | | | 1 | | | | 8 | | | | 1 | | | Reductions based on settlements with tax authorities | | | — | | | | (1 | ) | | | — | | | | (1 | ) | | Additions based on tax positions taken in the prior year | | | 16 | | | | — | | | | 13 | | | | — | | | Reductions based on tax positions taken in the prior year | | | (4 | ) | | | (1 | ) | | | (4 | ) | | | (1 | ) | | Reductions based on expiration of the statute of limitations | | | (1 | ) | | | — | | | | (1 | ) | | | — | | | | | | | | | | | | | | | | Unrecognized Tax Benefits, end of year | | $ | 41 | | | $ | 19 | | | $ | 35 | | | $ | 19 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | December 31, | | | December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Unrecognized Tax Benefits, Beginning of Year | | $ | 29 | | | $ | 41 | | | $ | 24 | | | $ | 35 | | Additions Based on Tax Positions Taken in the Current Year | | | 5 | | | | 9 | | | | 3 | | | | 8 | | Reductions Based on Settlements with Tax Authorities | | | (4 | ) | | | (22 | ) | | | (4 | ) | | | (19 | ) | Additions Based on Tax Positions Taken in the Prior Year | | | — | | | | 1 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Unrecognized Tax Benefits, End of Year | | $ | 30 | | | $ | 29 | | | $ | 23 | | | $ | 24 | | | | | | | | | | | | | | | | | | |
Unrecognized tax benefits which,of $1 million, if recognized, would reduce the effective tax rate totaled $1 million at December 31, 20102012, and 2009December 31, 2011, for both UniSourceUNS Energy and TEP. As a result of a change in accounting method filed with the IRS in February 2011 the balance of unrecognized tax benefits will decrease in 2011 by $13 million for UniSource Energy and $10 million for TEP. The remaining balance in unrecognized tax benefits could change in the next twelve12 months as a result of the ongoing IRS audits, but we are unable to determine the amount of the change cannot be determined. UniSourcechange.UNS Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements. In 2010, UniSourceUNS Energy and TEP recorded nodid not recognize a reduction to interest expense;expense in 2009,2012. A reduction to Other Interest Expense of $1 million of interest expense was recognized.recorded in 2011. The balance of interest payable at December 31, 2010 and December 31, 2009 for UniSourceUNS Energy and TEP was $2 million. Penalties$1 million at both December 31, 2012 and December 31, 2011. We have no penalties accrued are immaterial. UniSourcein the years presented.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) UNS Energy and TEP have been audited by the IRS through tax year 20062008 and are currently under audit by the IRS for 2008. Tax year 2007 has not yet been selected for audit.2009 and 2010. We are unable to determine when the 2008 auditaudits will be completed. UniSourceUNS Energy and TEP are not currently under audit by any state tax agencies. K-141
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
NOTE 9. EMPLOYEE BENEFIT PLANS TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees. Benefits are based on years of service and the employee’s average compensation. TEP, UNS Gas and UNS Electric fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service regulations.
We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in rates. In December 2008, as a result of the 2008 TEP Rate Order, TEP reapplied regulatory accounting to its generation operations. Accordingly, TEP reclassified pension amounts related to its generation operations, previously recognized in AOCI, to a regulatory asset.
Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by Internal Revenue Service benefit or compensation limitations. Changes in Supplemental Executive Retirement Plan (SERP) benefit obligations are recognized as a component of accumulated other comprehensive income (AOCI).
The Pension Protection Act of 2006 (The Pension Act) established minimum funding targets for pension plans beginning in 2008.plans. A plan’s funding target is the present value of all benefits accrued or earned as of the beginning of the plan year. While the annual targets are not legally required, benefit payment options are limited for plans that do not meet the targets, and a funding deficiency notice must be sent to all plan participants. TEP, UNS Gas and UNS ElectricOur plans are in compliance with The Pension Act. In 2010, UniSource Energy made pension plan contributions of $22 million, including $20 million in contributions by TEP. In 2009, UniSource Energy’s plan contributions were $25 million, including $23 million contributed by TEP. In 2011, UniSource2013, UNS Energy expects to contribute $23$24 million to the pension plans, including $20$22 million in contributions by TEP.
TEP Salaried Employees Pension Plan (Salaried Plan) Amendment
In August 2009, TEP amended one of its defined benefit pension plans to limit early retirement benefits for TEP non-union employees hired after June 1, 2009 and to modify disability retirement and survivor benefits for all TEP non-union employees. As a result of the pension plan amendment, the pension plan assets and liabilities were remeasured as of August 31, 2009. In performing the remeasurement, management reviewed the key assumptions used to measure the pension plan’s benefit obligation at December 31, 2008 and to calculate pension expense for 2009. TEP determined that the discount rate should be increased to 6.40% from the 6.30% rate assumed at December 31, 2008. The revised discount rate was determined using the same methodology as was employed at year-end 2008. All other key assumptions, including the expected rate of return on assets, remained unchanged from December 31, 2008.
The amendment reduced the 2009 annual expense for the Salaried Plan from $9 million to $8 million.
K-142
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
TEP Union Pension Plan Amendment
In December 2009, TEP amended its defined benefit pension plan for union employees to limit early retirement benefits for TEP union employees hired on or after January 1, 2011; modify disability retirement and survivor benefits for TEP union employees; and modify maximum credited service beginning in 2009. Because the amendment was applied in December 2009, there was no additional remeasurement.
OTHER POSTRETIREMENTRETIREE BENEFIT PLANS TEP provides limited health care and life insurance benefits for retirees. All regularActive TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Gas and UNS Electric provide postretirementretiree medical benefits for current retirees. UNS Gas and UNS Electric active employees doare not participate in the postretirementeligible for retiree medical plan. In the 2008 benefits.TEP Rate Order, the ACC authorized accrual basis recovery of other postretirement benefit plan costs based on a commitment to fund the plan. TEP establishedhas a Voluntary Employee Beneficiary Association (VEBA) trust in 2009 to fund its other postretirementretiree benefit plan related to classified employees. TEP contributed $3 million in 2012, and began funding$2 million in each of 2011 and 2010 to the plan. TEP, UNS Gas and UNS Electric nowVEBA. We record changes in their other postretirementretiree obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in rates. Amounts previously recordedthe rates charged to retail customers. Other retiree benefits for unclassified employees are funded on a year-by-year basis. TEP’s retiree medical plan was amended effective December 31, 2011, to increase the participant contributions for unclassified employees who retire on or after July 1, 2012. TEP’s retiree medical plan was amended in AOCI were reclassified2012, to a regulatory asset in 2008. increase the participant contributions for classified employees who retire after February 1, 2014.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The pension and other postretirementretiree benefit related amounts (excluding tax balances) included inon the UniSourceUNS Energy balance sheet are: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement | | | | | Pension Benefits | | | Benefits | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | Regulatory Pension Asset included in Other Regulatory Assets | | $ | 86 | | | $ | 75 | | | $ | 8 | | | $ | 9 | | | Accrued Benefit Liability included in Accrued Employee Expenses | | | — | | | | — | | | | (4 | ) | | | (4 | ) | | Accrued Benefit Liability included in Pension and Other Postretirement Benefits | | | (63 | ) | | | (58 | ) | | | (65 | ) | | | (65 | ) | | Accumulated Other Comprehensive Loss | | | 4 | | | | 3 | | | | — | | | | — | | | | | | | | | | | | | | | | Net Amount Recognized | | $ | 27 | | | $ | 20 | | | $ | (61 | ) | | $ | (60 | ) | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Retiree
Benefits | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Regulatory Pension Asset Included in Other Regulatory Assets | | $ | 129 | | | $ | 106 | | | $ | 10 | | | $ | 8 | | Accrued Benefit Liability Included in Accrued Employee Expenses | | | (1 | ) | | | (1 | ) | | | (2 | ) | | | (2 | ) | Accrued Benefit Liability Included in Pension and Other Retiree Benefits | | | (90 | ) | | | (72 | ) | | | (69 | ) | | | (66 | ) | Accumulated Other Comprehensive Loss (related to SERP) | | | 4 | | | | 2 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Net Amount Recognized | | $ | 42 | | | $ | 35 | | | $ | (61 | ) | | $ | (60 | ) | | | | | | | | | | | | | | | | | |
The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $6 million and $5$9 million at December 31, 20102012, and 2009, respectively, and$8 million at December 31, 2011. The table also includes a postretirementretiree benefit liability of $1 million for UNS Gas and UNS Electric for each period presented. The balance remaining in AOCI of $4 million relates to the TEP SERP.
K-143
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
OBLIGATIONS AND FUNDED STATUS We measured the actuarial present values of all pension benefit obligations and other postretirementretiree benefit plans at December 31, 20102012, and 2009.December 31, 2011. The tablestable below include TEP,includes TEP’s, UNS GasGas’, and UNS Electric’s plans. The change in projected benefit obligation and plan assets and reconciliation of the funded status are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement | | | | | Pension Benefits | | | Benefits | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | Change in Projected Benefit Obligation | | | | | | | | | | | | | | | | | | Benefit Obligation at Beginning of Year | | $ | 242 | | | $ | 230 | | | $ | 71 | | | $ | 67 | | | Actuarial (Gain) Loss | | | 28 | | | | — | | | | (1 | ) | | | 1 | | | Interest Cost | | | 15 | | | | 14 | | | | 4 | | | | 4 | | | Service Cost | | | 8 | | | | 7 | | | | 3 | | | | 2 | | | Amendments | | | — | | | | (1 | ) | | | — | | | | — | | | Other | | | 1 | | | | — | | | | — | | | | — | | | Benefits Paid | | | (11 | ) | | | (8 | ) | | | (4 | ) | | | (3 | ) | | | | | | | | | | | | | | | Projected Benefit Obligation at End of Year | | | 283 | | | | 242 | | | | 73 | | | | 71 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Change in Plan Assets | | | | | | | | | | | | | | | | | | Fair Value of Plan Assets at Beginning of Year | | | 184 | | | | 135 | | | | 2 | | | | — | | | Actual (Loss) Return on Plan Assets | | | 25 | | | | 32 | | | | — | | | | — | | | Benefits Paid | | | (11 | ) | | | (8 | ) | | | (4 | ) | | | (3 | ) | | Employer Contributions | | | 22 | | | | 25 | | | | 6 | | | | 5 | | | | | | | | | | | | | | | | Fair Value of Plan Assets at End of Year | | | 220 | | | | 184 | | | | 4 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Funded Status at End of Year | | $ | (63 | ) | | $ | (58 | ) | | $ | (69 | ) | | $ | (69 | ) | | | | | | | | | | | | | | |
In March 2010 the Patient Protection and Affordable Care Act (PPACA) was signed into law. One provision of PPACA imposes a 40% excise tax on plans in which the aggregate value of employer-sponsored health insurance exceeds a threshold amount (so-called “Cadillac Plans”) starting in 2018. There are currently many uncertainties surrounding implementation and calculation of the excise tax. Our best estimate of the potential impact resulted in an increase in the postretirement benefit obligation of $2.4 million at December 31, 2010. It is currently unclear whether the excise tax will be deductible for income tax purposes. Our calculation assumes the excise tax will be deductible. An assumption of non-deductibility would increase the postretirement benefit obligation and the corresponding regulatory asset by approximately $1 million.
| | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Retiree
Benefits | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Change in Projected Benefit Obligation | | | | | | | | | | | | | | | | | Benefit Obligation at Beginning of Year | | $ | 319 | | | $ | 283 | | | $ | 73 | | | $ | 73 | | Actuarial (Gain) Loss | | | 51 | | | | 22 | | | | 3 | | | | — | | Interest Cost | | | 15 | | | | 16 | | | | 3 | | | | 4 | | Service Cost | | | 10 | | | | 10 | | | | 3 | | | | 3 | | Amendments | | | — | | | | — | | | | — | | | | (2 | ) | Benefits Paid | | | (15 | ) | | | (12 | ) | | | (4 | ) | | | (5 | ) | | | | | | | | | | | | | | | | | | Projected Benefit Obligation at End of Year | | | 380 | | | | 319 | | | | 78 | | | | 73 | | | | | | | | | | | | | | | | | | | Change in Plan Assets | | | | | | | | | | | | | | | | | Fair Value of Plan Assets at Beginning of Year | | | 245 | | | | 220 | | | | 5 | | | | 4 | | Actual Return on Plan Assets | | | 36 | | | | 14 | | | | 1 | | | | — | | Benefits Paid | | | (15 | ) | | | (12 | ) | | | (4 | ) | | | (5 | ) | Employer Contributions(1) | | | 23 | | | | 23 | | | | 5 | | | | 6 | | | | | | | | | | | | | | | | | | | Fair Value of Plan Assets at End of Year | | | 289 | | | | 245 | | | | 7 | | | | 5 | | | | | | | | | | | | | | | | | | | Funded Status at End of Year | | $ | (91 | ) | | $ | (74 | ) | | $ | (71 | ) | | $ | (68 | ) | | | | | | | | | | | | | | | | | |
| (1) | TEP made $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012 and 2011. |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The table above includes pension benefit obligationsthe following for UNS Gas and UNS ElectricElectric: Pension benefit obligations of approximately $6 million and $5$23 million at December 31, 20102012, and 2009, respectively, plan assets of $9 million and $6$18 million at December 31, 20102011; Plan assets of $14 million at December 31, 2012, and 2009, respectively,$10 million at December 31, 2011; and a postretirement A retiree benefit liabilityobligation of less than $1 million for UNS Gasat December 31, 2012, and UNS Electric, for each period presented.at December 31, 2011. K-144
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The following table provides the components of UniSourceUNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of December 31, 2010 and 2009: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement | | | | | Pension Benefits | | | Benefits | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | Net Loss | | $ | 89 | | | $ | 77 | | | $ | 11 | | | $ | 13 | | | Prior Service Cost (Benefit) | | | 1 | | | | 1 | | | | (3 | ) | | | (4 | ) |
the dates presented: | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Retiree
Benefits | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Net Loss | | $ | 133 | | | $ | 108 | | | $ | 13 | | | $ | 11 | | Prior Service Cost (Benefit) | | | 1 | | | | 1 | | | | (3 | ) | | | (3 | ) |
Information for pension plans with Accumulated Benefit Obligations in excess of pension plan assets follows: | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | Projected Benefit Obligation at End of Year | | $ | 283 | | | $ | 242 | | | Accumulated Benefit Obligation at End of Year | | | 243 | | | | 210 | | | Fair Value of Plan Assets at End of Year | | | 220 | | | | 184 | |
| | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Projected Benefit Obligation at End of Year | | $ | 380 | | | $ | 319 | | Accumulated Benefit Obligation at End of Year | | | 334 | | | | 281 | | Fair Value of Plan Assets at End of Year | | | 289 | | | | 245 | |
At December 31, 2010,2012, and December 31, 2009,2011, all UniSourceUNS Energy defined benefit pension plans had accumulated benefit obligations in excess of pension plan assets. The components of net periodic benefit costs are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement | | | | | Pension Benefits | | | Benefits | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Service Cost | | $ | 8 | | | $ | 7 | | | $ | 7 | | | $ | 3 | | | $ | 2 | | | $ | 2 | | | Interest Cost | | | 15 | | | | 14 | | | | 14 | | | | 4 | | | | 4 | | | | 4 | | | Expected Return on Plan Assets | | | (14 | ) | | | (11 | ) | | | (16 | ) | | | — | | | | — | | | | — | | | Prior Service Cost Amortization | | | — | | | | 1 | | | | 2 | | | | (2 | ) | | | (2 | ) | | | (2 | ) | | Recognized Actuarial Loss | | | 5 | | | | 7 | | | | — | | | | — | | | | 1 | | | | 1 | | | | | | | | | | | | | | | | | | | | | | Net Periodic Benefit Cost | | $ | 14 | | | $ | 18 | | | $ | 7 | | | $ | 5 | | | $ | 5 | | | $ | 5 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Retiree
Benefits | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Service Cost | | $ | 10 | | | $ | 10 | | | $ | 8 | | | $ | 3 | | | $ | 3 | | | $ | 3 | | Interest Cost | | | 16 | | | | 15 | | | | 15 | | | | 3 | | | | 4 | | | | 4 | | Expected Return on Plan Assets | | | (17 | ) | | | (16 | ) | | | (14 | ) | | | — | | | | — | | | | — | | Prior Service Cost Amortization | | | — | | | | — | | | | — | | | | — | | | | (1 | ) | | | (2 | ) | Recognized Actuarial Loss | | | 7 | | | | 6 | | | | 5 | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Periodic Benefit Cost | | $ | 16 | | | $ | 15 | | | $ | 14 | | | $ | 6 | | | $ | 6 | | | $ | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | |
Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in Other Operations and Maintenance expense. current year earnings. K-145
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS �� (continued) (Continued)The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | | | 2010 | | | 2009 | | | 2008 | | | | | Regulatory | | | | | | | Regulatory | | | | | | | Regulatory | | | | | | | | Asset | | | AOCI | | | Asset | | | AOCI | | | Asset | | | AOCI | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current Year Actuarial (Gain) Loss | | $ | 16 | | | $ | 1 | | | $ | (21 | ) | | $ | — | | | $ | 85 | | | $ | 1 | | | Amortization of Actuarial Gain (Loss) | | | (5 | ) | | | — | | | | (7 | ) | | | — | | | | — | | | | — | | | Prior Service (Cost) Amortization | | | — | | | | — | | | | — | | | | — | | | | (2 | ) | | | — | | | Plan Amendments | | | — | | | | — | | | | (1 | ) | | | — | | | | (2 | ) | | | — | | | Reclassification from AOCI to Regulatory Asset | | | — | | | | — | | | | — | | | | — | | | | 8 | | | | (8 | ) | | | | | | | | | | | | | | | | | | | | | Total Recognized | | $ | 11 | | | $ | 1 | | | $ | (29 | ) | | $ | — | | | $ | 89 | | | $ | (7 | ) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Other Postretirement Benefits | | | | | 2010 | | | 2009 | | | 2008 | | | | | | | | Regulatory | | | Regulatory | | | Regulatory | | | 2008 | | | | | Asset | | | Asset | | | Asset | | | AOCI | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | | Current Year Actuarial (Gain) Loss | | $ | (1 | ) | | $ | 1 | | | $ | — | | | $ | — | | | Amortization of Actuarial Gain (Loss) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | — | | | Prior Service (Cost) Amortization | | | 2 | | | | 2 | | | | 2 | | | | — | | | Reclassification from AOCI to Regulatory Asset | | | — | | | | — | | | | 6 | | | | (6 | ) | | | | | | | | | | | | | | | Total Recognized | | $ | — | | | $ | 2 | | | $ | 7 | | | $ | (6 | ) | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | | | 2012 | | | 2011 | | | 2010 | | | | | Regulatory
Asset | | | AOCI | | | Regulatory
Asset | | | AOCI | | | Regulatory
Asset | | | AOCI | | | | | -Millions of Dollars- | | Current Year Actuarial (Gain) Loss | | $ | 30 | | | $ | 1 | | | $ | 25 | | | $ | (2 | ) | | $ | 16 | | | $ | 1 | | Amortization of Actuarial Gain (Loss) | | | (7 | ) | | | — | | | | (5 | ) | | | — | | | | (5 | ) | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Recognized (Gain) Loss | | $ | 23 | | | $ | 1 | | | $ | 20 | | | $ | (2 | ) | | $ | 11 | | | $ | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Other Retiree Benefits | | | | | 2012 | | | 2011 | | | 2010 | | | | | Regulatory
Asset | | | Regulatory
Asset | | | Regulatory
Asset | | | | | -Millions of Dollars- | | Prior Service Cost (Credit) | | $ | — | | | $ | (2 | ) | | $ | — | | Current Year Actuarial (Gain) Loss | | | 2 | | | | — | | | | (1 | ) | Amortization of Actuarial (Gain) Loss | | | — | | | | — | | | | (1 | ) | Amortization of Prior Service (Cost) Credit | | | — | | | | 1 | | | | 2 | | | | | | | | | | | | | | | Total Recognized (Gain) Loss | | $ | 2 | | | $ | (1 | ) | | $ | — | | | | | | | | | | | | | | |
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 $6$9 million estimated net loss from other regulatory assets and less than $1$0.5 million prior service cost from other regulatory assets or AOCI into net periodic benefit cost in 2011.2013. The estimated net loss and prior service benefit for the defined benefit postretirement plans that will be amortized from other regulatory assets into net periodic benefit cost in 2011 are2013 is less than $1 million andmillion. The estimated prior service benefit that will be amortized is less than $1 million, respectively. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Postretirement | | | Weighted-Average Assumptions Used to Determine | | Pension Benefits | | | Benefits | | | Benefit Obligations as of the Measurement Date | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | Discount Rate | | | 5.5 – 5.6 | % | | | 6.3 | % | | | 5.2 | % | | | 6.0 | % | | Rate of Compensation Increase | | | 3.0 – 5.0 | % | | | 3.0 – 5.0 | % | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | Weighted-Average Assumptions Used | | | | | | | | | | | | | | Other Postretirement | | | to Determine Net Periodic Benefit Cost | | Pension Benefits | | | Benefits | | | for Years Ended December 31 | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2008 & 2009 | | | Discount Rate | | | 6.3 | % | | | 6.3 | % | | | 6.6 – 6.8 | % | | | 6.0 | % | | | 6.5 | % | | Rate of Compensation Increase | | | 3.0 – 5.0 | % | | | 3.0 – 5.0 | % | | | 3.0 – 5.0 | % | | | N/A | | | | N/A | | | Expected Return on Plan Assets | | | 7.5 | % | | | 8.0 | % | | | 7.75 – 8.3 | % | | | 5.6 | % | | | N/A | |
| | | | | | | | | | | | | | | | Pension Benefits | | Other Retiree
Benefits | | | | | 2012 | | 2011 | | 2012 | | | 2011 | | Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | | | | | | | | | | | | | Discount Rate | | 4.1%-4.3% | | 4.9%-5.0% | | | 3.8 | % | | | 4.7 | % | Rate of Compensation Increase | | 3.0% | | 3.0% | | | N/A | | | | N/A | |
K-146
| | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | Other Retiree Benefits | | | | | 2012 | | 2011 | | 2010 | | 2012 | | | 2011 | | | 2010 | | Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31, | | | | | | | | | | | | | | | | | | | Discount Rate | | 4.9% - 5.0% | | 5.5% - 5.6% | | 6.3% | | | 4.7 | % | | | 5.2 | % | | | 6.0 | % | Rate of Compensation Increase | | 3.0% | | 3.0% - 5.0% | | 3.0% - 5.0% | | | N/A | | | | N/A | | | | N/A | | Expected Return on Plan Assets | | 7.0% | | 7.0% | | 7.5% | | | 7.0 | % | | | 5.1 | % | | | 5.6 | % |
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
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. TEP, UNS Gas and UNS ElectricWe use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | Assumed Health Care Cost Trend Rates | | | | | | | | | | Health Care Cost Trend Rate Assumed for Next Year | | | 7.9 | % | | | 7.9 | % | | Ultimate Health Care Cost Trend Rate Assumed | | | 4.5 | % | | | 4.5 | % | | Year that the Rate Reaches the Ultimate Trend Rate | | | 2027 | | | | 2027 | |
The assumed health care cost trend rates follow: | | | | | | | | | | | | December 31, | | | | | 2012 | | | 2011 | | Health Care Cost Trend Rate Assumed for Next Year | | | 6.9 | % | | | 6.9 | % | Ultimate Health Care Cost Trend Rate Assumed | | | 4.5 | % | | | 4.5 | % | Year that the Rate Reaches the Ultimate Trend Rate | | | 2027 | | | | 2027 | |
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, 20102012, amounts: | | | | | | | | | | | | | One-Percentage- | | | One-Percentage- | | | | | Point Increase | | | Point Decrease | | | | | -Millions of Dollars- | | | Effect on Total of Service and Interest Cost Components | | $ | 1 | | | $ | (1 | ) | | Effect on Postretirement Benefit Obligation | | | 5 | | | | (5 | ) |
| | | | | | | | | | | | One-Percentage-
Point Increase | | | One-Percentage-
Point Decrease | | | | | -Millions of Dollars- | | Effect on Total Service and Interest Cost Components | | $ | 1 | | | $ | (1 | ) | Effect on Retiree Benefit Obligation | | | 6 | | | | (5 | ) |
PENSION PLAN AND OTHER POSTRETIREMENTRETIREE BENEFIT ASSETS TEP, UNS Gas and UNS ElectricWe calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Gas and UNS Electric | | | | | TEP Plan Assets | | | Plan Assets | | | | | December 31, | | | December 31, | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | Asset Category | | | | | | | | | | | | | | | | | | Equity Securities | | | 57 | % | | | 57 | % | | | 57 | % | | | 56 | % | | Fixed Income Securities | | | 34 | | | | 34 | | | | 32 | | | | 33 | | | Real Estate | | | 7 | | | | 7 | | | | 11 | | | | 11 | | | Other | | | 2 | | | | 2 | | | | — | | | | — | | | | | | | | | | | | | | | | | Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | TEP Plan Assets | | | UNS Gas and UNS Electric Plan
Assets | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | Asset Category | | | | | Equity Securities | | | 50 | % | | | 49 | % | | | 56 | % | | | 55 | % | Fixed Income Securities | | | 41 | | | | 42 | | | | 33 | | | | 34 | | Real Estate | | | 7 | | | | 7 | | | | 11 | | | | 11 | | Other | | | 2 | | | | 2 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | | | | | | | | | | | |
K-147
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy, as of December 31, 2010 and 2009: | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements of Pension Assets | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | | | | | | | | Significant | | | | | | | | | | | Quoted Prices | | | Other | | | Significant | | | | | | | | in Active | | | Observable | | | Unobservable | | | | | | | | Markets | | | Inputs | | | Inputs | | | | | | Asset Category | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | | | | | | | | | | | | | | | | | Cash Equivalents | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | | Equity Securities: | | | | | | | | | | | | | | | | | | U.S. Large Cap | | | — | | | | 63 | | | | — | | | | 63 | | | U.S. Small Cap | | | — | | | | 12 | | | | — | | | | 12 | | | Non-U.S. | | | — | | | | 51 | | | | — | | | | 51 | | | Fixed Income | | | — | | | | 75 | | | | — | | | | 75 | | | Real Estate | | | — | | | | 6 | | | | 10 | | | | 16 | | | Private Equity | | | — | | | | — | | | | 2 | | | | 2 | | | | | | | | | | | | | | | | | Total | | $ | 1 | | | $ | 207 | | | $ | 12 | | | $ | 220 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Fair Value Measurements of Pension Assets | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | | | | | | | | Significant | | | | | | | | | | | Quoted Prices | | | Other | | | Significant | | | | | | | | in Active | | | Observable | | | Unobservable | | | | | | | | Markets | | | Inputs | | | Inputs | | | | | | Asset Category | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | | | | | | | | | | | | | | | | | Cash Equivalents | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | | Equity Securities: | | | | | | | | | | | | | | | | | | U.S. Large Cap | | | — | | | | 53 | | | | — | | | | 53 | | | U.S. Small Cap | | | — | | | | 10 | | | | — | | | | 10 | | | Non-U.S. | | | — | | | | 42 | | | | — | | | | 42 | | | Fixed Income | | | — | | | | 63 | | | | — | | | | 63 | | | Real Estate | | | — | | | | 5 | | | | 8 | | | | 13 | | | Hedge Fund | | | — | | | | — | | | | 1 | | | | 1 | | | Private Equity | | | — | | | | — | | | | 1 | | | | 1 | | | | | | | | | | | | | | | | | Total | | $ | 1 | | | $ | 173 | | | $ | 10 | | | $ | 184 | | | | | | | | | | | | | | | |
hierarchy: | | | | | | | | | | | | | | | | | | | | Fair Value Measurements of Pension Assets
December 31, 2012 | | | | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total | | | | | - Millions of Dollars - | | Asset Category | | | | | | | | | | | | | | | | | Cash Equivalents | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | Equity Securities: | | | | | | | | | | | | | | | | | United States Large Cap | | | — | | | | 71 | | | | — | | | | 71 | | United States Small Cap | | | — | | | | 15 | | | | — | | | | 15 | | Non-United States | | | — | | | | 59 | | | | — | | | | 59 | | Fixed Income | | | — | | | | 116 | | | | — | | | | 116 | | Real Estate | | | — | | | | 8 | | | | 13 | | | | 21 | | Private Equity | | | — | | | | — | | | | 6 | | | | 6 | | | | | | | | | | | | | | | | | | | Total | | $ | 1 | | | $ | 269 | | | $ | 19 | | | $ | 289 | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements of Pension Assets
December 31, 2011 | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | | - Millions of Dollars - | | Asset Category | | | | | | | | | | | | | | | | | Cash Equivalents | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | Equity Securities: | | | | | | | | | | | | | | | | | United States Large Cap | | | — | | | | 61 | | | | — | | | | 61 | | United States Small Cap | | | — | | | | 13 | | | | — | | | | 13 | | Non-United States | | | — | | | | 47 | | | | — | | | | 47 | | Fixed Income | | | — | | | | 101 | | | | — | | | | 101 | | Real Estate | | | — | | | | 7 | | | | 11 | | | | 18 | | Private Equity | | | — | | | | — | | | | 4 | | | | 4 | | | | | | | | | | | | | | | | | | | Total | | $ | 1 | | | $ | 229 | | | $ | 15 | | | $ | 245 | | | | | | | | | | | | | | | | | | |
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. Level 2 investments comprise amounts held in commingled equity funds, USUnited States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. Level 3 real estate investments were valued at December 31, 2010 and 2009, using a real estate index value. The real estate index value was developed based on appraisals comprising 94% and 82%87% of real estate assets tracked by the index in 20102012 and 2009, respectively. comprising 85% in 2011.Level 3 hedge and private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. K-148
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UES pension plan of $9 million and $6$14 million at December 31, 20102012, and 2009, respectively. $10 million at December 31, 2011.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. | | | | | | | | | | | | | | | | | | | | | Year Ended | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | | | | Private Equity | | | Real Estate | | | Hedge Fund | | | Total | | | | | | | | | | | | | | | | | | | | | Beginning Balances at January 1, 2010 | | $ | 1 | | | $ | 8 | | | $ | 1 | | | $ | 10 | | | Actual Return on Plan Assets: | | | | | | | | | | | | | | | | | | Relating to Assets still held at Reporting Date | | | — | | | | 1 | | | | — | | | | 1 | | | Relating to Assets sold during the Period | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | Purchases, Sales, and Settlements | | | 1 | | | | 1 | | | | — | | | | 2 | | | | | | | | | | | | | | | | | Ending Balance at December 31, 2010 | | $ | 2 | | | $ | 10 | | | $ | — | | | $ | 12 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Year Ended | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | | | | Private Equity | | | Real Estate | | | Hedge Fund | | | Total | | | | | | | | | | | | | | | | | | | | | Beginning Balances at January 1, 2009 | | $ | 1 | | | $ | 12 | | | $ | 3 | | | $ | 16 | | | Actual Return on Plan Assets: | | | | | | | | | | | | | | | | | | Relating to Assets still held at Reporting Date | | | — | | | | (4 | ) | | | — | | | | (4 | ) | | Relating to Assets sold during the Period | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | Purchases, Sales, and Settlements | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | | | | | | | | | | | | | | Ending Balance at December 31, 2009 | | $ | 1 | | | $ | 8 | | | $ | 1 | | | $ | 10 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Year Ended
December 31, 2012 | | | | | Private
Equity | | | Real Estate | | | Total | | Beginning Balance at January 1, 2012 | | $ | 4 | | | $ | 11 | | | $ | 15 | | Actual Return on Plan Assets: | | | | | | | | | | | | | Assets Held at Reporting Date | | | 1 | | | | 2 | | | | 3 | | Purchases, Sales, and Settlements | | | 1 | | | | — | | | | 1 | | | | | | | | | | | | | | | Ending Balance at December 31, 2012 | | $ | 6 | | | $ | 13 | | | $ | 19 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Year Ended
December 31, 2011 | | | | | Private
Equity | | | Real Estate | | | Total | | Beginning Balance at January 1, 2011 | | $ | 2 | | | $ | 10 | | | $ | 12 | | Actual Return on Plan Assets: | | | | | | | | | | | | | Assets Held at Reporting Date | | | — | | | | 1 | | | | 1 | | Purchases, Sales, and Settlements | | | 2 | | | | — | | | | 2 | | | | | | | | | | | | | | | Ending Balance at December 31, 2011 | | $ | 4 | | | $ | 11 | | | $ | 15 | | | | | | | | | | | | | | |
UNS Gas and UNS Electric have no pension assets classified as Level 3 in the fair value hierarchy. Pension Plan Investments Strategic assetAsset allocation is the principal method for achieving each pension plan’s investment objective,objectives, while maintaining an appropriate level of risk. We will consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding will be reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. The pension plans seek to provide returns in excess of a portfolio benchmark. K-149
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Risk Management We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: 1) Plan status; 2)plan status, plan sponsor financial status and profitability; 3) Plan features;profitability, plan features, and 4) workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also have beenbe used for defensive purposes. Relationship between Plan Assets and Benefit Obligations The overall health of each Planplan will be monitored by comparing the value of Planplan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the marketfair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of Planplan data, but will be no less frequent than annually via annual actuarial valuation. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Target Allocation Percentages The current target allocation percentages for the major asset categories of the plan assetsas of December 31, 2012, follow. Each Planplan allows a variance of +/-2%+/- 2% from these targets before funds are automatically rebalanced. The hedge fund is being closed, and is currently in the redemption/liquidation process. | | | | | | | | | | | | | | | | | TEP Plan % | | | UES Plan % | | | VEBA Trust % | | | Fixed Income | | | 34 | % | | | 33 | % | | | 63 | % | | U.S. Large Cap | | | 28 | % | | | 28 | % | | | 28 | % | | Non-US Developed | | | 18 | % | | | 17 | % | | | 2 | % | | Real Estate | | | 7 | % | | | 11 | % | | | — | | | U.S. Small Cap | | | 6 | % | | | 6 | % | | | 2 | % | | Non-US Emerging | | | 6 | % | | | 5 | % | | | — | | | Private Equity | | | 1 | % | | | — | | | | — | | | Cash / Treasury Bills | | | — | | | | — | | | | 5 | % | | | | | | | | | | | | | Total | | | 100.0 | % | | | 100.0 | % | | | 100.0 | % | | | | | | | | | | �� | |
| | | | | | | | | | | | | | | | TEP Plan | | | UES Plan | | | VEBA Trust | | Fixed Income | | | 41 | % | | | 33 | % | | | 35 | % | United States Large Cap | | | 24 | | | | 28 | | | | 43 | | Non-United States Developed | | | 15 | | | | 17 | | | | 13 | | Real Estate | | | 8 | | | | 11 | | | | — | | United States Small Cap | | | 5 | | | | 6 | | | | 2 | | Non-United States Emerging | | | 5 | | | | 5 | | | | 5 | | Private Equity | | | 2 | | | | — | | | | — | | Cash/Treasury Bills | | | — | | | | — | | | | 2 | | | | | | | | | | | | | | | Total | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | | | | | | | |
Pension Fund Descriptions The funds are managerFor each type of manager funds, withasset category selected by the exceptionPension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the hedgetotal investment to each fund andmanager. In the case of the private equity fund, which are funds ofour investment consultant directs investments to a private equity manager that invests in third-parties’ funds. Other PostretirementRetiree Benefit Assets As of December 31, 2010,2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. As of December 31, 2011, the fair value of VEBA trust assets was $5 million, including $2$3 million of fixed income investments and approximately $2 million of equity and money market funds. As of December 31, 2009, the fair value ofThe VEBA trust assets were $1.5 million of which $1 million were fixed income investments and $0.5 million were equities.are primarily Level 2. There are no level threeLevel 3 assets in the VEBA trust. K-150
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the defined benefit pension plans and postretirementretiree plan, which reflect future service, as appropriate. | | | | | | | | | | | | | | | | | Other | | | | | Pension | | | Postretirement | | | TEP | | Benefits | | | Benefits | | | | | -Millions of Dollars- | | | 2011 | | $ | 11 | | | $ | 4 | | | 2012 | | | 12 | | | | 5 | | | 2013 | | | 13 | | | | 5 | | | 2014 | | | 14 | | | | 5 | | | 2015 | | | 16 | | | | 6 | | | Years 2016-2020 | | | 94 | | | | 32 | |
| | | | | | | | | | | | Pension
Benefits | | | Other
Retiree
Benefits | | | | | -Millions of Dollars- | | 2013 | | $ | 15 | | | $ | 4 | | 2014 | | | 16 | | | | 5 | | 2015 | | | 16 | | | | 5 | | 2016 | | | 18 | | | | 5 | | 2017 | | | 20 | | | | 5 | | Years 2018-2022 | | | 110 | | | | 30 | |
TEP’s union plan was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments shown above was approximately $5 million in total. The pension benefit obligation was not materially affected by this amendment. UNS Gas and UNS Electric expect annual pension and postretirement benefit payments, of approximately $5 million in 2011 through 2015 and $8 million in 2016 through 2020 to be made by the defined benefit pension and postretirement plans. retiree plans, to be approximately $2 million in 2013 through 2017, and $9 million in 2018 through 2022.UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) DEFINED CONTRIBUTION PLANS TEP, UNS Gas and UNS ElectricPLANWe offer a defined contribution savings plansplan to all eligible employees. The Internal Revenue Code identifies the plansplan as a qualified 401(k) plans.plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. TEP, UNS Gas and UNS ElectricWe match part of a participant’s contributions to the plans.plan. TEP made matching contributions to these plansthe plan of approximately$5 million in 2012, $5 million in 2011, and $4 million in each of 2010, 2009, and 2008.2010. UNS Gas and UNS Electric made matching contributions of less than $1 million in each of 2010, 2009,2012, 2011, and 2008. NOTE 10. SHARE-BASED COMPENSATION PLAN Under the 2006UNS Energy 2011 Omnibus Stock and Incentive Plan (Share-based Compensation(2011 Plan), the Compensation Committee of the UniSourceUNS Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted shares/units, and performance shares. The total number of shares which may be awarded under the Share-based Compensation2011 Plan cannot exceed 2.251.2 million shares. At December 31, 2010, the total number of shares awarded under the Share-based Compensation Plan was 1 million shares. No stock options were granted by the Compensation Committee during 2010. In February 2009, the Compensation Committee granted 248,760 stock options to officers with an exercise price of $26.11. In 2008, the Compensation Committee granted 303,550 stock options to officers with an exercise price of $26.18.
Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of the grant. Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement eligibleretirement-eligible officers, compensation expense is recorded immediately. The 2002 stock option award accrues dividend equivalents that are paid in cash on the earlier of the date of separation of service or the date the option expires. Dividend equivalents are recorded as dividends when paid. K-151
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The fair value of each option award was estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table. The expected terms of the stock options granted in 2009 and 2008 were estimated using historical exercise data. The risk-free rate was 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. The expected volatility for each award was based on historical volatility for UniSource Energy’s stock for a period equal to the expected term of the award. The expected dividend yield on a share of stock was calculated using the historical dividend yield with the implicit assumption that current dividend yields will continue in the future.
| | | | | | | | | | | | | 2009 | | | 2008 | | | Expected Term (years) | | | 7 | | | | 6 | | | Risk-free Rate | | | 3.4 | % | | | 3.1 | % | | Expected Volatility | | | 25.0 | % | | | 18.8 | % | | Expected Dividend Yield | | | 3.2 | % | | | 2.8 | % | | Weighted-Average Grant-Date Fair Value of Options Granted During the Period | | $ | 5.53 | | | $ | 4.23 | |
ASee summary of the stock option activity follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | (Shares in Thousands) | | 2010 | | | 2009 | | | 2008 | | | | | | | | | Weighted | | | | | | | Weighted | | | | | | | Weighted | | | | | | | | | Average | | | | | | | Average | | | | | | | Average | | | | | | | | | Exercise | | | | | | | Exercise | | | | | | | Exercise | | | Stock Options | | Shares | | | Price | | | Shares | | | Price | | | Shares | | | Price | | | Outstanding, Beginning of Year | | | 1,598 | | | $ | 24.50 | | | | 1,635 | | | $ | 22.50 | | | | 1,451 | | | $ | 21.21 | | | Granted | | | — | | | | — | | | | 249 | | | $ | 26.11 | | | | 304 | | | $ | 26.18 | | | Exercised or Vested | | | (660 | ) | | $ | 19.33 | | | | (282 | ) | | $ | 14.46 | | | | (120 | ) | | $ | 16.34 | | | Forfeited/Expired | | | (17 | ) | | $ | 37.88 | | | | (4 | ) | | $ | 12.28 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | Outstanding, End of Year | | | 921 | | | $ | 27.96 | | | | 1,598 | | | $ | 24.50 | | | | 1,635 | | | $ | 22.50 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exercisable, End of Year | | | 654 | | | $ | 28.70 | | | | 1,085 | | | $ | 23.06 | | | | 1,153 | | | $ | 19.50 | | | Aggregate Intrinsic Value of Options Exercised ($000s) | | $ | 9,124 | | | | | | | $ | 4,177 | | | | | | | $ | 1,680 | | | | | |
| | | | | | | | | At December 31, 2010($000s) | | | Aggregate Intrinsic Value for Options Outstanding | | $ | 7,606 | | | Aggregate Intrinsic Value for Options Exercisable | | $ | 5,015 | | | Weighted Average Remaining Contractual Life of Outstanding Options | | | 5.3 years | | | Weighted Average Remaining Contractual Life of Exercisable Options | | | 4.5 years | |
| | | | | | | | | | | | | | | | | | | | | | | | | (Shares in Thousands) | | 2012 | | | 2011 | | | 2010 | | Stock Options | | Shares | | | Weighted
Average
Exercise
Price | | | Shares | | | Weighted
Average
Exercise
Price | | | Shares | | | Weighted
Average
Exercise
Price | | Outstanding, Beginning of Year | | | 581 | | | $ | 29.11 | | | | 921 | | | $ | 27.96 | | | | 1,598 | | | $ | 24.50 | | Granted | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Exercised | | | (132 | ) | | | 26.54 | | | | (319 | ) | | | 25.60 | | | | (660 | ) | | | 19.33 | | Forfeited/Expired | | | (40 | ) | | | 37.88 | | | | (21 | ) | | | 31.92 | | | | (17 | ) | | | 37.88 | | | | | | | | | | | | | | | | | | | | | | | | | | | Outstanding, End of Year | | | 409 | | | | 29.09 | | | | 581 | | | | 29.11 | | | | 921 | | | | 27.96 | | | | | | | | | | | | | | | | | | | | | | | | | | | Exercisable, End of Year | | | 409 | | | $ | 29.09 | | | | 508 | | | $ | 29.53 | | | | 654 | | | $ | 28.70 | | Aggregate Intrinsic Value of Options Exercised ($000s) | | | | | | $ | 1,878 | | | | | | | $ | 3,690 | | | | | | | $ | 9,124 | |
K-152
| | | | | | | | At December 31, 2012 | | Aggregate Intrinsic Value for Options Outstanding ($000s) | | $ | 5,450 | | Aggregate Intrinsic Value for Options Exercisable ($000s) | | $ | 5,450 | | Weighted Average Remaining Contractual Life of Outstanding Options | | | 5.2 years | | Weighted Average Remaining Contractual Life of Exercisable Options | | | 5.2 years | |
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) A(Continued)See summary of stock options follows: | | | | | | | | | | | | | | | | | | | | | | | | | Options Outstanding | | | Options Exercisable | | | | | | | | | Weighted- | | | | | | | | | | | | | | | | | | | Average | | | Weighted- | | | | | | | Weighted- | | | | | Number of | | | Remaining | | | Average | | | Number | | | Average | | | Range of | | Shares | | | Contractual | | | Exercise | | | of Shares | | | Exercise | | | Exercise Prices | | (000s) | | | Life | | | Price | | | (000s) | | | Price | | | $17.44 – $18.74 | | | 117 | | | 1.2 years | | $ | 18.05 | | | | 117 | | | $ | 18.05 | | | $26.11 – $37.88 | | | 804 | | | 5.9 years | | $ | 29.39 | | | | 537 | | | $ | 31.01 | |
We summarizein the status of non-vested stock options as of December 31, 2010, and changes during 2010table below:
| | | | | | | | | | | | | Number of Shares | | | Weighted-Average | | | Non-vested Shares | | (000s) | | | Grant-Date Fair Value | | | Non-vested at January 1, 2010 | | | 513 | | | $ | 5.33 | | | Granted | | | — | | | | — | | | Vested | | | (229 | ) | | | 5.46 | | | Forfeited | | | (17 | ) | | | 8.13 | | | Non-vested at December 31, 2010 | | | 267 | | | $ | 5.04 | |
| | | | | | | | | | | | | | | | | | | | | | | | Options Outstanding | | | Options Exercisable | | Range of Exercise Prices | | Number of
Shares
(000s) | | | Weighted
Average
Remaining
Contractual
Life | | | Weighted
Average
Exercise
Price | | | Number of
Shares
(000s) | | | Weighted
Average
Exercise Price | | $26.11—$37.88 | | | 409 | | | | 5.2 years | | | $ | 29.09 | | | | 409 | | | $ | 29.09 | |
RESTRICTED STOCK UNITS/AWARDSUNITS AND PERFORMANCE SHARES SHARE AWARDSRestricted Stock Units Restricted stock and stock units are generally granted under the Share-based Compensation 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 is payable in Common Stock. Stock units vest either immediately or over periods ranging from one to three years. The restricted stock units vest immediately upon death, disability, or retirement. In the January following the year the person is no longer a director, Common Stock shares will be issued for the vested stock units. Compensation expense equal to the fair market value on the grant date is recognized over the vesting period. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. Common Stock shares totaling 31,058 in 2012, 56,705 in 2011, and 14,866 101,765 and 22,686in 2010 were issued in 2010, 2009 and 2008, respectively, with no additional increase in equity as the expense was previously recognized over the vesting period. The Compensation Committee granted in total, the following stock units to non-employee directors: 2012—15,303 stock units at a weighted average fair value of $35.94 per share; 2011—14,655 stock units at a weighted average fair value of $37.53 per share; and May 2010 — 2010—15,620 stock units at a weighted average fair value of $31.69 per share, May 2009 — 21,886 stock units at a weighted average fair value of $26.73 per share,
August 2008 — 1,400 stock units at a weighted average fair value of $32.15 per share.
May 2008 — 18,448 stock units at a weighted average fair value of $31.71 per share, and
February 2008 — 3,130 stock units at a weighted average fair value of $28.75 per share,
K-153
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Performance Share Awards In February2012, 2011, and 2010, the Compensation Committee granted 93,720 performance share awards to officers. 50%upper management. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $31.26 per share. Those awards will be paid out in shares of UniSource Energy common stockCommon Stock based on a comparison of UniSourceUNS Energy’s cumulative Total Shareholder Return to that of an industry peer groupthe Edison Electric Institute Index during the performance period of January 1, 2010 through December 31, 2012.period. The remaining 50% had a grant date fair value of $30.52 per share and will be paid out in shares of UniSource Energy Common Stock based on cumulative net income for the 3-year period ended December 31, 2012. The performance shares vest based on goal attainment upon completion of the performance period; any unearnedthese awards are forfeited. Performance shares are eligible for dividend equivalents during the performance period. In February 2009, the Compensation Committee granted 62,190 performance share awards to Officers atwith a grant date fair value,market condition were derived based on a Monte Carlo simulation, of $21.62 per share. Those awards will be paid out in shares of UniSource Energy common stock based on a comparison of UniSource Energy’s cumulative Total Shareholder Return to that of an industry peer group during the performance period of January 1, 2009 through December 31, 2011. The performance shares vest based on the achievement of goals by the end of the performance period; any unearned awards are forfeited.simulation. Compensation expense equal to the fair value on the grant date is recognized over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved.
In February 2008, The remaining half will be paid out in Common Stock based on cumulative net income during the Compensation Committee granted 49,140 performance share awards to Officers at aperiod. The grant date fair value, basedvalues of these awards with a performance condition were the closing Common Stock market prices on a Monte Carlo simulation,the dates of $17.10 per share. At December 31, 2010, upon completion of the 3-year performance period, 56,232 shares vested based on goal attainment at 150% of targeted UniSource Energy Total Shareholder Return during the performance period compared to the Total Shareholder Return over the same period of an industry or peer group; 11,652 shares were unearned and forfeited.grant. Compensation expense equal to the fair value on the grant date wasis recognized over the vestingrequisite service period only for the requisite serviceawards that ultimately vest. The performance shares vest based on the achievement of these goals by the end of the performance period; any unearned awards are forfeited. Vested performance shares are eligible for dividend equivalents during the performance period.
| | | | | | | | | | | | | | | | | | | | | Performance Shares | | | Restricted Stock Units | | | | | | | | | Weighted- | | | | | | | Weighted- | | | | | | | | | Average | | | | | | | Average | | | | | Shares | | | Grant-Date | | | Shares | | | Grant-Date | | | | | (000s) | | | Fair Value | | | (000s) | | | Fair Value | | | Non-vested at January 1, 2010 | | | 100 | | | $ | 19.92 | | | | 22 | | | $ | 26.73 | | | Granted | | | 94 | | | | 30.89 | | | | 16 | | | | 31.69 | | | Vested | | | (38 | ) | | | 17.10 | | | | (22 | ) | | | 26.73 | | | Forfeited | | | — | | | | — | | | | — | | | | — | | | Non-vested at December 31, 2010 | | | 156 | | | $ | 27.19 | | | | 16 | | | $ | 31.69 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Grant Date Fair Value | | Award Year | | Performance Period | | | Shares
Granted | | | Market
Condition | | | Performance
Condition | | 2012 | | | January 1, 2012 to December 31, 2014 | | | | 80,140 | | | $ | 32.71 | | | $ | 36.40 | | 2011 | | | January 1, 2011 to December 31, 2013 | | | | 80,440 | | | | 33.73 | | | | 36.58 | | 2010 | | | January 1, 2010 to December 31, 2012 | | | | 93,720 | | | | 31.26 | | | | 30.52 | |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) At December 31, 2012, upon completion of the three-year performance period, 76,478 shares were earned and vested; 17,242 shares were unearned and forfeited. The vested performance shares also earned 10,516 in dividend equivalent shares. | | | | | | | | | | | | | | | | | | | | Performance Shares | | | Restricted Stock Units | | | | | Shares
(000s) | | | Weighted
Average
Grant Date
Fair Value | | | Shares
(000s) | | | Weighted
Average
Grant Date
Fair Value | | Non-vested at January 1, 2012 | | | 153 | | | $ | 32.85 | | | | 15 | | | $ | 37.53 | | Granted | | | 80 | | | | 34.56 | | | | 15 | | | | 35.94 | | Vested | | | (77 | ) | | | 31.08 | | | | (15 | ) | | | 37.53 | | Forfeited | | | (11 | ) | | | 31.42 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Non-vested at December 31, 2012 | | | 145 | | | | 34.83 | | | | 15 | | | | 35.94 | | | | | | | | | | | | | | | | | | |
SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units) Units, and Performance Shares)Annually during 20082010 through 2010, UniSource2012, UNS Energy recorded share-based compensation expense of $3 million, and TEP recorded$2 million of which related to TEP. No share-based compensation expensewas capitalized as part of $2 million.the cost of an asset. The actual tax deduction realized from the exercise of share-based payment arrangements totaled $3 million for 2010, $3 million for 2009, andless than $1 million in 2008. In 2010, 2009,2012 and 2008, we capitalized approximately 36%, 30% and 28%, respectively,$3 million in 2010. UNS Energy did not realize a tax deduction from the exercise of share-based compensation costs as a cost of construction. payment arrangements in 2011.At December 31, 2010,2012, the total unrecognized compensation cost related to non-vested share-based compensation was $3$2 million, which will be recorded as compensation expense over the remaining vesting periods through December 2012.2014. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation planplans at December 31, 2010,2012, was 1 million. K-154
We categorize our assets and liabilities at fair value into the three-level hierarchy based on inputs used to determine the fair value measurement. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable. Level 3 inputs are unobservable and supported by little or no market activity.UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) NOTE 11. FAIR VALUE MEASUREMENTS
Fair Value of Financial Instruments Carried at Fair Value
(Continued)The following tables set forth,present, by level within the fair value hierarchy, UniSource EnergyUNS Energy’s and TEP’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and December 31, 2009. Financialbasis. These assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. There were no transfers amongbetween Levels 1, 2, or 3 for either reporting period. | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | | | Quoted Prices | | | Significant | | | | | | | | | | | in Active | | | Other | | | Significant | | | | | | | | Markets for | | | Observable | | | Unobservable | | | | | | | | Identical Assets | | | Inputs | | | Inputs | | | | | | | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 38 | | | $ | — | | | $ | — | | | $ | 38 | | Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2) | | | — | | | | 16 | | | | — | | | | 16 | | Collateral Posted(4) | | | — | | | | 3 | | | | — | | | | 3 | | Energy Contracts(5) | | | — | | | | — | | | | 15 | | | | 15 | | | | | | | | | | | | | | | | Total Assets | | | 38 | | | | 19 | | | | 15 | | | | 72 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(5) | | | — | | | | (19 | ) | | | (25 | ) | | | (44 | ) | Interest Rate Swaps(6) | | | — | | | | (10 | ) | | | — | | | | (10 | ) | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (29 | ) | | | (25 | ) | | | (54 | ) | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 38 | | | $ | (10 | ) | | $ | (10 | ) | | $ | 18 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | | December 31, 2012 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 20 | | | $ | — | | | $ | — | | | $ | 20 | | Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans(2) | | | — | | | | 19 | | | | — | | | | 19 | | Energy Contracts(3) | | | — | | | | 2 | | | | 5 | | | | 7 | | | | | | | | | | | | | | | | | | | Total Assets | | | 20 | | | | 21 | | | | 5 | | | | 46 | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(3) | | | — | | | | (7 | ) | | | (10 | ) | | | (17 | ) | Interest Rate Swaps(4) | | | — | | | | (10 | ) | | | — | | | | (10 | ) | | | | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (17 | ) | | | (10 | ) | | | (27 | ) | | | | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 20 | | | $ | 4 | | | $ | (5 | ) | | $ | 19 | | | | | | | | | | | | | | | | | | |
K-155
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | | December 31, 2011 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 23 | | | $ | — | | | $ | — | | | $ | 23 | | Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans(2) | | | — | | | | 16 | | | | — | | | | 16 | | Energy Contracts(3) | | | — | | | | — | | | | 14 | | | | 14 | | | | | | | | | | | | | | | | | | | Total Assets | | | 23 | | | | 16 | | | | 14 | | | | 53 | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(3) | | | — | | | | (21 | ) | | | (24 | ) | | | (45 | ) | Interest Rate Swaps(4) | | | — | | | | (12 | ) | | | — | | | | (12 | ) | | | | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (33 | ) | | | (24 | ) | | | (57 | ) | | | | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 23 | | | $ | (17 | ) | | $ | (10 | ) | | $ | (4 | ) | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | TEP | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | | December 31, 2012 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 7 | | | $ | — | | | $ | — | | | $ | 7 | | Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans(2) | | | — | | | | 19 | | | | — | | | | 19 | | Energy Contracts(3) | | | — | | | | 1 | | | | 2 | | | | 3 | | | | | | | | | | | | | | | | | | | Total Assets | | | 7 | | | | 20 | | | | 2 | | | | 29 | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(3) | | | — | | | | (3 | ) | | | (2 | ) | | | (5 | ) | Interest Rate Swaps(4) | | | — | | | | (10 | ) | | | — | | | | (10 | ) | | | | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (13 | ) | | | (2 | ) | | | (15 | ) | | | | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 7 | | | $ | 7 | | | $ | — | | | $ | 14 | | | | | | | | | | | | | | | | | | |
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | | | Quoted Prices | | | Significant | | | | | | | | | | | in Active | | | Other | | | Significant | | | | | | | | Markets for | | | Observable | | | Unobservable | | | | | | | | Identical Assets | | | Inputs | | | Inputs | | | | | | | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 51 | | | $ | — | | | $ | — | | | $ | 51 | | Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2) | | | — | | | | 14 | | | | — | | | | 14 | | Equity Investments(3) | | | — | | | | — | | | | 6 | | | | 6 | | Collateral Posted(4) | | | — | | | | 2 | | | | — | | | | 2 | | Energy Contracts(5) | | | — | | | | 1 | | | | 6 | | | | 7 | | | | | | | | | | | | | | | | Total Assets | | | 51 | | | | 17 | | | | 12 | | | | 80 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(5) | | | — | | | | (16 | ) | | | (19 | ) | | | (35 | ) | Interest Rate Swaps(6) | | | — | | | | (6 | ) | | | — | | | | (6 | ) | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (22 | ) | | | (19 | ) | | | (41 | ) | | | | | | | �� | | | | | | | | Net Total Assets and (Liabilities) | | $ | 51 | | | $ | (5 | ) | | $ | (7 | ) | | $ | 39 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | TEP | | | | | Quoted Prices | | | Significant | | | | | | | | | | | in Active | | | Other | | | Significant | | | | | | | | Markets for | | | Observable | | | Unobservable | | | | | | | | Identical Assets | | | Inputs | | | Inputs | | | | | | | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 21 | | | $ | — | | | $ | — | | | $ | 21 | | Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2) | | | — | | | | 16 | | | | — | | | | 16 | | Energy Contracts(5) | | | — | | | | — | | | | 3 | | | | 3 | | | | | | | | | | | | | | | | Total Assets | | | 21 | | | | 16 | | | | 3 | | | | 40 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(5) | | | — | | | | (7 | ) | | | (2 | ) | | | (9 | ) | Interest Rate Swaps(6) | | | — | | | | (10 | ) | | | — | | | | (10 | ) | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (17 | ) | | | (2 | ) | | | (19 | ) | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 21 | | | $ | (1 | ) | | $ | 1 | | | $ | 21 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | TEP | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | | | December 31, 2011 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | | Rabbi Trust Investments to Support the Deferred Compensation and SERP Plans(2) | | | — | | | | 16 | | | | — | | | | 16 | | Energy Contracts(3) | | | — | | | | — | | | | 3 | | | | 3 | | | | | | | | | | | | | | | | | | | Total Assets | | | 8 | | | | 16 | | | | 3 | | | | 27 | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(3) | | | — | | | | (9 | ) | | | (3 | ) | | | (12 | ) | Interest Rate Swaps(4) | | | — | | | | (11 | ) | | | — | | | | (11 | ) | | | | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (20 | ) | | | (3 | ) | | | (23 | ) | | | | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 8 | | | $ | (4 | ) | | $ | — | | | $ | 4 | | | | | | | | | | | | | | | | | | |
K-156
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
| | | | | | | | | | | | | | | | | | | | | TEP | | | | | Quoted Prices | | | | | | | | | | | | | | in Active | | | Significant | | | | | | | | | | | Markets for | | | Other | | | Significant | | | | | | | | Identical | | | Observable | | | Unobservable | | | | | | | | Assets | | | Inputs | | | Inputs | | | | | | | | (Level 1) | | | (Level 2) | | | (Level 3) | | | Total | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | Assets | | | | | | | | | | | | | | | | | Cash Equivalents(1) | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | | Rabbi Trust Investments to support the Deferred Compensation and SERP Plans(2) | | | — | | | | 14 | | | | — | | | | 14 | | Energy Contracts(5) | | | — | | | | 1 | | | | 5 | | | | 6 | | | | | | | | | | | | | | | | Total Assets | | | 8 | | | | 15 | | | | 5 | | | | 28 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Energy Contracts(5) | | | — | | | | (5 | ) | | | (9 | ) | | | (14 | ) | Interest Rate Swaps(6) | | | — | | | | (6 | ) | | | — | | | | (6 | ) | | | | | | | | | | | | | | | Total Liabilities | | | — | | | | (11 | ) | | | (9 | ) | | | (20 | ) | | | | | | | | | | | | | | | Net Total Assets and (Liabilities) | | $ | 8 | | | $ | 4 | | | $ | (4 | ) | | $ | 8 | | | | | | | | | | | | | | | |
| (1) | | | (1) | | Cash Equivalents are based on observable market prices and include the fair value of commercial paper, money market funds and certificates of deposit. These amounts are included in Cash and Cash Equivalents and in Investments and Other Property — Property—Other inon the UniSource Energy and TEP balance sheets. |
| | (2) | | Rabbi Trust Investments include amounts held in mutual and money market funds related to deferred compensation and SERP benefits. The valuation is based on quoted prices traded in active markets. These investments are included in Investments and Other Property —– Other in the UniSource Energy and TEP balance sheets. | | (3) | | Equity Investments include Millennium’s equity investments in unregulated businesses. In the absence of readily ascertainable market values their value is based on the investment partner’s valuations. These investments are included in Investments and Other Property — Other in the UniSource Energy balance sheet.sheets. |
| (4)(3) | | Collateral provided for energy contracts with counterparties to reduce credit risk exposure. Collateral posted is included in Current Assets — Other in the UniSource Energy balance sheet. | | (5) | | Energy Contracts include gas swap agreements (Level 2), gas and power options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Other Assets and Derivative Instruments inon the UniSource Energy and TEP balance sheets. The valuation techniques are described below. See Note 16. |
| (6)(4) | | Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association (SIFMA) Municipal Swapmunicipal swap index. These interest rate swaps are included in Derivative Instruments inon the UniSource Energy and TEP balance sheets. |
TEP, UNS Gas and UNS ElectricWe primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Wheremeasurements. When we have observable inputs are available for substantially the full term of the asset or liability, such as gas swap derivatives valued using New York Mercantile Exchange (NYMEX) pricing adjusted for basis differences, we categorize the instrument is categorized in Level 2. K-157
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Derivatives valued using We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers are categorized in Level 3. brokers.For both power and gas prices, TEP and UNS Electricwe obtain quotes from brokers, major market participants, exchanges, or industry publications, and rely on theirour own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then use thevalidate those prices using other sources as validation of those prices. The broker providing quotes for power prices statessources. We believe that the market information provided is indicative only, but believes it to be reflective of market conditions as of the time and date indicated. In addition, Published prices for energy derivatives includederivative contracts where published prices aremay not readily available. These include contracts forbe available due to the nature of contract delivery periods duringterms such as non-standard time blocks contracts for delivery during only a few months of a given year when prices are quoted only for the annual average, or contracts for delivery at illiquidand non-standard delivery points. In these cases, certain management assumptions are applied to value such contracts. These assumptions include the use of percentage multipliers to value non-standard time blocks, the application ofwe apply adjustments based on historical price curve relationships, to calendar year quotes, and the inclusion of adjustments for transmission, and line losses tolosses. We estimate the fair value contracts at illiquid delivery points. of our options using the Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, correlations, interest rates, and forward price curves. UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using market credit default swap data. These assumptions are reviewed on a quarterly basis. The fair value of TEP’s purchase power call option is estimated using an internal pricing model which includes assumptions about market risks such as liquidity, volatility, and contract valuation. This model also considers credit and non-performance risk. UniSource Energy and TEP’s assessmentOur assessments of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our contracts monthly.The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements: | | | | | | | | | | | | | | | | Fair Value at December 31, 2012 | | | Range of | | | | | Assets | | | Liabilities | | | Unobservable Input | | | | | -Millions of Dollars- | | | | | Forward Contracts(1) | | $ | 4 | | | $ | (10 | ) | | | | | Valuation Technique: Market approach | | | | | | | | | | | | | Unobservable Input: | | | | | | | | | | | | | Market price per MWh | | | | | | | | | | | $19.50 - $ 56.24 | | | | | | Option Contracts(2) | | | 1 | | | | — | | | | | | Valuation Technique: Option model | | | | | | | | | | | | | Unobservable Inputs: | | | | | | | | | | | | | Market Price per MWh | | | | | | | | | | | $29.50 - $ 46.00 | | Power Volatility | | | | | | | | | | | 30.38% - 59.95% | | Market Price per MMbtu | | | | | | | | | | | $3.22 - $ 3.84 | | Gas Volatility | | | | | | | | | | | 29.32% -36.14% | | | | | | | | | | | | | | | Level 3 Energy Contracts | | $ | 5 | | | $ | (10 | ) | | | | | | | | | | | | | | | | | |
| (1) | TEP comprises $1 million of the forward contract assets and $2 million of the forward contract liabilities. |
| (2) | The option contracts relate to TEP. |
Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability. These are recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statements. The following tables set forthpresent a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: | | | | | | | | | | | | | | | | | | | | | Year Ended | | | | | December 31, 2010 | | | | | - Millions of Dollars - | | | | | UniSource Energy | | | TEP | | | | | Energy | | | Equity | | | | | | | Energy | | | | | Contracts | | | Investments | | | Total | | | Contracts | | Balance as of January 1, 2010 | | $ | (13 | ) | | $ | 6 | | | $ | (7 | ) | | $ | (4 | ) | | Gains and (Losses) (Realized/Unrealized) Recorded to: | | | | | | | | | | | | | | | | | | Net Regulatory Assets — Derivative Instruments | | | 4 | | | | — | | | | 4 | | | | 6 | | | Other Comprehensive Income | | | (1 | ) | | | — | | | | (1 | ) | | | (1 | ) | | Other Expense | | | — | | | | (6 | ) | | | (6 | ) | | | — | | | | | | | | | | | | | | | | Balance as of December 31, 2010 | | $ | (10 | ) | | $ | — | | | $ | (10 | ) | | $ | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total gains (losses) attributable to the change in unrealized gains or losses relating to assets/liabilities still held at the end of the period | | $ | (4 | ) | | $ | — | | | $ | (4 | ) | | $ | 5 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Year Ended
December 31, 2012 | | | | | UNS
Energy | | | TEP | | | | | Energy Contracts | | | | | -Millions of Dollars- | | Balance as of December 31, 2011 | | $ | (10 | ) | | $ | — | | Realized/Unrealized Gains/(Losses)Recorded to: | | | | | | | | | Net Regulatory Assets/Liabilities – Derivative Instruments | | | (5 | ) | | | 1 | | Settlements | | | 10 | | | | (1 | ) | | | | | | | | | | Balance as of December 31, 2012 | | $ | (5 | ) | | $ | — | | | | | | | | | | | Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | | $ | (1 | ) | | $ | — | | | | | | | | | | |
K-158
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) | | | | | | | | | | | | | | | | | | | | | Year Ended | | | | | December 31, 2009 | | | | | - Millions of Dollars - | | | | | UniSource Energy | | | TEP | | | | | Energy | | | Equity | | | | | | | Energy | | | | | Contracts | | | Investments | | | Total | | | Contracts | | Balance as of January 1, 2009 | | $ | (17 | ) | | $ | 11 | | | $ | (6 | ) | | $ | (1 | ) | | Gains and (Losses) (Realized/Unrealized) Recorded to: | | | | | | | | | | | | | | | | | | Net Regulatory Assets — Derivative Instruments | | | 5 | | | | — | | | | 5 | | | | (2 | ) | | Other Comprehensive Income | | | (1 | ) | | | — | | | | (1 | ) | | | (1 | ) | | Other Expense | | | — | | | | (2 | ) | | | (2 | ) | | | — | | | Cash Proceeds from Sale of Investment | | | — | | | | (3 | ) | | | (3 | ) | | | — | | | | | | | | | | | | | | | | Balance as of December 31, 2009 | | $ | (13 | ) | | $ | 6 | | | $ | (7 | ) | | $ | (4 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total gains (losses) attributable to the change in unrealized gains or losses relating to assets/liabilities held at the end of the period | | $ | (6 | ) | | $ | (2 | ) | | $ | (8 | ) | | $ | (3 | ) | | | | | | | | | | | | | | |
Gains and losses on energy contracts include the reclassification of realized gains and losses on the settlement of derivative contracts.
Fair Value of (Continued) | | | | | | | | | | | | Year Ended
December 31, 2011 | | | | | UNS
Energy | | | TEP | | | | | Energy Contracts | | | | | -Millions of Dollars- | | Balance as of December 31, 2010 | | $ | (10 | ) | | $ | 1 | | Realized/Unrealized Gains/(Losses) Recorded to: | | | | | | | | | Net Regulatory Assets/Liabilities – Derivative Instruments | | | (9 | ) | | | 2 | | Other Comprehensive Income | | | (1 | ) | | | (1 | ) | Settlements | | | 10 | | | | (2 | ) | | | | | | | | | | Balance as of December 31, 2011 | | $ | (10 | ) | | $ | — | | | | | | | | | | | Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | | $ | (9 | ) | | $ | — | | | | | | | | | | |
Financial Instruments Not Carried at Fair Value The fair value of a financial instrument is the market price that would be received to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments: The carrying amounts of our current assets and liabilities, including Current Maturitiescurrent maturities of Long-Term Debt,long-term debt, and amounts outstanding under our credit agreements, which approximate theirthe fair valuevalues due to the short-term nature of these instruments; with the exception of $50 million of UNS Gas Senior Unsecured Notes with a make-whole provision on a call premium that have a fair value of $51 million.financial instruments. These items have been excluded from the table below. InvestmentsFor Investment in Lease Debt, we calculate the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and Equity: TEP calculatedtime-to-maturity. We also incorporate the impact of counterparty credit risk using market credit default swap data. For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 in 2011. For Long-Term Debt, we use quoted market prices, where available, or calculate the present value of remaining cash flows at the balance sheet date using current market rates for instruments with similar characteristics with respect to credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data. Long-Term Debt: UniSource Energy and TEP used quoted market prices, where available, or calculated thedate. When calculating present value, of remaining cash flows at the balance sheet date usingwe use current market rates for bonds with similar characteristics with respect tosuch as credit rating and time-to-maturity. TEP considersWe consider the principal amounts of variable rate debt outstanding to be reasonable estimates of theirthe fair value. We also incorporate the impact of our own credit risk using a credit default swap rate when determining the fair value of long-term debt.
rate.K-159
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The amountcarrying value recorded inon the balance sheet (carrying value) and the estimated fair values of our financial instruments includedwere as follows: | | | | | | | | | | | | | | | | | | | | | | | | �� | | | December 31, | | | | | | | | 2012 | | | 2011 | | | | | Fair Value
Hierarchy | | | Carrying
Value | | | Fair
Value | | | Carrying
Value | | | Fair
Value | | | | | | | | -Millions of Dollars- | | Assets: | | | | | | | | | | | | | | | | | | | | | TEP Investment in Lease Debt | | | Level 2 | | | $ | 9 | | | $ | 9 | | | $ | 29 | | | $ | 29 | | TEP Investment in Lease Equity | | | Level 3 | | | | 36 | | | | 23 | | | | 37 | | | | 21 | | Liabilities: | | | | | | | | | | | | | | | | | | | | | Long-Term Debt | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | Level 2 | | | | 1,498 | | | | 1,583 | | | | 1,517 | | | | 1,543 | | TEP | | | Level 2 | | | | 1,223 | | | | 1,271 | | | | 1,080 | | | | 1,061 | |
TEP held the following: | | | | | | | | | | | | | | | | | | | | | December 31, | | | | | 2010 | | | 2009 | | | | | Carrying | | | Fair | | | Carrying | | | Fair | | | | | Value | | | Value | | | Value | | | Value | | | | | -Millions of Dollars- | | Assets: | | | | | | | | | | | | | | | | | | TEP Investment in Lease Debt and Equity | | $ | 105 | | | $ | 112 | | | $ | 132 | | | $ | 140 | | | Millennium Note Receivable | | | 15 | | | | 15 | | | | 15 | | | | 15 | | Liabilities: | | | | | | | | | | | | | | | | | | Long-Term Debt | | | | | | | | | | | | | | | | | | TEP | | | 1,004 | | | | 866 | | | | 904 | | | | 778 | | | UniSource Energy | | | 1,304 | | | | 1,194 | | | | 1,254 | | | | 1,145 | |
See Note 6 for a description of TEP’s investmentInvestment in Springerville Lease Debt and Equity. TEP intends to hold the $68 million investmentmaturity in Springerville Lease Debt Securities to maturity.January 2013. This investment iswas stated at amortized cost, which means the purchase cost hashad been adjusted for the amortization of the premium and discount to maturity.
The fair value of TEP’s Long-Term Debt increased from prior year because of a change in valuation methodology concerning the make-whole premium applied to the bonds if they are called early.
NOTE 12. UNISOURCEUNS ENERGY EARNINGS PER SHARE (EPS) We compute basic EPSEarnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options,options; contingently issuable shares under equity-based awards, or common shares that would result from the conversion of convertible notes.Convertible Senior Notes. The numerator in calculating diluted earnings per shareEPS is Net Income adjusted for the interest on convertible notesConvertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to common shares. Common Stock. K-160
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) (Continued)The following table shows the effects of potentially dilutive common stock on the weighted average number of shares: | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -In Thousands- | | | Numerator: | | | | | | | | | | | | | | Net Income | | $ | 111,477 | | | $ | 104,258 | | | $ | 14,021 | | | Income from Assumed Conversion of Convertible Senior Notes | | | 4,390 | | | | 4,390 | | | | — | | | | | | | | | | | | | | Adjusted Numerator | | $ | 115,867 | | | $ | 108,648 | | | $ | 14,021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Denominator: | | | | | | | | | | | | | | Weighted-average Shares of Common Stock Outstanding Common Shares Issued | | | 36,200 | | | | 35,653 | | | | 35,415 | | | Fully Vested Deferred Stock Units | | | 123 | | | | 105 | | | | 217 | | | Participating Securities | | | 92 | | | | 100 | | | | — | | | | | | | | | | | | | | Total Weighted-average Shares of Common Stock Outstanding and Participating Securities — Basic | | | 36,415 | | | | 35,858 | | | | 35,632 | | | Effect of Diluted Securities | | | | | | | | | | | | | | Convertible Senior Notes | | | 4,178 | | | | 4,093 | | | | — | | | Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan | | | 447 | | | | 499 | | | | 537 | | | | | | | | | | | | | | Total Shares | | | 41,040 | | | | 40,450 | | | | 36,169 | | | | | | | | | | | | |
For | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | Numerator: | | | | | | | | | | | | | Net Income | | $ | 90,919 | | | $ | 109,975 | | | $ | 112,984 | | Income from Assumed Conversion of Convertible Senior Notes | | | 1,100 | | | | 4,390 | | | | 4,390 | | | | | | | | | | | | | | | Adjusted Numerator | | $ | 92,019 | | | $ | 114,365 | | | $ | 117,374 | | | | | | | | | | | | | | | | | | | | -Thousands of Shares- | | Denominator: | | | | | Weighted Average Shares of Common Stock Outstanding: | | | | | | | | | | | | | Common Shares Issued | | | 40,212 | | | | 36,780 | | | | 36,200 | | Fully Vested Deferred Stock Units | | | 150 | | | | 129 | | | | 123 | | Participating Securities | | | — | | | | 53 | | | | 92 | | | | | | | | | | | | | | | Total Weighted Average Shares of Common Stock Outstanding and Participating Securities—Basic | | | 40,362 | | | | 36,962 | | | | 36,415 | | Effect of Diluted Securities: | | | | | | | | | | | | | Convertible Senior Notes | | | 1,062 | | | | 4,281 | | | | 4,178 | | Options and Stock Issuable Under Share-Based Compensation Plans | | | 331 | | | | 366 | | | | 448 | | | | | | | | | | | | | | | Total Shares—Diluted | | | 41,755 | | | | 41,609 | | | | 41,041 | | | | | | | | | | | | | | |
The following table shows the year ended December 31, 2008, 4 million potentially dilutive sharesnumber of stock options excluded from the conversion of convertible senior notes, and after-tax interest expense of $4 million was not included in the computation of diluted EPS because doing so would be anti-dilutive. Stock options to purchase an average of 212,000, 395,000 and 312,000 shares of Common Stock were outstanding during 2010, 2009 and 2008, respectively, 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 at year end.
Stock: | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Shares- | | Stock Options Excluded from the Diluted EPS Computation | | | 50 | | | | 153 | | | | 212 | | | | | | | | | | | | | | |
In the first half of 2012, the entire balance of Convertible Senior Notes was converted to Common Shares or redeemed for cash. See Note 6.
NOTE 13. MILLENNIUM INVESTMENTS In 2010, Millennium recorded impairment losses of $10 million related to its investments, reducing to zero the book value of its unconsolidated equity and cost method investments.investments to zero. Millennium received notification of valuation changes and ownership percentage reductions as projects lost viability and funding failed. In addition, Millennium sold a wholly-owned subsidiary and recorded a gain of less than $1 million. Gains and losses were included in Other Income or Other Expense on UniSourcein UNS Energy’s income statement.statements. Millennium also wrote off $3 million of Deferred Tax Assets related to its investments. In 2009, Millennium finalized the sale ofsold an equity investment. Millennium receivedinvestment, receiving an upfront payment of $5 million in January 2009 and a $15 million, three-year, 6%, secured note receivable. Principal onpromissory note. Millennium received the note is due at maturity; interest on the note is due annually on December 31. Theremaining principal amount of $15 million note is included in Investments and Other Property — Other on UniSource Energy’s balance sheet. Millennium recorded a $6 million gain on the sale which is included in Other Income on UniSource Energy’s income statement. 2012. K-161
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS The following recently issued accounting standards are not yet reflected in the UniSource Energy and TEP’s financial statements: The Financial Accounting Standards Board (FASB) issued authoritativea pronouncement that will require entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position (balance sheet) or subject to an agreement similar to a master netting arrangement. In addition, the pronouncement requires disclosure of collateral received and posted in connection with master netting arrangements. We will be required to comply in the first quarter of 2013 and do not expect this pronouncement to have a material impact on our disclosures. The FASB issued a rule which amends the guidance for multiple deliverable revenue arrangements that provides another alternative for determiningimpairment testing of indefinite-lived intangible assets. An entity will have the selling priceoption to perform qualitative analysis to determine whether an indefinite-lived intangible asset may be impaired. If the qualitative assessment does not result in likely impairment, an entity will not be required to perform the quantitative impairment test. We will be required to comply in the first quarter of deliverables and eliminates the residual method of allocating consideration. In addition,2013; however, we do not expect this pronouncement requires expanded qualitative and quantitative disclosures and is effective for revenue arrangements entered into after January 1, 2011. After adopting this guidanceto have a material impact on January 1, 2011, TEP and UNS Electric will continueour financial statements as our indefinite-lived intangible assets, RECs, are currently recoverable under the RES as we use RECs to assign costscomply with renewable resources requirements. The FASB decided in December 2012 to both renewable energy credits and energy when purchased through a renewable purchased power agreement. The Financial Accounting Standards Board issued amendments that require some new disclosures on items reclassified from AOCI. Companies will be required to disclose, in a single location, amounts reclassified from each component of AOCI based on its source and clarify some existing disclosure requirements about fair value measurements. Disclosures about purchases, sales, issuances, and settlementsthe income statement line items affected by the reclassification. We plan to present this information in a footnote. We will be required to comply in the roll forward of activity in Level 3 fair value measurements are effective for interim and annual reporting periods beginning January 1, 2011. We will incorporate these new disclosures in our first quarter 2011of 2013 and do not expect this decision to have a material impact on our financial statements.
K-162
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION A reconciliation of net income to net cash flows from operating activities follows: | | | | | | | | | | | | | | | | | UniSource Energy | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Thousands of Dollars- | | Net Income | | $ | 111,477 | | | $ | 104,258 | | | $ | 14,021 | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities | | | | | | | | | | | | | | Depreciation Expense | | | 128,215 | | | | 144,960 | | | | 132,366 | | | Amortization Expense | | | 28,094 | | | | 31,058 | | | | 15,324 | | | Depreciation and Amortization Recorded to Fuel and Other O&M Expense | | | 5,432 | | | | 4,929 | | | | 6,467 | | | Amortization of Deferred Debt-Related Costs included in Interest Expense | | | 3,753 | | | | 4,171 | | | | 3,891 | | | Provision for Bad Debts | | | 3,724 | | | | 3,583 | | | | 5,007 | | | Use of Renewable Energy Credits for Compliance | | | 4,745 | | | | — | | | | — | | | Deferred Income Taxes | | | 29,486 | | | | 58,692 | | | | 35,739 | | | Deferred Tax Valuation Allowance | | | 7,510 | | | | — | | | | — | | | California Power Exchange Provision for Wholesale Revenue Refunds | | | — | | | | 4,172 | | | | — | | | Pension and Postretirement Expense | | | 19,688 | | | | 23,594 | | | | 11,991 | | | Pension and Postretirement Funding | | | (27,742 | ) | | | (30,078 | ) | | | (13,928 | ) | | Stock Based Compensation Expense | | | 2,751 | | | | 2,779 | | | | 2,901 | | | Excess Tax Benefit from Stock Options Exercised | | | (3,338 | ) | | | (3,256 | ) | | | (633 | ) | | Allowance for Equity Funds used During Construction | | | (4,232 | ) | | | (4,113 | ) | | | (3,244 | ) | | Impact of Reapplication of Regulatory Accounting | | | — | | | | — | | | | (40,144 | ) | | Provision for Navajo Retiree Health Care and Mine Reclamation | | | — | | | | — | | | | 10,198 | | | Amortization of Transition Recovery Asset | | | — | | | | — | | | | 23,945 | | | CTC Revenue Refunded | | | (10,095 | ) | | | (12,141 | ) | | | 58,092 | | | Decrease to Reflect PPFAC/PGA Recovery | | | (31,105 | ) | | | (17,091 | ) | | | (10,975 | ) | | Loss/(Gain) on Millennium’s Investments | | | 9,936 | | | | (4,730 | ) | | | 2,469 | | | Changes in Assets and Liabilities which Provided (Used) | | | | | | | | | | | | | | Cash Exclusive of Changes Shown Separately | | | | | | | | | | | | | | Accounts Receivable | | | (7,156 | ) | | | 17,696 | | | | 432 | | | Materials and Fuel Inventory | | | 21,744 | | | | (24,621 | ) | | | (10,176 | ) | | Accounts Payable | | | 2,612 | | | | (8,196 | ) | | | 8,164 | | | Income Taxes | | | 24,456 | | | | 14,267 | | | | (5,201 | ) | | Interest Accrued | | | 14,354 | | | | 15,956 | | | | 16,772 | | | Other Regulatory Liabilities | | | 2,788 | | | | 10,009 | | | | 7,501 | | | Taxes Other Than Income Taxes | | | 2,442 | | | | (48 | ) | | | (29 | ) | | Other | | | 2,820 | | | | 7,347 | | | | 2,817 | | | | | | | | | | | | | Net Cash Flows — Operating Activities | | $ | 342,359 | | | $ | 343,197 | | | $ | 273,767 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | UNS Energy | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | Net Income | | $ | 90,919 | | | $ | 109,975 | | | $ | 112,984 | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities | | | | | | | | | | | | | Depreciation Expense | | | 141,303 | | | | 133,832 | | | | 128,215 | | Amortization Expense | | | 35,784 | | | | 30,983 | | | | 28,094 | | Depreciation and Amortization Recorded to Fuel and O&M Expense | | | 6,622 | | | | 6,140 | | | | 5,432 | | Amortization of Deferred Debt-Related Costs included in Interest Expense | | | 3,000 | | | | 3,985 | | | | 3,753 | | Provision for Retail Customer Bad Debts | | | 2,767 | | | | 2,072 | | | | 3,724 | | Use of Renewable Energy Credits for Compliance | | | 5,935 | | | | 5,695 | | | | 4,745 | | Deferred Income Taxes | | | 60,273 | | | | 75,787 | | | | 28,142 | | Deferred Tax Valuation Allowance | | | (9 | ) | | | (272 | ) | | | 7,510 | | Pension and Retiree Expense | | | 21,856 | | | | 21,202 | | | | 19,688 | | Pension and Retiree Funding | | | (29,058 | ) | | | (28,775 | ) | | | (27,742 | ) | Share-Based Compensation Expense | | | 2,573 | | | | 2,599 | | | | 2,751 | | Excess Tax Benefit from Stock Options Exercised | | | (145 | ) | | | — | | | | (3,338 | ) | Allowance for Equity Funds Used During Construction | | | (3,464 | ) | | | (4,496 | ) | | | (4,232 | ) | Increase (Decrease) to Reflect PPFAC/PGA Recovery | | | 32,246 | | | | (4,932 | ) | | | (29,622 | ) | Competition Transition Charge Revenue Refunded | | | — | | | | (35,958 | ) | | | (10,095 | ) | Partial Write-off of Tucson to Nogales Transmission Line | | | 4,668 | | | | — | | | | — | | Liquidated Damages for Springerville Unit 3 Outage | | | 2,050 | | | | — | | | | — | | Gain on Settlement of El Paso Electric Dispute | | | — | | | | (7,391 | ) | | | — | | Loss on Millennium’s Investments | | | — | | | | — | | | | 9,936 | | Changes in Assets and Liabilities which Provided (Used) | | | | | | | | | | | | | Cash Exclusive of Changes Shown Separately | | | | | | | | | | | | | Accounts Receivable | | | 3,369 | | | | 2,743 | | | | (8,851 | ) | Materials and Fuel Inventory | | | (39,429 | ) | | | (20,864 | ) | | | 21,744 | | Accounts Payable | | | 595 | | | | 8,792 | | | | 2,661 | | Income Taxes | | | (11,557 | ) | | | (2,739 | ) | | | 24,470 | | Interest Accrued | | | 6,922 | | | | 14,344 | | | | 14,354 | | Taxes Other Than Income Taxes | | | (58 | ) | | | 2,857 | | | | 2,442 | | Current Regulatory Liabilities | | | (684 | ) | | | 2,644 | | | | 2,788 | | Other | | | 11,631 | | | | 19,097 | | | | 7,367 | | | | | | | | | | | | | | | Net Cash Flows – Operating Activities | | $ | 348,109 | | | $ | 337,320 | | | $ | 346,920 | | | | | | | | | | | | | | |
K-163
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) | | | | | | | | | | | | | | | | | TEP | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Thousands of Dollars- | | Net Income | | $ | 106,978 | | | $ | 89,248 | | | $ | 4,363 | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities | | | | | | | | | | | | | | Depreciation Expense | | | 99,510 | | | | 116,970 | | | | 105,859 | | | Amortization Expense | | | 32,196 | | | | 35,931 | | | | 20,181 | | | Depreciation and Amortization Recorded to Fuel and Other O&M Expense | | | 3,855 | | | | 3,439 | | | | 5,039 | | | Amortization of Deferred Debt-Related Costs included in Interest Expense | | | 2,146 | | | | 2,364 | | | | 2,826 | | | Provision for Bad Debts | | | 2,506 | | | | 2,342 | | | | 2,957 | | | Use of Renewable Energy Credits for Compliance | | | 4,245 | | | | — | | | | — | | | California Power Exchange Provision for Wholesale Revenue Refunds | | | — | | | | 4,172 | | | | — | | | Deferred Income Taxes | | | 26,017 | | | | 46,721 | | | | 24,410 | | | Pension and Postretirement Expense | | | 17,454 | | | | 21,294 | | | | 10,402 | | | Pension and Postretirement Funding | | | (25,672 | ) | | | (28,330 | ) | | | (12,439 | ) | | Stock Based Compensation Expense | | | 2,131 | | | | 2,121 | | | | 2,239 | | | Allowance for Equity Funds used During Construction | | | (3,567 | ) | | | (3,516 | ) | | | (2,950 | ) | | CTC Revenue Refunded | | | (10,095 | ) | | | (12,141 | ) | | | 58,092 | | | Decrease to Reflect PPFAC Recovery | | | (23,025 | ) | | | (20,724 | ) | | | — | | | Impact of Reapplication of Regulatory Accounting | | | — | | | | — | | | | (40,144 | ) | | Provision for Navajo Retiree Health Care and Mine Reclamation | | | — | | | | — | | | | 10,198 | | | Amortization of Transition Recovery Asset | | | — | | | | — | | | | 23,945 | | | Changes in Assets and Liabilities which Provided (Used) | | | | | | | | | | | | | | Cash Exclusive of Changes Shown Separately | | | | | | | | | | | | | | Accounts Receivable | | | (3,463 | ) | | | 9,488 | | | | 131 | | | Materials and Fuel Inventory | | | 20,920 | | | | (23,794 | ) | | | (8,774 | ) | | Accounts Payable | | | (496 | ) | | | (10,410 | ) | | | 14,812 | | | Income Taxes | | | 16,012 | | | | (2,714 | ) | | | 17,646 | | | Interest Accrued | | | 14,431 | | | | 16,142 | | | | 15,857 | | | Taxes Other Than Income Taxes | | | 1,469 | | | | 725 | | | | (1,011 | ) | | Other Regulatory Liabilities | | | 2,500 | | | | 10,555 | | | | 6,449 | | | Other | | | 11,703 | | | | 4,665 | | | | 5,668 | | | | | | | | | | | | | Net Cash Flows — Operating Activities | | $ | 297,755 | | | $ | 264,548 | | | $ | 265,756 | | | | | | | | | | | | |
Proceeds from(Continued) | | | | | | | | | | | | | | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | Net Income | | $ | 65,470 | | | $ | 85,334 | | | $ | 108,260 | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities | | | | | | | | | | | | | Depreciation Expense | | | 110,931 | | | | 104,894 | | | | 99,510 | | Amortization Expense | | | 39,493 | | | | 34,650 | | | | 32,196 | | Depreciation and Amortization Recorded to Fuel and O&M Expense | | | 5,384 | | | | 4,509 | | | | 3,855 | | Amortization of Deferred Debt-Related Costs included in Interest Expense | | | 2,227 | | | | 2,378 | | | | 2,146 | | Provision for Retail Customer Bad Debts | | | 1,871 | | | | 1,447 | | | | 2,506 | | Use of Renewable Energy Credits for Compliance | | | 5,071 | | | | 5,190 | | | | 4,245 | | Deferred Income Taxes | | | 45,232 | | | | 59,309 | | | | 24,897 | | Pension and Retiree Expense | | | 19,289 | | | | 18,816 | | | | 17,454 | | Pension and Retiree Funding | | | (25,899 | ) | | | (25,878 | ) | | | (25,672 | ) | Share-Based Compensation Expense | | | 2,029 | | | | 2,027 | | | | 2,131 | | Allowance for Equity Funds Used During Construction | | | (2,840 | ) | | | (3,842 | ) | | | (3,567 | ) | Increase (Decrease) to Reflect PPFAC Recovery | | | 31,113 | | | | (6,165 | ) | | | (21,541 | ) | Competition Transition Charge Revenue Refunded | | | — | | | | (35,958 | ) | | | (10,095 | ) | Partial Write-off of Tucson to Nogales Transmission Line | | | 4,484 | | | | — | | | | — | | Liquidated Damages for Springerville Unit 3 Outage | | | 2,050 | | | | — | | | | — | | Gain on Settlement of El Paso Electric Dispute | | | — | | | | (7,391 | ) | | | — | | Changes in Assets and Liabilities which Provided (Used) | | | | | | | | | | | | | Cash Exclusive of Changes Shown Separately | | | | | | | | | | | | | Accounts Receivable | | | (871 | ) | | | 4,809 | | | | (5,156 | ) | Materials and Fuel Inventory | | | (38,384 | ) | | | (19,789 | ) | | | 20,920 | | Accounts Payable | | | 1,115 | | | | 14,561 | | | | (447 | ) | Income Taxes | | | (11,421 | ) | | | (5,582 | ) | | | 20,203 | | Interest Accrued | | | 8,055 | | | | 14,268 | | | | 14,431 | | Taxes Other Than Income Taxes | | | 905 | | | | 2,282 | | | | 1,469 | | Current Regulatory Liabilities | | | (3,040 | ) | | | 303 | | | | 2,500 | | Other | | | 5,655 | | | | 18,122 | | | | 12,238 | | | | | | | | | | | | | | | Net Cash Flows – Operating Activities | | $ | 267,919 | | | $ | 268,294 | | | $ | 302,483 | | | | | | | | | | | | | | |
NON-CASH TRANSACTIONS In 2012, the issuancefollowing non-cash transactions occurred: UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6. In 2010, Coconino A Bonds were deposited withthe following non-cash transactions occurred: TEP used a trustee to issue and were used on December 30, 2010, to redeem $37 million of 1997 Coconino A Bonds.tax-exempt bonds. TEP had no cash receipts or payments as a result of this transaction. See Note 6; and ProceedsTEP deposited proceeds from the issuance of the 2010$100 million Pima A Bonds were depositedCounty tax-exempt IDBs in a construction fund with a trustee. TEP drew down funds as qualified expenditures were incurred. The $11 million remaining in the construction fund at December 31, 2010, affected recognized assets and liabilities but did not result in cash receipts or payments. Proceeds from TEP drew down the issuance ofremaining funds in the 2009 Pima A San Juan Bonds and the 2009 Coconino A Bonds were deposited with a trustee and were used in November 2009, to redeem approximately $80 million of 6.95% 1997 Series A City of Farmington, New Mexico Pollution Control Bonds and approximately $15 million of 7.0% 1997 Series B Coconino County, Arizona Pollution Control Bonds. TEP had no cash receipts or payments as a result of this transaction.construction fund by March 2011. See Note 6.
K-164
UNISOURCEUNS ENERGY, TEP, AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued) In 2008, TEP applied the proceeds of the 2008 Pima B bonds to redeem previously issued Pima bonds that TEP had repurchased in 2005. TEP deposited these redemption proceeds with a trustee which was subsequently applied to the payment of $128 million of principal plus $5 million of accrued interest upon maturity of the 7.5% collateral trust bonds, giving rise to a $128 million non-cash financing activity that affected recognized assets and liabilities but did not result in cash receipts or payments.
(Continued)Other 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: | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Thousands of Dollars- | | (Decrease)/Increase to Utility Plant Accruals(1) | | $ | 8,514 | | | $ | 1,082 | | | $ | (25,450 | ) | Net Cost of Removal of Interim Retirements(2) | | | 4,592 | | | | 43,381 | | | | 45,100 | | Capital Lease Obligations(3) | | | 16,630 | | | | 17,984 | | | | 16,612 | | UED Secured Term Loan Prepayments(4) | | | 3,188 | | | | 3,625 | | | | — | |
| | | | | | | | | | | | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | | | -Thousands of Dollars- | | (Decrease)/Increase to Utility Plant Accruals(1) | | $ | 4,813 | | | $ | (2,741 | ) | | $ | 8,514 | | Net Cost of Removal of Interim Retirements(2) | | | 35,983 | | | | 31,626 | | | | 4,592 | | Capital Lease Obligations(3) | | | 11,967 | | | | 15,162 | | | | 16,630 | | Asset Retirement Obligations(4) | | | 789 | | | | 7,638 | | | | (1,872 | ) | UED Secured Term Loan Prepayments(5) | | | — | | | | — | | | | 3,188 | |
| | | | (1) | | The non-cash additions to Utility Plant represent accruals for capital expenditures. |
| | (2) | | The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings. |
| | (3) | | The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments. |
| | (4) | The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations. |
| (5) | The non-cash UED Secured Term Loan prepayment represents deposits applied to $30 million of loan principal. |
NOTE 16. ACCOUNTING FOR DERIVATIVE INSTRUMENTS TRADING ACTIVITIES AND HEDGING ACTIVITIES See Note 1 for description of our related accounting policies. policies and Note 11 for information related to the fair value of derivatives.FINANCIAL IMPACT OF DERIVATIVES At December 31, 2010 and December 31, 2009, UniSourceUNS Energy and TEP had liabilities related to their cash flow hedges of $12 million as of December 31, 2012, and $7$14 million respectively. UniSource Energy and TEP had net after-tax unrealized losses on derivative activities reportedas of December 31, 2011. TEP’s power purchase swap agreement under which these hedges are entered into expires in AOCI of $6 million and $5 million in 2010 and 2008, respectively. In 2009, UniSource Energy and TEP had net2015. The after-tax unrealized gains and losses on derivative activitiescash flow hedge activity and amounts reclassified to earnings are reported in AOCIthe statements of less than $1other comprehensive income. The amounts reclassified to earnings are reported in Long Term Debt Interest Expense, Capital Leases Interest Expense, and Purchased Power Expense in the statements of income. The amounts expected to be reclassified to earnings within the next twelve months is estimated to be $2 million. K-165
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
Regulatory Treatment of Commodity Derivatives The following table disclosesWe disclose unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheetsheets as a regulatory asset or a regulatory liability rather than as a componentin the statements of AOCIother comprehensive income or in the income statement. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) to Regulatory Assets | | $ | — | | | $ | (29 | ) | | $ | 65 | | | $ | (4 | ) | | $ | (11 | ) | | $ | 19 | |
statements, as shown in the following table: | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Increase (Decrease) to Regulatory Assets /Liabilities | | $ | (21 | ) | | $ | 2 | | | $ | — | | | $ | (6 | ) | | $ | 2 | | | $ | (4 | ) |
UNS ENERGY, TEP, AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The fair valuevalues of derivative assets and liabilities were as follows: | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | TEP | | | | | December 31, | | | December 31, | | | December 31, | | | December 31, | | | | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | | | -Millions of Dollars- | | | | | Assets | | $ | 15 | | | $ | 7 | | | $ | 3 | | | $ | 1 | | | Liabilities | | | (42 | ) | | | (34 | ) | | | (7 | ) | | | (9 | ) | | | | | | | | | | | | | | | | Net Assets (Liabilities) | | $ | (27 | ) | | $ | (27 | ) | | $ | (4 | ) | | | (8 | ) | | | | | | | | | | | | | | |
Realized gains | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2012 | | | 2011 | | | | | -Millions of Dollars- | | Assets | | $ | 7 | | | $ | 14 | | | $ | 4 | | | $ | 3 | | Liabilities | | | (15 | ) | | | (43 | ) | | | (4 | ) | | | (9 | ) | | | | | | | | | | | | | | | | | | Net Assets (Liabilities) | | $ | (8 | ) | | $ | (29 | ) | | $ | — | | | $ | (6 | ) | | | | | | | | | | | | | | | | | |
Derivative assets are included in Derivative Instruments and Other Non-Current Assets on the UNS Energy balance sheet and Other Current Assets and Other Non-Current Assets on the TEP balance sheet. The realized losses on settled gas swaps that are fully recoveredrecoverable through the PPFAC or PGA. In 2010, 2009, and 2008, UniSource Energy realized losses of $23 million, $51 million and $9 million, respectively. TEP realized losses of $9 million, $29 million and $4 million in 2010, 2009, and 2008, respectively. PGA were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | Years Ended December 31, | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Realized Losses on Gas Swaps | | $ | (22 | ) | | $ | (19 | ) | | $ | (23 | ) | | $ | (10 | ) | | $ | (7 | ) | | $ | (9 | ) |
At December 31, 2010,2012, UNS Energy and TEP had contracts that will settle through the third quarter of 2015; UNS Electric had contracts that will settle through the first quarter of 2014; and UNS Gas had contracts that will settle through the fourth quarter of 2013. 2015.Other Commodity Derivatives UniSource Energy and TEP record realized and unrealized gains and losses on other energy contracts on a net basis in Wholesale Sales. In 2010, 2009, and 2008, net realized and unrealized gains and losses were less than $1 million. At December 31, 2010, UniSource Energy and TEP had no other energy contracts outstanding. At December 31, 2009, TEP had assets of $4 million and liabilities of $4 million related to other energy contracts. TEP’s other energy contracts were with an affiliated counterparty; therefore, related assets and liabilities were eliminated in the UniSource Energy financial statements.
The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial statements of UniSourceUNS Energy and TEP as follows: | | | | | | | | | | | | | | | | | 2010 | | | 2009 | | | 2008 | | | | | -Millions of Dollars- | | | Recorded in Wholesale Sales: | | | | | | | | | | | | | | Forward Power Sales | | $ | 27 | | | $ | 20 | | | $ | 17 | | | Forward Power Purchases | | | (34 | ) | | | (18 | ) | | | (17 | ) | | | | | | | | | | | | Total Sales and Purchases Not Resulting in Physical Delivery | | $ | (7 | ) | | $ | 2 | | | $ | — | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | TEP | | | | | 2012 | | | 2011 | | | 2010 | | | 2012 | | | 2011 | | | 2010 | | | | | -Millions of Dollars- | | Recorded in Wholesale Sales (1): | | | | | | | | | | | | | | | | | | | | | | | | | Forward Power Sales | | $ | 22 | | | $ | 41 | | | $ | 53 | | | $ | 5 | | | $ | 14 | | | $ | 27 | | Forward Power Purchases | | | (20 | ) | | | (46 | ) | | | (62 | ) | | | (6 | ) | | | (15 | ) | | | (34 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Total Sales and Purchases Not Resulting in Physical Delivery | | $ | 2 | | | $ | (5 | ) | | $ | (9 | ) | | $ | (1 | ) | | $ | (1 | ) | | $ | (7 | ) | | | | | | | | | | | | | | | | | | | | | | | | | |
K-166
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
DERIVATIVE VOLUMES At December 31, 2010, UniSource2012, UNS Energy had gas swaps totaling 14,351 billion British thermal units (GBtu) and power contracts totaling 2,228 Gigawatt-hours (GWh), while TEP had gas swaps totaling 14,973 Billion British thermal units (GBtu) and 6,4246,158 GBtu respectively, and power contracts totaling 4,807 Gigawatt-hours (GWh) and 1,144 GWh, respectively, which were accounted for as derivatives.820 GWh. At December 31, 2009, UniSource2011, UNS Energy had gas swaps totaling 14,856 GBtu and power contracts totaling 3,147 GWh, while TEP had gas swaps totaling 13,3216,855 GBtu and 5,658 GBtu, respectively, and power contracts totaling 3,859 GWh and 1,247 GWh, respectively, which were accounted for as derivatives. 815 GWh.CREDIT RISK ADJUSTMENT When the fair value of our derivative contracts is reflected as an asset, the counterparty owes us and this creates credit risk. We minimize our credit risk by: (1) entering into transactions with high-quality counterparties, (2) limiting our exposure to each counterparty, (3) monitoring the financial condition of the counterparties and (4) requiring collateral in accordance with the counterparty master agreements. Using a combination of market credit default swap data and historical recovery rates for bonds, we consider the impact of counterparty creditworthiness in determining the fair value of our derivatives as well as its possible effect on continued qualification for cash flow hedge accounting. At December 31, 2010, and at December 31, 2009, the impact of counterparty credit risk on the fair value of derivative asset contracts was less than $1 million. We also consider the impact of our own credit risk on instruments that are in a net liability position, after deducting collateral posted, using market credit default swap data and allocating theposition. The impact of counterparty credit risk adjustment to all individual contracts in a net liability position. At December 31, 2010, and at December 31, 2009, the impact of our own credit risk on the fair value of derivative asset contracts was less than $1 million.
$0.5 million at December 31, 2012 and December 31, 2011.CONCENTRATION OF CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP, UNS Gas and UNS ElectricWe 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-marketsubsequent measurement at fair value valuations. UNS ENERGY, TEP, UNS Gas and UNS ElectricAND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) We have contractual agreements for their energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Gas, or UNS Electric; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, TEP, UNS Gas and UNS Electricwe would have to provide certain credit enhancements in the form of cash or letters of creditLOCs to fully collateralize theirour exposure to these counterparties. K-167
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)
The following table shows the sum of the fair value of all derivative instruments under contracts with credit-risk related contingent features that are in a net liability position at December 31, 2010.2012. It also shows cash collateral and letters of creditLOCs posted and additional collateral to be posted if credit-risk related contingent features wereare triggered. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UniSource | | | | | TEP | | | UNS Gas | | | UNS Electric | | | Energy | | | | | December 31, 2010 | | | | | -Millions of Dollars- | | | Net Liability Position | | $ | 15 | | | $ | 25 | | | $ | 21 | | | $ | 61 | | | Cash Collateral Posted | | | — | | | | 3 | | | | — | | | | 3 | | | Letters of Credit | | | 1 | | | | — | | | | 13 | | | | 14 | | | Additional Collateral to Post if Contingent Features Triggered | | | 15 | | | | 23 | | | | 10 | | | | 48 | |
| | | | | | | | | | | | UNS Energy | | | TEP | | | | | December 31, 2012 | | | | | -Millions of Dollars- | | Net Liability Position | | $ | 36 | | | $ | 10 | | LOCs | | | 1 | | | | 1 | | Additional Collateral to Post if Contingent Features Triggered | | | 36 | | | | 10 | |
As of December 31, 2010,2012, TEP had $20$15 million of credit exposure to other counterparties’ creditworthiness related to its wholesale marketing and gas hedging activities, of which two counterparties individually composed greater than 10% of the total credit exposure. UNS Electric and UNS ElectricGas had $3less than $1 million of such credit exposure related to its supply and hedging contracts. UNS ENERGY, TEP, had five counterparties which individually comprise greater than 10% of the total credit exposure and UNS Electric had one. At December 31, 2010, UNS Gas had $1 million exposure to other counterparties’ creditworthiness. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED) Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. | | | | | | | | | | | | | | | | | | | | | UniSource Energy | | | | | First | | | Second | | | Third | | | Fourth | | | | | -Thousands of Dollars- | | | | | (except per share data) | | 2010 | | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 318,821 | | | $ | 339,036 | | | $ | 438,767 | | | $ | 357,053 | | | Operating Income | | | 52,917 | | | | 72,294 | | | | 123,482 | | | | 48,259 | | | Net Income | | | 19,972 | | | | 25,540 | | | | 54,883 | | | | 11,082 | | | Basic EPS | | | 0.55 | | | | 0.70 | | | | 1.50 | | | | 0.30 | | | Diluted EPS | | | 0.52 | | | | 0.65 | | | | 1.36 | | | | 0.29 | | | | | | | | | | | | | | | | | | | | 2009 | | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 312,226 | | | $ | 338,158 | | | $ | 415,138 | | | $ | 331,179 | | | Operating Income | | | 33,300 | | | | 59,090 | | | | 116,858 | | | | 43,085 | | | Net Income | | | 4,919 | | | | 31,275 | | | | 57,646 | | | | 10,418 | | | Basic EPS | | | 0.14 | | | | 0.88 | | | | 1.60 | | | | 0.29 | | | Diluted EPS | | | 0.14 | | | | 0.80 | | | | 1.45 | | | | 0.28 | |
| | | | | | | | | | | | | | | | | | | | UNS Energy | | | | First | | | Second | | | Third | | | Fourth | | | | | -Thousands of Dollars- (Except Per Share Amounts) | | 2012 | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 315,387 | | | $ | 363,997 | | | $ | 434,108 | | | $ | 348,274 | | Operating Income | | | 34,403 | | | | 68,065 | | | | 106,409 | | | | 42,918 | | Net Income | | | 6,476 | | | | 26,273 | | | | 50,664 | | | | 7,506 | | Basic EPS | | | 0.17 | | | | 0.65 | | | | 1.22 | | | | 0.18 | | Diluted EPS | | | 0.17 | | | | 0.64 | | | | 1.21 | | | | 0.18 | | 2011 | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 338,177 | | | $ | 365,141 | | | $ | 441,557 | | | $ | 333,827 | | Operating Income | | | 44,820 | | | | 71,290 | | | | 123,760 | | | | 41,837 | | Net Income | | | 13,472 | | | | 28,604 | | | | 59,712 | | | | 8,187 | | Basic EPS | | | 0.37 | | | | 0.77 | | | | 1.61 | | | | 0.22 | | Diluted EPS | | | 0.35 | | | | 0.71 | | | | 1.46 | | | | 0.22 | |
K-168
UNISOURCE ENERGY, TEP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (concluded)
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. | | | | | | | | | | | | | | | | | | | | | TEP | | | | | First | | | Second | | | Third | | | Fourth | | | | | -Thousands of Dollars- | | 2010 | | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 231,054 | | | $ | 274,617 | | | $ | 354,576 | | | $ | 264,732 | | | Operating Income | | | 36,504 | | | | 62,315 | | | | 114,373 | | | | 33,575 | | | | | | | | | | | | | | | | | | | | | Net Income | | | 10,349 | | | | 27,636 | | | | 58,993 | | | | 10,000 | | | | | | | | | | | | | | | | | | | | 2009 | | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 213,644 | | | $ | 271,918 | | | $ | 358,088 | | | $ | 255,337 | | | Operating Income | | | 18,572 | | | | 51,594 | | | | 108,055 | | | | 31,902 | | | | | | | | | | | | | | | | | | | | | Net Income (Loss) | | | (553 | ) | | | 26,507 | | | | 55,277 | | | | 8,017 | |
| | | | | | | | | | | | | | | | | | | | TEP | | | | First | | | Second | | | Third | | | Fourth | | | | | -Thousands of Dollars- | | 2012 | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 223,978 | | | $ | 299,419 | | | $ | 366,910 | | | $ | 271,353 | | Operating Income | | | 17,892 | | | | 58,211 | | | | 94,079 | | | | 30,305 | | Net Income (Loss) | | | (1,461 | ) | | | 21,910 | | | | 44,569 | | | | 452 | | 2011 | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 239,588 | | | $ | 295,233 | | | $ | 369,845 | | | $ | 251,720 | | Operating Income | | | 27,792 | | | | 62,497 | | | | 111,479 | | | | 27,640 | | Net Income | | | 4,704 | | | | 25,158 | | | | 53,912 | | | | 1,560 | |
The principal unusual items for TEP and UniSource Energy include: UniSource Energy
Millenniumfollowing tables reflect the quarterly impact of revisions on UNS Energy’s statements of income recorded impairment losses in investments of $10 million ($8 million after-tax). $5 million in losses occurred in the fourth quarter of 2010, and $5 million occurred in the second quarter of 2010. In the third quarter of 2010, Millennium wrote off $3 million of Deferred Tax Assets related to its investments.
In the second quarter of 2009, Millennium recorded a $6 million ($3.6 million after-tax) gain, on the sale of an investment.
UniSource Energy and TEP
In the fourth quarter of 2009, based on settlement discussions related to its sales to the CPX and CISO, TEP wrote off the remaining receivable balance of $2 million and accrued an additional liability of $2 million resulting in a $4 million ($2 million after-tax) reduction in net income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | UNS Energy | | | | | 2012
Three Months Ended | | | | | March 31, | | | June 30, | | | September 30, | | | | | | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | | | | | | | | | -Thousands of Dollars- | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenue | | $
| 318,874
|
| | $
| 315,387
|
| | $
| 367,171
|
| | $
| 363,997
|
| | $
| 437,261
|
| | $
| 434,108
|
| | | | | | | | | Operating Income(1) | | | 34,395 | | | | 34,403 | | | | 68,059 | | | | 68,065 | | | | 106,409 | | | | 106,409 | | | | | | | | | | | | | 2011
Three Months Ended | | | | | March 31, | | | June 30, | | | September 30, | | | December 31, | | | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | As
Reported | | | As
Revised | | | | | -Thousands of Dollars- | | Income Statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Revenue | | $ | 344,766 | | | $ | 338,177 | | | $ | 369,673 | | | $ | 365,141 | | | $ | 450,947 | | | $ | 441,557 | | | $ | 344,129 | | | $ | 333,827 | | Operating Income(1) | | | 44,820 | | | | 44,820 | | | | 71,290 | | | | 71,290 | | | | 123,760 | | | | 123,760 | | | | 41,802 | | | | 41,837 | |
K-169
| (1) | Includes immaterial reclassifications from Operating Expense to Other Expense to conform with current year presentation. |
Schedule
Valuation and Qualifying Accounts
Schedule II — II—Valuation and Qualifying Accounts — UniSource– UNS Energy | | | | | | | | | | | | | | | | | | | | | | | | | Additions- | | | | | | | | | | Description | | Beginning | | | Charged to | | | | | | | Ending | | | Year Ended December 31, | | Balance | | | Income | | | Deductions | | | Balance | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | Allowance for Doubtful Accounts(1) | | | | | | | | | | | | | | | | | | 2010 | | $ | 6 | | | $ | 4 | | | $ | 4 | | | $ | 6 | | | 2009 | | | 20 | | | | 4 | | | | 18 | | | | 6 | | 2008(2) | | | 18 | | | | 5 | | | | 3 | | | | 20 | | | | | | | | | | | | | | | | | | | | Deferred Tax Assets Valuation Allowance(3) | | | | | | | | | | | | | | | | | | 2010 | | $ | — | | | $ | 8 | | | $ | — | | | $ | 8 | |
| | | | | | | | | | | | | | | | | Description | | Beginning
Balance | | | Additions-
Charged to
Income | | | Deductions | | | Ending
Balance | | | | | -Millions of Dollars- | | Year Ended December 31, | | | | | | | | | | | | | | | | | | | | | | Reserve for Uncollectible Accounts(1) | | | | | | | | | | | | | | | | | 2012 | | $ | 16 | | | $ | 4 | | | $ | 13 | | | $ | 7 | | 2011 | | $ | 13 | | | $ | 5 | | | $ | 2 | | | $ | 16 | | 2010 | | $ | 13 | | | $ | 4 | | | $ | 4 | | | $ | 13 | | | | | | | Deferred Tax Assets Valuation Allowance(2) | | | | | | | | | | | | | | | | | 2012 | | $ | 7 | | | $ | — | | | $ | — | | | $ | 7 | | 2011 | | $ | 8 | | | $ | — | | | $ | 1 | | | $ | 7 | | 2010 | | $ | — | | | $ | 8 | | | $ | — | | | $ | 8 | | | | | | | Other(3) | | | | | | | | | | | | | | | | | 2012 | | $ | 6 | | | | | | | | | | | $ | 9 | | 2011 | | $ | 4 | | | | | | | | | | | $ | 6 | | 2010 | | $ | 2 | | | | | | | | | | | $ | 4 | |
| | | | (1) | | TEP, UNS Gas, and UNS Electric record additions to the AllowanceReserve for DoubtfulUncollectible Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. | | (2) | | Balances are related primarily to TEP Amounts include reserves for trade receivables, wholesale sales, to the CPX and CISO in 2000 and 2001. The accounts were written off in 2009 as a result of negotiations in the fourth quarter of 2009. See Note 4.in-kind transmission imbalances. |
| (3)(2) | | Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. Management believes that it is more likely than not that we will not be able to generate future capital gains to offset the capital losses related to an unregulated investment loss deferred tax asset. As a result, an $8 million valuation allowance was recorded against the deferred tax asset as of December 31, 2010. |
| (3) | Principally reserves for sales tax audits, litigation matters, and damages billable to third parties. As the Other reserves are not individually significant, additions and deductions need not be disclosed. |
Schedule II—Valuation and Qualifying Accounts Schedule II — Valuation and Qualifying Accounts — Accounts—TEP
| | | | | | | | | | | | | | | | | | | | | | | | | Additions- | | | | | | | | | | Description | | Beginning | | | Charged to | | | | | | | Ending | | | Year Ended December 31, | | Balance | | | Income | | | Deductions | | | Balance | | | | | -Millions of Dollars- | | | | | | | | | | | | | | | | | | | | Allowance for Doubtful Accounts(1) | | | | | | | | | | | | | | | | | | 2010 | | $ | 4 | | | $ | 3 | | | $ | 3 | | | $ | 4 | | | 2009 | | | 17 | | | | 2 | | | | 15 | | | | 4 | | 2008(2) | | | 17 | | | | 3 | | | | 3 | | | | 17 | |
| | | | | | | | | | | | | | | | | Description | | Beginning
Balance | | | Additions-
Charged to
Income | | | Deductions | | | Ending
Balance | | | | | -Millions of Dollars- | | Year Ended December 31, | | | | | | | | | | | | | | | | | | | | | | Reserve for Uncollectible Accounts(1) | | | | | | | | | | | | | | | | | 2012 | | $ | 14 | | | $ | 3 | | | $ | 12 | | | $ | 5 | | 2011 | | $ | 11 | | | $ | 4 | | | $ | 1 | | | $ | 14 | | 2010 | | $ | 11 | | | $ | 3 | | | $ | 3 | | | $ | 11 | | | | | | | Other(2) | | | | | | | | | | | | | | | | | 2012 | | $ | 4 | | | | | | | | | | | $ | 8 | | 2011 | | $ | 3 | | | | | | | | | | | $ | 4 | | 2010 | | $ | — | | | | | | | | | | | $ | 3 | |
| | | | (1) | | TEP records additions to the AllowanceReserve for DoubtfulUncollectible Accounts based on historical experience and any specific customer collection issues identified.Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances. |
| | (2) | | Balances are related primarily to TEPPrincipally reserves for sales tax audits, litigation matters, and damages billable to third parties. As the CPXOther reserves are not individually significant, additions and CISO in 2000 and 2001. The accounts were written off in 2009 as a result of negotiations in the fourth quarter of 2009. See Note 4.deductions need not be disclosed. |
TEP had no deferred tax assets valuation allowance in the periods presented. K-170
ITEM 9. – CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.ITEM 9A. – CONTROLS AND PROCEDURES | | | ITEM 9. | | — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| | | ITEM 9A. | | — CONTROLS AND PROCEDURES |
UniSourceUNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSourceUNS Energy and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13(a) —– 15(e) or Rule 15(d) —– 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2010.2012. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSourceUNS 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 UniSourceUNS 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, UniSourceUNS Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSourceUNS Energy and TEP’s disclosure controls and procedures are effective.
While UniSourceUNS 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 UniSourceUNS Energy or TEP’s internal control over financial reporting during the fourth quarter of 2010,2012, that has materially affected, or is reasonably likely to materially affect, UniSourceUNS Energy or TEP’s internal control over financial reporting. UniSourceUNS Energy’s and TEP’s Management’s Reports on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appear as the first two reports under Item 8 in UniSourceUNS Energy’s and TEP’s 20102012 Annual Report on Form 10-K, the Report of Independent Registered Public Accounting Firm for UniSourceUNS Energy appears as the third report under Item 8, and the Report of Independent Registered Public Accounting Firm for TEP appears as the fourth report under Item 8. | | | ITEM 9B. | | — OTHER INFORMATION |
None.
ITEM 9B. – OTHER INFORMATION K-171None.
PART III ITEM 10. – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTSDirectors – UNS Energy | | | | | | | | | | | | | Name | | Age | | | Board
Committee* | | | Director
Since | | Paul J. Bonavia | | | 61 | | | | None | | | | 2009 | | Lawrence J. Aldrich | | | 60 | | | | 2,3 | | | | 2000 | | Barbara M. Baumann | | | 57 | | | | 1,2,4 | | | | 2005 | | Larry W. Bickle | | | 67 | | | | 3,5 | | | | 1998 | | Harold W. Burlingame | | | 72 | | | | 2,3 | | | | 1998 | | Robert A. Elliott | | | 57 | | | | 1,2,3,4,5 | | | | 2003 | | Daniel W.L. Fessler | | | 71 | | | | 1,3,5 | | | | 2005 | | Louise L. Francesconi | | | 60 | | | | 1,2,4 | | | | 2008 | | Warren Y. Jobe | | | 72 | | | | 1,4,5 | | | | 2001 | | Ramiro G. Peru | | | 57 | | | | 1,2,4 | | | | 2008 | | Gregory A. Pivirotto | | | 60 | | | | 1,2,4 | | | | 2008 | | Joaquin Ruiz | | | 60 | | | | 3,5 | | | | 2005 | |
| | | ITEM 10. | | — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS |
Directors — UniSource Energy
| | | | | | | | | | | | | | | | | | | | | Board | | | Director | | | Name | | Age | | | Committee* | | | Since | | | Paul J. Bonavia | | | 59 | | | None | | | | 2009 | | | Lawrence J. Aldrich | | | 58 | | | | 2,3,5 | | | | 2000 | | | Barbara M. Baumann | | | 55 | | | | 1,2,4 | | | | 2005 | | | Larry W. Bickle | | | 65 | | | | 3,4,5 | | | | 1998 | | | Harold W. Burlingame | | | 70 | | | | 2,3,5 | | | | 1998 | | | Robert A. Elliott | | | 55 | | | | 1,2,3,4,5 | | | | 2003 | | | Daniel W.L. Fessler | | | 69 | | | | 1,3,5 | | | | 2005 | | | Louise L. Francesconi | | | 58 | | | | 1,2,4 | | | | 2008 | | | Warren Y. Jobe | | | 70 | | | | 1,2,4 | | | | 2001 | | | Ramiro G. Peru | | | 55 | | | | 1,2,4 | | | | 2008 | | | Gregory A. Pivirotto | | | 58 | | | | 1,3,4 | | | | 2008 | | | Joaquin Ruiz | | | 58 | | | | 2,3,5 | | | | 2005 | |
| (3) | | Corporate Governance and Nominating | |
| (5) | | Environmental, Safety and Security |
| | | |
Paul J. Bonavia | | Mr. Bonavia becamehas served as Chairman President and Chief Executive Officer of UniSourceUNS Energy and TEP insince January 2009.2009; he also served as President from January 2009 to December 2011. Prior to joining UniSourceUNS Energy, and TEP, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit. | | | | Lawrence J. Aldrich | | Chairman and Executive Director, Arizona Business Coalition on Health, since October 2011; President and Chief Executive Officer of University Physicians Healthcare (UPH) from 2009-2010.2009 to 2010; Senior Vice President/Corporate Operations and General Counsel for UPH from 2007 to 2008; President of Aldrich Capital Company since January 2007; Chief Operating Officer of The Critical Path Institute from 2005-2007; General Partner of Valley Ventures, LP from September 20022005 to December 2005; Managing Director and Founder of Tucson Ventures, LLC, from February 2000 to September 2002.2007. | | | | Barbara M. Baumann | | President and Owner of Cross Creek Energy Corporation since 2003; Executive Vice President of Associated Energy Managers, LLC from 2000 to 2003; former Vice President of Amoco Production Company; Director of SM Energy Company since 2002; memberMember of the Board of Trustees of theThe Putnam Mutual Funds since 2010; Director of Cody Resources since 2010. | | | | Larry W. Bickle | | Director of SM Energy Company since 1994; Retired private equity investor;investor since 2007; Managing Director of Haddington Ventures, LLC from 1997 to 2007.2007; Non-executive Chairman of Quantum Natural Gas Strategies,Storage, LLC since 2008. | | | | Harold W. Burlingame | | Executive Vice President of AT&T from 1986-2001; Senior Executive Advisor for ATT Wireless from 2001-2005; Chairman of ORC Worldwide from 2004-2010; President of IRC Foundation since December 2010; Director of Cornerstone On Demand since 2006. | | | | Robert A. Elliott | | President and owner of The Elliott Accounting Group since 1983; Vice Chairman of AAA of Arizona since 2012 and Director since 2007; Director and Corporate Secretary of Southern Arizona Community Bank from 1998-2010;1998 to 2010; Television Analyst/Pre-game Show Co-host for Fox Sports Arizona from 1998-2009; Chairman of the Board of Tucson Metropolitan Chamber of Commerce from 20021998 to 2003; Chairman of the Board of Tucson Urban League from 2003 to 2004;2009; Chairman of the Board of the Tucson Airport Authority from January 2006 to January 2007; Director of AAA since 2007; DirectorPresident and Chairman of the NBABoard of the National Basketball Retired Players Association since 2010; and2011; Director of the University of Arizona Foundation.Foundation, a philanthropic organization, since 2011. |
K-172
| | | |
Daniel W.L. Fessler | | President of the California Public Utility Commission from 1991-1996;1991 to 1996; Professor Emeritus of the University of California since 1994; Of counselCounsel for the law firm of Holland & Knight from 2003-2007;2003 to 2007; Partner in the law firm of LeBoeuf, Lamb, Greene & MacRae LLP from 1997 to 2003; previously served on the UniSourceUNS Energy and TEP boards of directors from 1998 to 2003; Managing Principal of Clear Energy Solutions, LLC since December 2004. | | | | Louise L. Francesconi | | Retired President of Raytheon Missile Systems;Systems from 1997 to 2008; Director of Stryker Corporation since July 2006; Chairman of the Board of Trustees for TMC Healthcare;Healthcare since 1999; and Director of Global Solar Energy, Inc. since 2008.from 2008 to 2011. | | | | Warren Y. Jobe | | Certified Public Accountant (licensed, but not practicing); Senior Vice President of Southern Company from 1998 to 2001; Executive Vice President and Chief Financial Officer of Georgia Power Company from 1987-1998; Director of WellPoint Health Networks, Inc. from 2003 to December 2004; Director of WellPoint, Inc. since December 2004; Trustee of RidgeWorth Funds since 2004. Director of Home Banc Corp. from 2005-2009. | | | | Ramiro G. Peru | | Executive Vice President and Chief Financial Officer of Swift Corporation from June 2007 to December 2007; Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation from October 2004 to March 2007; Senior Vice President and Chief Financial Officer of Phelps Dodge Corporation from May 1999 to September 2004; Director of WellPoint Health Networks, Inc. from 2003 to December 2004; Director of WellPoint, Inc. since December 2004; Director of Southern Peru Copper Corporation from 2002 to 2004. | | | | Gregory A. Pivirotto | | Adjunct Professor at the University of Arizona College of Law since 2013; President and Chief Executive Officer and Director of University Medical Center Corporation, in Tucson, AZ from 1994-2010; Certified Public Accountant1994 to 2010; certified public accountant since 1978; Director of Arizona Hospital & Healthcare Association from 1997 to 2005.2005; Director of Tucson Airport Authority since 2008; Member of the Advisory Board of Harris Bank since 2010. | | | | Joaquin Ruiz | | Professor of Geosciences, University of Arizona since 1983; Dean, College of Science, University of Arizona, since 2000; Executive Dean of the University of Arizona College of Letters, Arts and Science since 2009. |
| | | | | | | | | | | | | | | | | Director | | | Name | | Age | | | Since | | | Paul J. Bonavia | | | 59 | | | | 2009 | | | Michael J. DeConcini | | | 46 | | | | 2009 | | | Raymond S. Heyman | | | 55 | | | | 2009 | | | Kevin P. Larson | | | 54 | | | | 2009 | |
| | | | | Name | | Age | | Director
Since | Paul J. Bonavia | | 61 | | 2009 | Michael J. DeConcini | | 48 | | 2009 | David G. Hutchens | | 46 | | 2011 | Kevin P. Larson | | 56 | | 2009 |
| | | |
Paul J. Bonavia | | Mr. Bonavia becamehas served as Chairman President and Chief Executive Officer of UniSourceUNS Energy and TEP insince January 2009.2009; he also served as President from January 2009 to December 2011. Prior to joining UniSourceUNS Energy, and TEP, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit. | | | | Michael J. DeConcini | | Mr. DeConcini has served as Senior Vice President, Operations of UNS Energy since May 2010 and Senior Vice President and Chief Operating Officer of TEP from May 2009 to December 2011 when his title at TEP was changed to Senior Vice President, Operations. Mr. DeConcini joined TEP in 1988 and was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003. In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution. |
| | | | David G. Hutchens | | Mr. Hutchens has served as President of UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, heMr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995. | | | | Kevin P. Larson | | Mr. Larson has served as Senior Vice President and Chief Operating Officer. |
K-173
| | | |
Raymond S. Heyman
| | Mr. Heyman was elected to the positionFinancial Officer of Senior Vice President and General Counsel of TEP and UniSource Energy in September 2005. Prior to joining UniSourceUNS Energy and TEP since September 2005. Mr. Heyman was a memberLarson is also Treasurer of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC. | | | | Kevin P. Larson
| | UNS Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. He was elected 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 serves as Treasurer of both organizations. He was named Senior Vice President in September 2005.Officer. |
Executive Officers of UniSourceUNS Energy and TEP SeeItem 1. Business, Executive Officers of the Registrants. Information required by Items 401, 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UniSourceUNS Energy’s Proxy Statement relating to the 20112012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. | | | ITEM 11. | | — EXECUTIVE COMPENSATION |
ITEM 11. – EXECUTIVE COMPENSATIONInformation concerning Executive Compensation will be contained in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. | | | ITEM 12. | | — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSGeneral At February 15, 2011, UniSource13, 2013, UNS Energy had outstanding 36.641.4 million shares of Common Stock. As ofAt February 15, 2010,13, 2013, the number of shares of Common Stock beneficially owned by all directors and officers of UniSourceUNS Energy as a group amounted to approximately 3%less than 1% of the outstanding Common Stock. At February 15, 2011, UniSource13, 2013, UNS Energy owned 100% of the outstanding shares of common stock of TEP. Security Ownership of Certain Beneficial Owners Information concerning the security ownership of certain beneficial owners of UniSourceUNS Energy will be contained in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. Security Ownership of Management Information concerning the security ownership of the Directors and Executive Officers of UniSourceUNS Energy and TEP will be contained in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. K-174
Securities Authorized for Issuance Under Equity Compensation Plans Information concerning securities authorized for issuance under equity compensation plans will be contained in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. | | | ITEM 13. | | — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
ITEM 13. – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEInformation concerning certain relationships and related transactions, and director independence of UniSourceUNS Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks, and Insider Participation in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. | | | ITEM 14. | | — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
ITEM 14. – PRINCIPAL ACCOUNTANT FEES AND SERVICESInformation concerning principal accountant fees and services will be contained in UniSourceUNS Energy’s Proxy Statement relating to the 20112013 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2010,2012, which information is incorporated herein by reference. PART IV ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULE | | | ITEM 15. | | — EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
Reference is made to the Exhibit Index commencing on page 179. 167. K-175
SIGNATURES
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. | | | | | | | | | UNS ENERGY CORPORATION | | UNISOURCE ENERGY CORPORATION
| | Date: March 1, 2011February 26, 2013 | | By: | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | | | Senior Vice President and
Principal Chief Financial Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Paul J. Bonavia* | | | | | Paul J. Bonavia | | | | | Chairman of the Board President and
Principal Chief Executive Officer | | | | | | (Principal Executive Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | Principal Financial Officer | | | | | | Senior Vice President and Chief Financial Officer | | | | | (Principal Financial Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Karen G. Kissinger* | | | | | Karen G. Kissinger | | | Principal Accounting Officer | | | | | | Vice President, Controller, and Chief Compliance Officer | | | | | (Principal Accounting Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Lawrence J. Aldrich* | | | | | Lawrence J. Aldrich | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Barbara M. Baumann* | | | | | Barbara M. Baumann | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Larry W. Bickle* | | | | | Larry W. Bickle | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Harold W. Burlingame* | | | | | Harold W. Burlingame | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Robert A. Elliott* | | | | | Robert A. Elliott | | | | | Director |
| | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Daniel W.L. Fessler* | | | | | Daniel W.L. Fessler | | | | |
K-176
| | Director | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Louise L. Francesconi* | | | | | Louise L. Francesconi | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Warren Y. Jobe* | | | | | Warren Y. Jobe | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Ramiro Peru* | | | | | Ramiro Peru | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Gregory A. Pivirotto* | | | | | Gregory A. Pivirotto | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Joaquin Ruiz* | | | | | Joaquin Ruiz | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | By: | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | | | As attorney-in-fact for each
of the persons indicated | |
K-177
SIGNATURES
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 1, 2011February 26, 2013 | | By: | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | | | Senior Vice President and
Principal Chief Financial Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Paul J. Bonavia* | | | | | Paul J. Bonavia | | | | | Chairman of the Board President and
Principal Chief Executive Officer | | | | | | (Principal Executive Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | | | PrincipalSenior Vice President, Chief Financial Officer and Director | | | | | | (Principal Financial Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Karen G. Kissinger* | | | | | Karen G. Kissinger | | | Principal Accounting Officer | | | | | | Vice President, Controller, and Chief Compliance Officer | | | | | (Principal Accounting Officer) | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Michael J. DeConcini* | | | | | Michael J. DeConcini | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | | | /s/ Raymond S. Heyman* David G. Hutchens* | | | | | David G. Hutchens | | | | | Director | | | | | Date: March 1, 2011February 26, 2013 | | By: | | /s/ Kevin P. Larson | | | | | Kevin P. Larson | | | | | As attorney-in-fact for each
of the persons indicated | |
EXHIBIT INDEX K-178
EXHIBIT INDEX
| | | | | | | | *2(a) | | — | | Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc. (Form 10-K for the year ended December 31,1997, File No. 13739 — Exhibit. 2(a)). | | | | | | | 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 the year ended December 31, 1996, and as further amended byFile No. 1-5924-Exhibit No 3(a)). | | | | | *3(a)(1) | | — | | TEP Articles of Amendment filed with the ACC on September 3, 2009.2009 (Form 10-K for the year ended December 31, 2010, File No. 1-1379 – Exhibit 3(a)) | | | | | | | *3(b) | | — | | Bylaws of TEP, as amended as of August 31, 2009 (Form 10-Q for the quarter ended September 30, 2009, File No. 13739 —– Exhibit 3.1). | | | | | | | *3(c) | | — | | Amended and Restated Articles of Incorporation of UniSource Energy.UNS Energy, as amended. (Form 8-A/A,8-K, dated January 30, 1998,May 10, 2012, File No. 1-13739 —– Exhibit 2(a))3.1). | | | | | | | *3(d) | | — | | BylawsRevised and restated bylaws of UniSourceUNS Energy, as amended February 27, 2008revised and restated December 14, 2011 (Form 10-K for the year ended8-K, dated December 31, 2007,15, 2011, File No. 13739 —– Exhibit 3(b)).3.1) | | | | | | | 4(a) | | — | | Reserved. | | | | | | | *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)).) | | | | | | | *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)).) |
K-179
| | | | | | | | | *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)).) | | | | | | | *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)).) |
K-180
| | | | | | | | | *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(e)(7) | | — | | Third Supplemental Indenture of Trust, dated as of December 7, 2011, between the Apache County Authority and U.S. Bank Trust National Association, as successor trustee, relating to Industrial Development Bonds 1983 Series B (Tucson Electric Power Company Springerville Project). | | | | | *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(f)(7) | | — | | Third Supplemental Indenture of Trust, dated as of December 7, 2011, between the Apache County Authority and U.S. Bank Trust National Association, as successor trustee, relating to Industrial Development Bonds 1983 Series C (Tucson Electric Power Company Springerville Project). | | | | | 4(g) | | — | | Reserved | | | | | | | *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)).) |
| | | | | | | | | | | *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)).) |
K-181
| | | | | | | | | *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.)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.)4.1). | | | | | | | *4(i)(9) | | — | | Supplemental Indenture No. 8 creating a series of bonds designated First Mortgage Bonds, Collateral Series G, dated as of June 1, 2008. (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 —– Exhibit 4(b).). | | | | | | | *4(i)(10) | | — | | Supplemental Indenture No. 9 dated as of July 3, 2008, (Form 10-K for the year ended December 31, 2009, File No. 1-3739, Exhibit 4(i)(10)). | | | | | | | *4(i)(11) | | — | | Supplemental Indenture No. 10 creating a series of bonds designated as First Mortgage Bonds, Collateral Series H, dated as of March 1, 2010. (Form 8-K dated March 5, 2010, File No. 1-13739, Exhibit 4(b)). | | | | | | | *4(i)(12) | | — | | Supplemental Indenture No.11, dated as of November 1, 2010, between Tucson Electric Power Company and The Bank of New York Mellon, as trustee. (For(Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.5). | | | | | | | *4(i)(13) | | — | | Supplemental Indenture No. 12, dated as of December 1, 2010, between TEP and the Bank of New York Mellon, creating a series of bonds designated First Mortgage Bonds, Collateral Series J. (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(b)). |
| | | | | | | | | *4(i)(14) | | — | | Supplemental Indenture No.13, dated as of November 1, 2011, between Tucson Electric Power Company and The Bank of New York Mellon, amending terms of bonds designated First Mortgage Bonds, Collateral Series I. | | | | | *4(j)(1) | | — | | Indenture of Trust, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a)).) | | | | | *4(j)(2) | | — | | Loan Agreement, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(b)).) | | | | | *4(k)(1) | | — | | Indenture of Trust, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(c)). | | | | | *4(k)(2) | | — | | Loan Agreement, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(d)). | | | | | *4(l)(1) | | — | | Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(a)). | | | | | *4(l)(2) | | — | | Loan Agreement, dated as of September 15, 1997,March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(b)). | | | | | *4(m)(1) | | — | | Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-13739, Exhibit 4(a)). | | | | | *4(m)(2) | | — | | Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 19972012 Series A (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended September 30, 1997,8-K dated June 21, 2012, File No. 1-5924 —1-13739, Exhibit 4(a)4(b)).) | | | | | | *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).) |
K-182
| | | | | |
*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) | | — | | Reserved. | | | | | | *4(q)(1) | | — | | Amendment No. 4 to Amended and Restated TEP Credit Agreement, dated as of June 24, 2010. (Form 10-Q for the quarter ended June 30, 2010, File No. 1-13739, Exhibit 4(a)). | | | | | | *4(r)4(o)(1) | | — | | Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders. (For(Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.3). | | | | | *4(o)(2) | | — | | Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders. | | | | *4(s)4(p)(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.)99.2). |
| | | | | | | | | *4(p)(2) | | — | | Note Purchase Agreement, dated as of May 4, 2011, among UNS Gas, Inc., UniSource Energy Services, Inc., and a group of purchasers. (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.1). | | | | *4(t)4(q)(1) | | — | | Note Purchase and Guaranty Agreement dated August 5, 2008, among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 10-Q for the quarter ended June 30, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4.)4). | | | | | | *4(u)(1)4(r) | | — | | 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).Reserved. | | | | | | *4(v)4(s)(1) | | — | | Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UniSourceUNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (For(Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.1). | | | | | *4(s)(2) | | — | | Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. | | | | *4(w)4(t)(1) | | — | | Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders. (For(Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.4). |
K-183
| | | | *4(t)(2) | | — | | Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders. | | | | *4(x)4(u)(1) | | — | | Reimbursement Agreement, dated as of December 14, 2010, among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank. (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(a)). | | | | | | *4(y)4(v)(1) | | — | | Second Amended and Restated Pledge Agreement, dated as of November 9, 2010, among UniSourceUNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.2). | | | | | | *4(z)4(w)(1) | | — | | Indenture of Trust, dated as of March 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a)).) | | | | | | *4(z)4(w)(2) | | — | | Loan Agreement, dated as of March 1, 2008, between the Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(b)).) | | | | | | *4(ab)4(x)(1) | | — | | Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.SU.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(A)). | | | | | | *4(ab)4(x)(2) | | — | | Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(B)). | | | | | | *4(ab)4(x)(3) | | — | | Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and U.SU.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(C)). |
| | | | | | | | *4(ab)4(x)(4) | | — | | Loan Agreement, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(D)). | | | | | | *4(ac)(1) | | — | | UniSource Energy Development Credit Agreement, dated as of March 26, 2009, between UED and Union Bank, N.A. and the banks named therein and from time to time parties thereto. (Form 8-K dated April 1, 2009, File No. 1-13739- Exhibit 4(a)). | | | | | | *4(ac)(2) | | — | | Guaranty Agreement, dated as of March 26, 2009, made by UniSource Energy in favor of Union Bank, N.A. as Agent for each of the secured parties as defined in the UED Credit Agreement. (Form 8-K dated April 1, 2009, File No. 1-13739- Exhibit 4(b)). | | | | | | *4(ac)(3) | | — | | Amendment No. 1 to UED Credit Agreement, dated as of February 3, 2010, among UED, Union Bank, N.A. as Agent, and the banks named therein and from time to time party thereto. (Form 10-K for the year ended December 31, 2009, File No. 1-13739 Exhibit 4(aa)(9)). |
K-184
| | | | | |
*4(ad)(1) | | — | | Loan Agreement dated as of March 1, 2010, between Tucson Electric Power Company and JP Morgan Chase Bank, as Lender and Administrative Agent. (Form 8-K dated March 5, 2010, File No. 1-13739, Exhibit 4(a)). | | | | | | *4(ad)(2) | | — | | Amendment No. 1, dated as of June 24, 2010, to TEP Loan Agreement dated as of March 1, 2010. (Form 10-Q for the quarter ended June 30, 2010, File No. 1-13739, Exhibit 4(b)). | | | | | | *4(ae)4(y)(1) | | — | | Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(a)). | | | | | | *4(ae)4(y)(2) | | — | | Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(b)). | | | | | *4(z)(1) | | — | | Credit Agreement, dated as of August 10, 2011, among UNS Electric, Inc., UniSource Energy Services, Inc., and Union Bank, N.A., as Administrative Agent (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.2). | | | | | *4(aa)(1) | | — | | Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing 5.15% Notes due 2021 and 3.85% Notes due 2023 (Form 8-K dated November 8, 2011, File 1-13739 — Exhibit 4.1). | | | | | *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)).) |
K-185
| | | | | | | | | *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 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)).) |
K-186
| | | | | | | | | *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)).) |
| | | | | | | | | | | *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)).) |
K-187
| | | | | | | | | *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)).) |
| | | | | | | | | | | *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)).) |
K-188
| | | | | | | | | *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)).) |
| | | | | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(a)).) | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(b)).) | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(c)).) | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(d)).) |
K-189
| | | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(e)).) |
| | | | | | | | | | | *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. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 —– Exhibit 10(f)).) | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.1.)10.1). | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.2.)10.2). | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.3.)10.3). | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.4.)10.4). | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.5.)10.5). | | | | | | | *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. (Form 8-K dated June 12, 2006, File No. 1-5924 —– Exhibit 10.6.)10.6). | | | | | | | *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)).) |
K-190
| | | | | | | | | *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)).) |
| | | | | | | | | | | *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(h) | | — | | 1994 Omnibus Stock and Incentive Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43767.)Reserved. | | | | | | +*10(i) | | — | | Management and Directors Deferred Compensation Plan of UniSource Energy. (Form S-8 dated January 6, 1998, File No. 333-43769.)Reserved. | | | | | | +*10(j) | | — | | TEP Supplemental Retirement Account for Classified Employees. (Form S-8 dated May 21, 1998, File No. 333-53309.)Reserved. | | | | | | +*10(k) | | — | | TEP Triple Investment Plan for Salaried Employees. (Form S-8 dated May 21, 1998, File No. 333-53333.)Reserved. | | | | | | +*10(m) | | — | | 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.) (Form 10-K for the year ended December 31, 2004, File No. 1-5924 — Exhibit 10(q))Reserved. | | | | | | | +*10(n) | | — | | Amended and Restated UniSourceUNS Energy 1994 Outside Director Stock Option Plan of UniSourceUNS Energy. (Form S-8 dated September 9, 2002, File No. 333-99317.)333-99317). | | | | | | *10(o)(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.)Reserved. | | | | | | | +*10(p) | | — | | UniSourceUNS Energy 2006 Omnibus Stock and Incentive PlanPlan. (Form S-8 dated January 31, 2007.2007, File No. 333-140353.)333-140353). | | | | | | +*10(q) | | — | | Stock Option Agreement between UniSource Energy and Raymond S. Heyman dated as of September 15, 2005 (Form 10-K for the year ended December 31, 2007, File No. 1-13739, Exhibit 10(r).)Reserved. | | | | | | | +*10(r) | | — | | Management and Directors Deferred Compensation Plan II of UniSourceUNS Energy. (Form S-8 dated December 30, 2008, File No. 333-156491.)333-156491). | | | | | | +*10(s) | | — | | Letter of Employment dated as of December 9, 2008, between UniSource Energy and Paul J. Bonavia. (Form 8-K dated December 15, 2008, File No. 1-13739.)Reserved. | | | | | | | +*10(t) | | — | | Amended and Restated Officer Change in Control Agreement, dated as of October 9, 2009, between TEP and Michael J. DeConcini (including a schedule of other officers who are covered by substantially identical agreements). (Form 8-K dated October 13, 2009, File No. 1-13739 —– Exhibit 10(A)). | | | | | | +*10(u) | | — | | Officer Change in Control Agreement, dated as of October 9, 2009, between UniSource Energy Corporation and Raymond S. Heyman (Form 8-K dated October 13, 2009, File No. 1-13739 — Exhibit 10(B)).Reserved. | | | | | | | +*10(v) | | — | | Employment Agreement,UNS Energy Corporation 2011 Omnibus Stock and Incentive Plan. (Form 8-K dated May 4, 2009, between UniSource Energy and Paul J. Bonavia (Form 10-Q for the quarter ended March 31, 2009,10, 2011, File No. 13739 —1-13739 – Exhibit 4)10.1). | | | | | | | 12(a) | | — | | Computation of Ratio of Earnings to Fixed Charges — TEP. |
K-191
| | | | – UNS Energy. | | | | | 12(b) | | — | | Computation of Ratio of Earnings to Fixed Charges — UniSource Energy.– TEP. | | | | | | | 21 | | — | | Subsidiaries of the Registrants. | | | | | | 2323(a) | | — | | Consent of Independent Registered Public Accounting Firm.Firm – UNS Energy. |
| | | | | | | | | | | 23(b) | | — | | Consent of Independent Registered Public Accounting Firm – TEP. | | | | | 24(a) | | — | | Power of Attorney — UniSource– UNS Energy. | | | | | | | 24(b) | | — | | Power of Attorney —– TEP. | | | | | | | 31(a) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act — UniSource– UNS Energy, by Paul J. Bonavia. | | | | | | | 31(b) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act — UniSource– UNS Energy, by Kevin P. Larson. | | | | | | | 31(c) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act —– TEP, by Paul J. Bonavia. | | | | | | | 31(d) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act —– TEP, by Kevin P. Larson. | | | | | | | **32 | | — | | Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). |
| | | (*)***101 | | — | | The following materials from UNS Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language): | | | | | | | | | (a) | | UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Capitalization, (vi) Consolidated Statements of Changes in Stockholders’ Equity; and | | | | | | | | | (b) | | Notes to Consolidated Financial Statements. |
| (*) | Previously filed as indicated and incorporated herein by reference. | |
| (+) | | Management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601(b)(10)(iii) of Regulation S-K. | |
| ** | | Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
| *** | XBRL materials for Tucson Electric Power Company are deemed not filed or part of a registration statement or prospectus for the purposes of Section 11 or 12 of the Securities Act of 1933, as amended, and are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections. |
K-192K-181
|