TUCSON ELECTRIC POWER CO

FORM 10-K

(Annual Report)

Filed 02/28/12 for the Period Ending 12/31/11

 

Address ONE SOUTH CHURCH AVENUE

SUITE 100

TUCSON, AZ 85701

Telephone 520-571-4000

CIK 0000100122

SIC Code 4911 - Electric Services

Fiscal Year 12/31

http://www.edgar-online.com

© Copyright 2012, EDGAR Online, Inc. All Rights Reserved.

Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.
Table of Contents 

 

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

 

FORM 10-K 

(Mark One) 

 

For the fiscal year ended December 31, 2011 

OR 

 

For the transition period from to . 

 

Securities registered pursuant to Section 12(b) of the Exchange Act: 

 

Securities registered pursuant to Section 12(g) of the Exchange Act: 

 

 

Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. 

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities 

Exchange Act of 1934 (Exchange Act). 

 

 

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 

OF 1934 

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE 

ACT OF 1934 

Commission 

File Number 

Registrant; State of Incorporation; 

Address; and Telephone Number 

IRS Employer 

Identification Number 

1-13739 

 

UNISOURCE ENERGY CORPORATION 

(An Arizona Corporation) 

88 E. Broadway Boulevard 

Tucson, AZ 85701 

(520) 571-4000 

86-0786732 

1-5924 

 

TUCSON ELECTRIC POWER COMPANY 

(An Arizona Corporation) 

88 E. Broadway Boulevard 

Tucson, AZ 85701 

(520) 571-4000 

86-0062700 

Registrant Title of Each Class 

Name of Each Exchange 

on Which Registered 

UniSource Energy Corporation Common Stock, no par value New York Stock Exchange 

 

Registrant Title of Each Class 

Name of Each Exchange 

on Which Registered 

Tucson Electric Power Company Common Stock, without par value N/A 

UniSource Energy Corporation 

 

 Yes 

 No  

Tucson Electric Power Company 

 

 Yes 

 No  

UniSource Energy Corporation 

 

 Yes 

 No  

Tucson Electric Power Company 

 

 Yes 

 No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange 

Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has 

been subject to such filing requirements for the past 90 days. 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every 

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months 

(or for such shorter period that the registrant was required to submit and post such files). 

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not 

be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in 

Part III of this Form 10-K or any amendment to this Form 10-K.  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller 

reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 

of the Exchange Act. (Check one): 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 

 

The aggregate market value of UniSource Energy Corporation voting Common Stock held by non-affiliates of the registrant was 

$1,361,485,759 based on the last reported sale price thereof on the consolidated tape on June 30, 2011. 

At February 21, 2012, 37,956,169 shares of UniSource Energy Corporation Common Stock, no par value (the only class of 

Common Stock), were outstanding. 

At February 21, 2012, 32,139,434 shares of Tucson Electric Power Company’s Common Stock, no par value, were outstanding, all 

of which were held by UniSource 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 UniSource Energy Corporation’s Proxy Statement relating to the 2012 

Annual Meeting of Shareholders are incorporated by reference into Part III. 

 

 

UniSource Energy Corporation 

 

 Yes 

 No  

Tucson Electric Power Company 

 

 Yes 

 No  

UniSource Energy Corporation 

 

 Yes 

 No  

Tucson Electric Power Company 

 

 Yes 

 No  

UniSource Energy Corporation 

 

Large Accelerated Filer 

 Accelerated Filer  Non-accelerated filer  

 

Smaller Reporting Company 

 

Tucson Electric Power Company 

 

Large Accelerated Filer 

 Accelerated Filer  Non-accelerated filer  

 

Smaller Reporting Company 

 

UniSource Energy Corporation 

 

 Yes 

 No  

Tucson Electric Power Company 

 

 Yes 

 No  
Table of Contents 

Table of Contents 

 

 

i 

Definitions iv 

— PART I — 

Item 1. – Business 1 

Overview of Consolidated Business 1 

TEP 2 

Service Area and Customers 2 

Generating and Other Resources 4 

Fuel Supply 7 

Transmission Access 8 

Rates and Regulation 9 

TEP’s Utility Operating Statistics 11 

Environmental Matters 12 

UNS Gas 15 

Service Territory and Customers 15 

Gas Supply and Transmission 15 

Rates and Regulation 15 

Environmental Matters 17 

UNS Electric 17 

Service Territory and Customers 17 

Power Supply and Transmission 17 

Rates and Regulation 18 

Environmental Matters 19 

Other Non-Reportable Segments 19 

Millennium 19 

Employees 19 

Executive Officers of the Registrants 20 

SEC Reports Available on UniSource Energy’s Website 21 

Item 1A. – Risk Factors 21 

Item 1B. – Unresolved Staff Comments 27 

Item 2. – Properties 27 

TEP Properties 27 

UES Properties 28 

Item 3. – Legal Proceedings 28 

Item 4. – Mine Safety Disclosures 29 

— PART II — 

Item 5. – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity 29 

Item 6. – Selected Consolidated Financial Data 31 

UniSource Energy 31 

TEP 32 

Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations 33 

UniSource Energy Consolidated 33 

Outlook and Strategies 33 

Results of Operations 34 

Liquidity and Capital Resources 36 

Tucson Electric Power Company 41 

Results of Operations 41 

Factors Affecting Results of Operations 48 

Liquidity and Capital Resources 51 
Table of Contents 

 

 

ii 

UNS Gas 56 

Results of Operations 56 

Factors Affecting Results of Operations 57 

Liquidity and Capital Resources 58 

UNS Electric 60 

Results of Operations 60 

Factors Affecting Results of Operations 62 

Liquidity and Capital Resources 63 

Other Non-Reportable Business Segments 65 

Results of Operations 65 

Factors Affecting Results of Operations 66 

Critical Accounting Policies 66 

Recently Issued Accounting Pronouncements 70 

Safe Harbor for Forward-Looking Statements 71 

Item 7A. – Quantitative and Qualitative Disclosures about Market Risk 71 

Item 8. – Consolidated Financial Statements and Supplementary Data 77 

Management’s Reports on Internal Controls Over Financial Reporting 77 

Reports of Independent Registered Public Accounting Firm 78 

UniSource Energy Corporation 

Consolidated Statements of Income 80 

Consolidated Statements of Cash Flows 81 

Consolidated Balance Sheets 82 

Consolidated Statements of Capitalization 84 

Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income 85 

Tucson Electric Power Company 

Consolidated Statements of Income 86 

Consolidated Statements of Cash Flows 87 

Consolidated Balance Sheets 88 

Consolidated Statements of Capitalization 90 

Consolidated Statements of Changes in Stockholder’s Equity and Comprehensive Income 91 

Notes to Consolidated Financial Statements 

Note 1. Nature of Operations and Summary of Significant Accounting Policies 92 

Note 2. Regulatory Matters 101 

Note 3. Segment and Related Information 108 

Note 4. Commitments, Contingencies, and Proposed Environmental Matters 111 

Note 5. Utility Plant and Jointly-Owned Facilities 118 

Note 6. Debt, Credit Facilities, and Capital Lease Obligations 119 

Note 7. Stockholders’ Equity 125 

Note 8. Income Taxes 126 

Note 9. Employee Benefit Plans 129 

Note 10. Share-Based Compensation Plan 137 

Note 11. Fair Value Measurements 140 

Note 12. UniSource Energy Earnings Per Share (EPS) 145 

Note 13. Millennium Investments 146 

Note 14. Recently Issued Accounting Pronouncements 146 

Note 15. Supplemental Cash Flow Information 147 

Note 16. Accounting for Derivative Instruments and Hedging Activities 149 

Note 17. Quarterly Financial Data (Unaudited) 151 

Schedule II – Valuation and Qualifying Accounts 153 

Item 9. – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 154 

Item 9A. – Controls and Procedures 154 

Item 9B. – Other Information 154 
Table of Contents 

 

 

 

iii 

— PART III — 

Item 10. – Directors, Executive Officers and Corporate Governance of the Registrants 155 

Item 11. – Executive Compensation 157 

Item 12. – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 157 

Item 13. – Certain Relationships and Related Transactions and Director Independence 158 

Item 14. – Principal Accountant Fees and Services 158 

— PART IV — 

Item 15. – Exhibits and Financial Statement Schedules 158 

Signatures 159 

Exhibit Index 162 
Table of Contents 

DEFINITIONS 

The abbreviations and acronyms used in the 2011 Form 10-K are defined below: 

 

 

iv 

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 Settlement Agreement 

 

TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for 

electric retail competition 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, 2008 

ACC Arizona Corporation Commission 

AMT Alternative Minimum Tax 

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 UNSGas’ delivery costs and customer charge 

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 MWs 

CO2 Carbon dioxide 

Common Stock UniSource Energy’s common stock, without par value 

Company or UniSource Energy UniSource Energy Corporation 

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 management 

EE Standards Electric and Gas 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 nitrogenoxide; allowances can be bought and sold 

Energy The amount of power produced over a given period of time; measured in MWh 

EPA The Environmental Protection Agency 

EL Paso El Paso Electric Company 

EPNG El Paso Natural Gas Company 

ESP Energy Service Provider 

Express Line A dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service area 

FERC Federal Energy Regulatory Commission 

Fixed CTC 

 

Competition Transition Charge that was included in TEP’s retail rate for the purpose of 

recovering TEP’s TRA; approximately $58 million is being 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 

GHG Greenhouse gases 

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 
Table of Contents 

 

 

v 

IDBs Industrial development revenue or pollution control revenue bonds 

IRS Internal Revenue Service 

kWh Kilowatt-hour(s) 

kV Kilovolt(s) 

LIBOR London Interbank Offered Rate 

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 Facility 

Mark-to-Market Adjustments 

 

Forward energy sales and purchase contracts that are considered to be derivatives and are 

adjusted monthly by recording unrealized gains and losses to reflect the market prices at the 

end of each month 

Millennium Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy 

MMBtu Million British Thermal Units 

Mortgage Bonds Bonds issued under the 1992 Mortgage 

MW Megawatt(s) 

MWh Megawatt-hour(s) 

Navajo Navajo Generating Station 

NERC North American Electric Reliability Corporation 

NOx Nitrogen oxide 

NTUA Navajo Tribal Utility Authority 

O&M Operations and Maintenance Expense 

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 

PPA Power Purchase Agreement 

PPFAC Purchased Power and Fuel Adjustment Clause 

PV Photovoltaic 

RES Renewable Energy Standard and Tariff 

Reimbursement Agreement 

 

Reimbursement Agreement dated as of December 14, 2010 among TEP as borrower and a group 

of financial institutions 

Retail Margin Revenues 

 

A 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 

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 

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 reduction 

SES Southwest Energy Solutions, a wholly-owned subsidiary of Millennium 

SO2 Sulfur dioxide 

Springerville Springerville Generating Station 

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 with Springerville Unit 1 and Springerville Unit 2 

Springerville Common 

Facilities Leases 

Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville 

Common Facilities. 

Springerville Unit 1 Unit 1 of the Springerville Generating Station 

Springerville Unit 1 Leases 

 

Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in 

certain Springerville Common Facilities 
Table of Contents 

 

 

vi 

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 UniSource Energy 

TEP Credit Agreement 

 

Second Amended and Restated Credit Agreement between TEP and a syndicate of Banks, dated 

as of November 9, 2010 (as amended) 

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 

Transwestern Transwestern Pipeline Company 

Tri-State Tri-State Generation and Transmission Association 

UED 

 

UniSource Energy Development Company, a wholly-owned subsidiary of UniSource Energy, 

which engages in developing generation resources and other project development services and 

related activities 

UES 

 

UniSource Energy Services, Inc., an intermediate holding company established to own the 

operating companies (UNS Gas and UNS Electric) which acquired the Citizens Arizona gas and 

electric utility assets in 2003 

UniSource Credit Agreement 

 

Second Amended and Restated Credit Agreement between UniSource Energy and a syndicate of 

banks, dated as of November 9, 2010 (as amended) 

UniSource Energy UniSource Energy Corporation 

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 
Table of Contents 

PART I 

This combined Form 10-K is being filed separately by UniSource Energy Corporation and Tucson Electric Power Company 

(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 UniSource 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. (See Item 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, UniSource 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 

UniSource Energy is a holding company with no significant operations of its own. UniSource Energy’s operating subsidiaries are 

separate legal entities with their own assets and liabilities. UniSource Energy owns the outstanding common stock of Tucson 

Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), UniSource Energy Development Company (UED), and 

Millennium Energy Holdings, Inc. (Millennium). 

Our business includes three primary business segments: TEP; UNS Gas, Inc. (UNS Gas); and UNS Electric, Inc. (UNS Electric). 

TEP is an electric utility serving the community of Tucson, Arizona. UES provides gas and electric service to more than 30 

communities in northern and southern Arizona through its two operating subsidiaries, UNS Gas and UNS Electric. 

Other subsidiaries include UED, which developed the Black Mountain Generating Station (BMGS) in northwestern Arizona in 2008. 

The facility, which includes two natural gas-fired combustion turbines, initially provided energy to UNS Electric through a power 

sales agreement. In July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. This 

transaction did not impact UniSource Energy’s consolidated financial statements. 

Millennium has existing investments in unregulated businesses that represented less than 1% of UniSource Energy’s total assets 

as of December 31, 2011. We have no new investments planned for Millennium. Southwest Energy Solutions (SES) is a subsidiary 

of Millennium that provides supplemental labor and meter reading services to TEP, UNS Gas, and UNS Electric. 

UniSource Energy was incorporated in the state of Arizona in 1995 and obtained regulatory approval to form a holding company in 

1997. TEP and UniSource Energy exchanged shares of stock in 1998, making TEP a subsidiary of UniSource Energy. 

 

K-1 

ITEM 1. – BUSINESS 
Table of Contents 

BUSINESS SEGMENT CONTRIBUTIONS 

The table below shows the contributions to our consolidated after-tax earnings by our three business segments. 

 

 

See Note 3 for additional financial information regarding our business segments. 

References in this report to “we” and “our” are to UniSource 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 Retail Rates for retail electric and natural gas service are determined on a “cost of service” 

basis. Retail Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for our utility 

businesses to earn a reasonable return on rate base. Rate base is generally determined by reference to the original cost (net of 

depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and 

other items plus a working capital component. Over time, additions to utility plant in service increase rate base while depreciation 

and retirements of utility plant reduce rate base. 

Retail Rates charged by TEP, UNS Gas and UNS Electric also include pass-through mechanisms that allow each utility to recover 

the actual costs of its fuel, transmission, and energy purchases. 

The Federal Energy Regulatory Commission (FERC) regulates the terms and prices of transmission services and wholesale 

electricity sales, wholesale transport and purchases of natural gas and portions of our accounting practices. TEP and UNS Electric 

have FERC tariffs to sell power at market-based rates. 

TE P 

TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UniSource Energy. In 2011, 

TEP’s electric utility operations contributed 77% of UniSource Energy’s operating revenues and comprised 82% of its assets. 

SERVICE AREA AND CUSTOMERS 

TEP is a vertically integrated utility that provides regulated electric service to approximately 404,000 retail customers in 

southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately one million 

people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to 

other utilities and power marketing entities in the western United States. 

Retail Customers 

TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major 

industries served include copper mining, cement manufacturing, defense, health care, education, military bases and other 

governmental entities. TEP’s retail sales are influenced by several factors, including economic conditions, seasonal weather 

patterns, demand side management (DSM) initiatives and increasing use of energy efficient products, and opportunities for 

customers to generate their own electricity. 

 

K-2 

 2011 2010 2009 

 -Millions of DollarsTEP $ 85 $ 108 $ 91 

UNS Gas 10 9 7 

UNS Electric 18 15 11 

Other (3 ) (19 ) (3 ) 

 

Consolidated Net Income $ 110 $ 113 $ 106 

 

 

 

 

 

 

Includes: UniSource Energy parent company expenses; interest expense (net of tax) on UniSource Energy Convertible Senior 

Notes and on the UniSource Credit Agreement; Millennium; and UED. 

(1) 

(1) 
Table of Contents 

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, the retail energy consumption by customer class is expected to be similar to the historical distribution. 

 

Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2009, 

2010 and 2011, TEP’s average number of retail customers increased by less than 1% per year. 

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 Retail Rate paid by mining customers, and the mines’ 

potential development of their own electric generation resources. TEP’s kWh sales to mining customers increased by 0.3% in 2011 

and 1.4% in 2010 as a result of increased production due to high copper prices. 

We expect the number of TEP’s retail customers to increase at a rate of approximately 0.5% in 2012 and approximately 0.9% in 

2013. 

Sales Volumes 

Weak economic conditions and the implementation of energy efficiency programs have had a negative impact on electricity sales. 

In 2009 and 2010, TEP’s retail kWh sales declined by 1.4% and 0.8%, respectively. In 2011, TEP’s retail kWh sales were 0.4% 

above 2010 due in part to a 0.3% increase in the average number of retail customers. In 2012, we expect kWh sales to TEP’s retail 

customers to be near the same level as 2011. 

Energy Service Providers 

Although the ACC’s Retail Electric Competition Rules contemplated that TEP’s retail customers may be eligible to choose an 

alternative energy service provider (ESP), portions of those Rules have been invalidated by the Arizona courts and there are no 

ESPs currently authorized to provide alternative retail electric service to TEP’s customers. See Rates and Regulation, below for 

more information regarding the status of retail competition in Arizona. 

Wholesale Business 

TEP’s electric utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale 

sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand 

(except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined 

conditions. See Generating and Other Resources, Purchases and Interconnections , below. 

Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, 

using a diversified portfolio approach to provide a balance between long-term, mid-term and spot energy sales. When TEP expects 

to have excess generating capacity and energy (usually in the first, second and fourth calendar quarters), its wholesale sales 

consist primarily of two types of sales: 

Long-Term Sales 

Long-term wholesale sales contracts cover periods of more than one year. TEP typically uses its own generation to serve the 

requirements of its long-term wholesale customers. TEP currently has long-term contracts with three entities to sell energy: 

 

 

K-3 

 2011 2010 2009 

Residential 42 % 42 % 42 % 

Commercial 21 % 21 % 21 % 

Non-mining Industrial 23 % 23 % 23 % 

Mining 11 % 12 % 11 % 

Public Authority 3 % 2 % 3 % 

• 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 Palo Verde 

Market Index. Prior to June 1, 2011, TEP received an annual demand charge of approximately $22 million. 
Table of Contents 

 

Short-Term Sales 

Forward contracts commit TEP to sell a specified amount of capacity or energy at a specified price over a given period of time, 

typically for one-month, three-month or one-year periods. TEP also engages in short-term sales by selling energy in the daily or 

hourly markets at fluctuating spot market prices and making other non-firm energy sales. All revenues from short-term wholesale 

sales offset fuel and purchased power costs and are passed through to TEP retail customers. TEP uses short-term wholesale sales 

as part of its hedging strategy to reduce customer exposure to fluctuating power prices. See Rates and Regulation, below. 

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power 

Company, Factors Affecting Results of Operations, for additional discussion of TEP’s wholesale marketing activities. 

GENERATING A ND OTHER RESOURCES 

At December 31, 2011, TEP owned or leased 2,262 MW of net generating capability, as set forth in the following table: 

 

 

 

 

K-4 

• Navajo Tribal Utility Authority (NTUA) expires in December 2015. TEP serves the portion of NTUA’s load that is not served by 

the authority’s allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh per 

year. Since 2010, the price of 50% of the MWh sales to NTUA from June to September has been based on the Palo Verde 

Market Index. In 2011, approximately 12% 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. 

• Tohono O’odham Utility Authority—2 MW, expires in 2014. 

 Net 

 Unit Date Fuel Capability Operating TEP’s Share 

Generating Source No. Location In Service Type MW Agent % MW 

Springerville Station 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 Energy Facility 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 Springerville, AZ 2002-2010 Solar 6 TEP 100.0 6 

Community Solar Projects Tucson, AZ 2010 Solar 7 TEP 100.0 7 

Total TEP Capacity 2,262 

 Leased asset as of December 31, 2011. 

 Excludes 1,009 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At 

December 31, 2011, total owned capacity was 1,861 MW and leased capacity was 401 MW. 

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Springerville Generating Station 

Springerville Unit 1 is leased by TEP and Unit 2 is owned by San Carlos, a wholly-owned subsidiary of TEP. TEP’s other interests 

in the Springerville Generating Station include the Springerville Coal Handling Facilities and the Springerville Common Facilities. 

The terms of the Springerville Unit 1 Leases, which include a 50% interest in the Springerville Common Facilities, expire in 2015 

but have optional fair market value renewal and purchase provisions. In 1985, TEP sold and leased back the remaining 50% 

interest in the Springerville Common Facilities. 

In December 2011, TEP and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure to 

determine the fair market value purchase price. The formal appraisal process was completed in accordance with the Springerville 

Unit 1 lease agreements. The purchase price was determined to be $478 per kW of capacity. TEP has until September 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; TEP currently owns a 14% undivided interest in 

Springerville Unit 1. 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. 

The 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. 

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 2015 but have optional fixed-rate renewal options if certain conditions are satisfied as well as a fixed-price purchase 

provision of $120 million. 

See Note 6 and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric 

Power Company, Liquidity and Capital Resources, Contractual Obligations , for more information regarding the Springerville leases. 

Sundt Generating Station 

The Sundt Generating Station and the internal combustion turbines located in Tucson are designated as “must-run generation” 

facilities. Must-run generation units are required to run in certain circumstances to maintain distribution system reliability and to 

meet local load requirements. 

In 2010, TEP purchased 100% of the equity interest in the Sundt Unit 4 lease for approximately $51 million, redeemed the 

outstanding Sundt Unit 4 lease debt of $5 million, and terminated the lease agreement. 

Renewable Energy Resources 

Owned Resources 

As of December 31, 2011, TEP’s owned photovoltaic (PV) solar generating capacity totaled 13 MW. The Springerville Generating 

Station solar system, which is located near TEP’s Springerville coal-fired facility in eastern Arizona, includes 43,380 PV modules, 

with a total capacity of 6 MW. TEP’s remaining 7 MW of PV solar generating capacity is located in the city of Tucson. 

Power Purchase Agreements 

In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 130 MW of capacity 

from solar resources, 50 MW of capacity from wind resources and 2 MW of capacity from a landfill gas generation plant. As of 

December 31, 2011, approximately 2 MW of contracted solar resources and 50 MW of contracted wind resources were operational. 

The remaining resources are expected to be developed over the next several years. The solar PPAs contain options that would 

allow TEP to purchase all or part of the related project at a future period. See Rates and Regulation, Renewable Energy Standard 

and Tariff below for more information. 

 

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Table of Contents 

Purchases and Interconnections 

TEP purchases power from other utilities and power marketers. TEP may enter into contracts: (a) to purchase energy under longterm 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, to meet the summer peak demands of its 

retail customers. Some of these PPAs are price-indexed to natural gas prices. Due to its increasing seasonal gas and purchased 

power usage, TEP hedges a portion of its total natural gas exposure with fixed price contracts for a maximum of three years. TEP 

also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation 

outages, or when doing so is more economical than generating its own energy. 

TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. 

These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and 

reduce the amount of reserves TEP is required to carry. 

As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject 

to mandatory reliability standards that are developed and enforced by the North American Electric Reliability Corporation (NERC) 

and subject to the oversight of the FERC. TEP periodically reviews its operating policies and procedures to ensure continued 

compliance with these standards. 

Springerville Units 3 and 4 

Springerville Units 3 and 4 are each approximately 400 MW coal-fired generating facilities that are operated, but not owned by TEP. 

These facilities are located at the same site as TEP’s Springerville Units 1 and 2. The owners of Units 3 and 4 compensate TEP for 

operating the facilities and pay an allocated portion of the fixed costs related to the Springerville Common Facilities and Coal 

Handling Facilities. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson 

Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4 . 

Peak Demand and Resources 

 

 

Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand 

varies from year-to-year due to weather, economic conditions and other factors. TEP’s retail peak demand declined from 2008 to 

2010 due primarily to weak economic conditions and the implementation of energy efficiency programs. 

The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources. TEP’s total 

margin is the difference between total energy resources and coincident peak demand, and 

 

K-6 

Peak Demand 2011 2010 2009 2008 2007 

 -MWRetail Customers 2,334 2,333 2,354 2,376 2,386 

Firm Sales to Other Utilities 322 340 385 394 369 

 

Coincident Peak Demand (A) 2,656 2,673 2,739 2,770 2,755 

Total Generating Resources 2,262 2,245 2,229 2,204 2,204 

Other Resources 1,009 799 781 966 785 

 

Total TEP Resources (B) 3,271 3,044 3,010 3,170 2,989 

Total Margin (B) – (A) 615 371 271 400 234 

Reserve Margin (% of Coincident Peak Demand) 23 % 14 % 10 % 14 % 8 % 

 

 Other Resources include firm power purchases and interruptible retail and wholesale loads. Additional firm power purchases 

were made in 2009 and 2010 to displace more expensive owned gas generation. 

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the reserve margin is the ratio of margin to coincident peak demand. TEP’s reserve margin in 2011 was in compliance with 

reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC. 

Forecasted retail peak demand for 2012 is 2,269 MW, compared with actual peak demand of 2,334 MW in 2011 when cooling 

degree days exceeded the ten-year average by 4%. TEP’s 2012 estimated retail peak demand is based on normal weather 

patterns. TEP believes existing generation capacity and power purchase agreements are sufficient to meet expected demand in 

2012. 

Future Generating Resources 

TEP will add generating resources and/or import capability to meet forecasted retail and firm wholesale load. TEP anticipates that 

additional import capacity and/or additional local peaking resources of 75 to 150 MW may be required by 2018. TEP expects to add 

approximately 5 MW of new solar PV resources in 2012. 

FUEL SUPP LY 

Fuel Summary 

Fuel cost and usage information is provided below: 

 

Coal 

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and 

Colorado. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. 

The average cost per ton of coal, including transportation, for 2011, 2010 and 2009 was $46.64, $41.99, and $39.81, respectively . 

 

 

TEP Operated Generating Facilities 

TEP is the operator, and sole owner (or lessee), of the Springerville Units 1 and 2 and Sundt Unit 4. The coal supplies for 

Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects coal 

reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining 

lives. 

The coal supplies for Sundt are transported approximately 1,300 miles by railroad from Colorado. Prior to 2010, Sundt Unit 4 was 

predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with 

methane, a renewable energy resource, piped in from a nearby landfill. Since 2010, TEP has fueled Sundt Unit 4 with both coal and 

natural gas depending on which resource is most economic. In 2012, TEP expects to fuel Sundt Unit 4 with natural gas. See Note 4 

for more information. 

 

K-7 

 Average Cost per MMBtu Percentage of Total Btu 

 Consumed Consumed 

 2011 2010 2009 2011 2010 2009 

Coal $ 2.42 $ 2.23 $ 2.11 92 % 90 % 90 % 

Gas $ 5.20 $ 4.69 $ 4.51 8 % 10 % 10 % 

All Fuels $ 2.65 $ 2.47 $ 2.34 100 % 100 % 100 % 

Station Coal Supplier 

2011 Coal 

Consumption 

(tons in 000’s) 

Contract 

Expiration 

Avg. 

Sulfur 

Content Coal Obtained From (A) 

Springerville Peabody Coalsales 3,123 2020 0.9 % Lee Ranch Coal Co. 

Four Corners BHP Billiton 387 2016 0.8 % Navajo Indian Tribe 

San Juan 

 San Juan Coal Co. 1,217 2017 0.8 % 

Federal and State 

Agencies 

Navajo 

 Peabody Coalsales 529 2019 0.4 % 

Navajo and Hopi Indian 

Tribes 

Sundt Peabody Coalsales 265 2012 0.5 % Twentymile Mine 

(A) Substantially all of the suppliers’ mining leases extend at least as long as coal is being mined in economic quantities. 
Table of Contents 

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, are mine-mouth generating stations located adjacent to the coal 

reserves. Navajo, which is operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. 

The coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to 

these three jointly-owned generating facilities to be sufficient for the remaining presently estimated lives of the stations. 

Natural Gas Supply 

TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and 

purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from 

Southwest Gas Corporation under a retail tariff for North Loop’s 95 MWs of internal combustion turbines and receives distribution 

service under a transportation agreement for DeMoss Petrie, a 75 MW internal combustion turbine. TEP purchases capacity from 

El Paso Natural Gas Company (EPNG) for transportation from the San Juan and Permian Basins to its Sundt plant under a contract 

that expires in April 2013, with right-of-first-refusal for continuation thereafter. TEP also buys gas from third-party suppliers for 

Sundt and DeMoss Petrie. 

TEP purchases gas transportation for Luna from EPNG from the Permian Basin to the plant site under an agreement effective 

through January 2017, with right-of-first-refusal for continuation thereafter. TEP purchases gas for its share of Luna from various 

suppliers in the Permian Basin region. 

TRANSMISSION ACCESS 

TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers. TEP also has 

various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability, 

capacity and efficiency of its existing transmission and distribution systems. 

TEP is participating in the continuation of the 500 kV transmission line from the Pinal West substation to the Pinal Central 

substation. TEP is also in the process of obtaining permits to build a 40-mile 500-kV transmission line from the Pinal Central 

substation to the Tortolita substation northwest of Tucson to further enhance its ability to access the region’s energy 

resources. TEP expects the transmission lines to be in service in 2014. As a result of these high-voltage transmission additions, 

TEP anticipates that its ability to import energy into its service territory should 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 to Nogales, Arizona. The project development agreement was initiated in response to an order by 

the ACC to improve reliability to UNS Electric’s retail customers in Nogales and surrounding Santa Cruz County by building a 

second transmission line to Nogales. TEP received approval from the ACC for construction along a specific route in 2002. 

However, due to an impasse with the US Forest Service, UNS Electric has taken alternative steps towards improving service 

reliability in the area. 

As of December 31, 2011, TEP had capitalized $11 million related to the project, including $2 million of 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 costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving 

Santa Cruz County. 

 

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RATES AND REGULATION 

Purchased Power and Fuel Adjustment Clause 

The PPFAC allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, and the prudent 

costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward 

component and a true-up component. 

 

 

 

As part of the reconciliation of fuel and purchased power costs and PPFAC revenues, TEP credits, among other things, 100% of 

short-term wholesale revenues against the recoverable costs. 

As part of the 2008 Rate Order, TEP was required to credit $58 million of previously collected revenues to customers through the 

PPFAC. As a result, the PPFAC charge has been zero since it became effective in January 2009. As of November 2011, the $58 

million was fully refunded to customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate is approved by 

the ACC. 

In February 2012, TEP filed its annual PPFAC update report with the ACC. TEP is requesting an increase in the total PPFAC rate 

from approximately 0.5 cents per kWh to 0.8 cents per kWh. The proposed PPFAC rate includes a forward component charge of 

approximately 0.3 cents per kWh and a true-up component charge of approximately 0.5 cents per kWh. TEP’s proposed PPFAC 

rate, including the forward component, is expected to collect approximately $77 million of under-collected fuel and purchased power 

costs. If the ACC approves TEP’s PPFAC filing, it is anticipated that the new PPFAC rate would be implemented on April 1, 2012. 

Base Rate Increase Moratorium 

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. The test year to be used in TEP’s next Base Rate application must conclude no earlier than December 31, 

2011. 

Notwithstanding the Base Rate increase moratorium, Base Rates and adjustor mechanisms may be changed in emergency 

conditions beyond TEP’s control if the ACC concludes such changes are required to protect the public interest. The moratorium 

does not preclude TEP from seeking rate relief in the event of the imposition of a federal carbon tax or related regulations. 

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. The approved cost of carrying out those 

plans is recovered from retail customers through the RES surcharge. Any RES surcharge collections above or below the costs 

incurred to implement the plans are deferred and reflected in TEP’s financial statements as a regulatory asset or liability. 

In 2011, TEP spent $34 million on its 2011 RES implementation and met the 2011 renewable energy target of 3%. TEP expects to 

collect $30 million in surcharges from retail customers in 2012 to implement its RES plan and expects to meet the 2012 renewable 

energy target of 3.5%. 

 

K-9 

 

• The forward component is updated on April 1 of each year. The forward component is based on the forecasted fuel and 

purchased power costs for the 12-month period from April 1 to March 31 of the following year, less the base fuel, 

transmission, and purchased power costs 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. 

 

• For the 12 month period ending March 31, 2012, the PPFAC rate of 0.5 cents per kWh includes a forward component 

charge of 0.1 cents per kWh and the true-up component charge of 0.4 cents per kWh. 
Table of Contents 

For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, 

Tucson Electric Power Company, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff. 

Electric Energy Efficiency Standards and Decoupling

In August 2010, the ACC approved EE Standards designed to require TEP, UNS Electric and other affected electric utilities to 

implement cost-effective programs to reduce customers’ energy consumption. In 2011, TEP estimates its programs saved energy 

equal to 1.4% of its 2010 sales. In 2012, the EE Standards target total kWh savings of 3.0% of 2011 sales. The EE Standards 

increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. 

In January 2012, TEP filed a modification to its Energy Efficiency Implementation Plan with the ACC. The proposal includes a 

request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 2013. TEP’s 

proposed annual performance incentive for 2012 and 2013 ranges from $6 million to $8 million. TEP expects the ACC to issue a 

decision on this matter in the first quarter of 2012. 

The EE Standards can be met by new and existing DSM programs, direct load control programs and energy efficient building 

codes. The EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs and rates 

charged to customers for such programs are subject to annual approval by the ACC. 

Decoupling 

In December 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to 

make Arizona’s EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring 

utility Retail 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 general rate case on or after 

June 30, 2012. 

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 ESPs to compete in the retail market were 

invalidated by an Arizona Court of Appeals decision in 2005. In 2008, the ACC opened an administrative proceeding to address the 

Rules. Unless and until the ACC clarifies the Rules or authorizes alternative ESPs to provide retail electric service, and ESPs offer 

to provide energy in TEP’s service area, it is not possible for TEP’s retail customers to use alternative ESPs. We cannot predict 

what changes, if any, the ACC will make to the Rules. 

 

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TEP’S UTILITY OPERATING STATISTICS 

 

 

K-11 

 2011 2010 2009 2008 2007 

Generation and Purchased Power – kWh (000) 

Remote Generation 10,005,127 9,077,032 9,134,183 10,438,864 11,001,318 

Local Tucson Generation (Oil, Gas & Coal) 906,496 1,492,885 1,131,399 1,016,254 1,065,778 

Purchased Power 2,686,918 2,759,912 3,677,925 3,077,619 1,713,125 

 

Total Generation and Purchased Power 13,598,541 13,329,829 13,943,507 14,532,737 13,780,221 

Less Losses and Company Use 794,171 768,819 780,529 638,302 625,073 

 

Total Energy Sold 12,804,370 12,561,010 13,162,978 13,894,435 13,155,148 

Sales – kWh (000) 

Residential 3,888,011 3,869,540 3,905,696 3,852,707 4,004,797 

Commercial 1,972,526 1,963,469 1,988,356 2,034,453 2,057,982 

Industrial 2,145,163 2,138,749 2,160,946 2,263,706 2,341,025 

Mining 1,083,071 1,079,327 1,064,830 1,095,962 983,173 

Public Authorities 243,336 240,703 250,915 255,817 247,430 

 

Total – Electric Retail Sales 9,332,107 9,291,788 9,370,743 9,502,645 9,634,407 

Electric Wholesale Sales 3,472,263 3,269,222 3,792,235 4,391,790 3,520,741 

 

Total Electric Sales 12,804,370 12,561,010 13,162,978 13,894,435 13,155,148 

 

 

 

 

 

 

 

 

 

 

Operating Revenues (000) 

Residential $ 383,908 $ 372,212 $ 377,761 $ 351,079 $ 362,967 

Commercial 223,621 217,032 219,694 211,639 213,364 

Industrial 164,024 159,937 163,720 164,849 168,279 

Mining 65,720 62,112 61,033 55,619 48,707 

Public Authorities 20,024 19,128 19,865 19,146 18,332 

RES and DSM 46,633 37,767 25,443 2,781 — 

Other — — — 415 4,822 

 

Total – Electric Retail Sales 903,930 868,188 867,516 805,528 816,471 

CTC To Be Refunded — — — (58,092 ) — 

Wholesale Revenue- Long-Term 41,056 55,653 48,249 57,493 55,788 

Wholesale Revenue- Short-Term 72,798 71,435 84,410 197,754 126,732 

California Power Exchange 

Provision for Wholesale Refunds — (2,970 ) (4,172 ) — — 

Transmission 16,392 20,863 18,974 17,173 14,842 

Other Revenues 122,210 112,098 84,361 72,292 56,956 

 

Total Operating Revenues $ 1,156,386 $ 1,125,267 $ 1,099,338 $ 1,092,148 $ 1,070,789 

 

 

 

 

 

 

 

 

 

 

Customers (End of Period) 

Residential 367,396 366,217 365,157 363,861 361,945 

Commercial 36,203 35,877 35,759 35,432 34,759 

Industrial 636 635 629 633 641 

Mining 2 2 2 2 2 

Public Authorities 62 62 61 61 61 

 

Total Retail Customers 404,299 402,793 401,608 399,989 397,408 

 

 

 

 

 

 

 

 

 

 

Average Retail Revenue per kWh Sold (cents) 

Residential 9.9 9.6 9.7 9.1 9.1 

Commercial 11.3 11.1 11.0 10.4 10.4 

Industrial and Mining 7.1 6.9 7.0 6.6 6.6 

Average Retail Revenue per kWh Sold 9.7 9.3 9.3 8.5 8.5 

Average Revenue per Residential Customer $ 1,047 $ 1,018 $ 1,036 $ 968 $ 1,009 

Average kWh Sales per Residential Customer 10,606 10,579 10,708 10,621 11,129 

 
Table of Contents 

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 to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO ), 

nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $8 million in 2011, $18 million in 2010 and 

$24 million in 2009 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control 

equipment installed at San Juan described below. TEP expects to capitalize environmental compliance costs of $7 million in 2012 

and $25 million in 2013. 

TEP recorded operating expenses of $12 million in 2011, $14 million in 2010 and $13 million in 2009 related to environmental 

compliance. TEP expects to record $14 million in operating expenses related to environmental compliance in 2012. TEP may incur 

additional costs to comply with future changes in federal and state environmental laws, regulations and permit requirements at 

existing electric generating facilities. Compliance with these changes may reduce operating efficiency. 

TEP has sufficient Emission Allowances to comply with acid rain SO regulations. 

EPA Information Request 

TEP has submitted its response to the request received in 2010 from the EPA under Section 114 of the Clean Air Act for 

information regarding projects and operations at the Sundt Generating Station. TEP owns and operates all four units at Sundt. Units 

1, 2 and 3 can be operated on either natural gas or diesel oil. Unit 4 can be operated on either natural gas or coal. 

The EPA uses information obtained from such requests to determine if additional action is necessary. TEP can neither predict 

whether the EPA will take further action at Sundt nor 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 2009, the EPA entered into a consent order through which it agreed to develop rules establishing 

standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units. The EPA issued 

the final rule in December 2011. 

Navajo 

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. 

TEP’s share of the estimated capital cost of this equipment for Navajo is less than $1 million for mercury control and approximately 

$43 million if the installation of baghouses to control particulates is necessary. 

Springerville 

Based on the EPA’s final standards, mercury emission control equipment may be required at Springerville by 2015. The estimated 

capital cost of this equipment for Springerville Units 1 and 2 is approximately $5 million. The annual operating cost associated with 

the mercury emission control equipment is expected to be approximately $3 million. 

San Juan 

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final standards. 

 

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Sundt 

TEP does not anticipate the final EPA rule will have a material impact on TEP’s capital expenditures related to Sundt Unit 4. 

Four Corners 

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated 

capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control 

equipment is expected to be less than $1 million. 

Climate Change 

In 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al. v. EPA that carbon dioxide (CO ) and other 

greenhouse gases (GHGs) are air pollutants under the Clean Air Act. In 2009, the EPA issued a final Endangerment Finding stating 

that GHGs endanger public health and welfare. The EPA issued final GHG regulations for new motor vehicles in 2010, triggering 

GHG permitting requirements for power plants under the Clean Air Act. As of January 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. 

While the debate over the direction of domestic climate policy continues on the national level, several states have developed statespecific 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) which 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 2010, New Mexico adopted regulations limiting GHG emissions from power plants and providing for participation in the Western 

Climate Initiative. Several parties filed petitions to repeal those regulations and the New Mexico Environmental Improvement Board 

held hearings on the repeal petitions in November and December 2011. In February 2012, the New Mexico Environmental 

Improvement Board repealed some, but not all, of the GHG regulations and will deliberate on the repeal of the remaining 

regulations in March 2012. We cannot predict if, or when, the remaining regulations will impact the generating output or cost of 

operations at San Juan and Luna. 

Based on the competing proposals to regulate GHG emissions by federal, state, and local regulatory and legislative bodies and 

uncertainty in the regulatory and legislative processes, the scope of such requirements and initiatives and their effect on our 

operations cannot be determined at this time. 

Regional Haze Rules 

The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial 

facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies 

for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. 

Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory 

jurisdictions. The EPA is the lead regulatory agency for these plants in terms of regional haze planning. 

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other 

environmental regulations and other business considerations, could jeopardize the economic viability of the San Juan, Four 

Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. 

TEP cannot predict the ultimate outcome of these matters. 

San Juan 

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO and 

sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) 

technology with sorbent injection on all four units within five years in order to reduce NOx and control sulfuric acid emissions. San 

Juan is able to meet the FIP’s SO limit with current emissions control equipment. Based on two cost analyses commissioned by 

PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 and $200 million. 

 

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Table of Contents 

In September 2011, PNM filed a petition to review the Federal Implementation Plan with the 10th Circuit Court of Appeals 

challenging various aspects of that plan. In addition, PNM filed a request with the EPA to stay the five-year installation timeframe 

for environmental upgrades ordered by the Federal Implementation Plan until the 10th Circuit considers and rules on the petition to 

review. 

In October 2011, PNM filed a Petition for Reconsideration of the Federal Implementation Plan. PNM also filed a Request to Stay 

the effective date of the final BART Federal Implementation Plan under the Clean Air Act with the EPA. In November 2011, PNM 

filed with the 10th Circuit a Motion to Stay the Federal Implementation Plan. WildEarth Guardians, Dine Citizens against Ruining 

our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club 

were granted leave to intervene in PNM’s petition to review in the 10th Circuit. Neither the Petition in the 10th Circuit, nor the 

Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a 

separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted 

leave to intervene in that appeal. 

In October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for 

Review of the EPA’s final Federal Implementation Plan determination in the 10th Circuit and a Petition for Reconsideration of the 

rule with the EPA. In November 2011, the New Mexico Governor and Environment Department filed a motion with the 10th Circuit 

to stay the rule. These appeals and motions are all currently pending. 

Four Corners 

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that it had originally issued 

in 2010. If approved, the revised plan would require the installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the 

capital costs to install SCR is approximately $35 million. 

Navajo 

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the 

National Renewable Energy Laboratory (NREL) in partnership with the Department of the Interior and the Department of Energy. 

The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The 

report was submitted to the EPA in January 2012. A final BART rule is expected later in 2012. If the EPA determines that SCR is 

required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could 

increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated 

share of the capital expenditure for the required baghouses would be approximately $43 million. The cost of required pollution 

controls 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. 

Coal Combustion Residuals 

In 2010, the EPA published its proposed regulations governing the handling and disposal of coal ash and other coal combustion 

residuals (CCRs). The EPA has proposed regulating CCRs as either non-hazardous solid waste or hazardous waste. The 

hazardous waste alternative would require additional capital investments and operational costs associated with storage and 

handling at plants and transportation to the disposal locations. Both the hazardous waste and non-hazardous solid waste 

alternatives would require liners for new ash landfills or expansions to existing ash landfills. The rules will apply to CCRs produced 

by all of TEP’s coal-fired generating assets. San Juan may also be subject to separate regulations being drafted by the Office of 

Surface Mining Reclamation and Enforcement because it disposes of CCRs in surface mine pits. 

The EPA has not yet indicated a preference for an alternative. Each option would allow CCRs to be beneficially reused or recycled 

as components of other products. The EPA has indicated that it will issue a final rule by the end of 2012. The financial impact of this 

rulemaking to TEP, if any, cannot be determined at this time. 

 

K-14 
Table of Contents 

Ozone National Ambient Air Quality Standard 

In September 2011, President Obama ordered the EPA to withdraw its reconsideration of the 2008 National Ambient Air Quality 

Standard for Ozone. The ozone standard is scheduled to be updated in 2013 as required by the Clean Air Act. 

UNS GAS 

SERVICE TERRITORY AND CUSTOMERS 

UNS Gas is a gas distribution company serving approximately 148,000 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 60% of total revenues in 2011, while sales to other retail customer classes 

accounted for about 36% of total revenues. 

UNS Gas’ annual retail customer growth rate was less than 1% from 2009 through 2011. In 2012, we expect UNS Gas’ retail 

customer base to increase by less than 1%. 

GAS SUPPLY AN D 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. 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 began in 2009, when construction of that pipeline was completed. 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). 

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Liquidity and 

Capital Resources, Contractual Obligations, UNS Gas Supply Contracts , for more information. 

RATES AND REGUL ATION 

2011 UNS Gas Rate Filing 

Due to increases in capital and operating costs, UNS Gas filed a general rate case with the ACC in April 2011 requesting higher 

Base Rates. The proposed Retail Rates include a higher fixed service charge and a decoupling mechanism to assist in recovering 

the company’s authorized fixed costs under the EE Standards. The table below summarizes UNS Gas’ request. 

 

K-15 
Table of Contents 

 

In January 2012, the ACC Staff filed testimony recommending a Base Rate increase of $2.7 million as well as a mechanism to 

enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the ACC’s EE Standards. In February 2012, UNS 

Gas filed testimony indicating that management is willing to agree with ACC Staff’s recommendations in the context of this rate 

proceeding. Hearings before an ACC administrative law judge concluded in February 2012. UNS Gas expects the ACC to issue a 

final order in the second quarter of 2012. If the proposed Base Rate increase is approved, UNS Gas indicated that it would file a 

proposal with the ACC requesting to return the over-collected PGA bank balance to customers. See Purchased Gas Adjustor 

(PGA), below, for more information. 

2010 UNS Gas Rate Order 

Effective April 2010, UNS Gas implemented a Base Rate increase of $3 million, or 2%. 

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 surcredit. The PGA factor is a mechanism 

that calculates the twelve-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how 

much the price per therm may change in a 12-month period. The annual cap on the maximum increase in the PGA factor is $0.15 

per therm in a 12-month period. 

At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA 

surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the 

PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customers basis, UNS Gas is required to make a 

filing with the ACC to determine how the over-collected balance should be returned to customers. On December 31, 2011, the PGA 

bank balance was over-collected by $8 million on a billed-to-customers basis. 

Gas Utility Energy Efficiency Standards and Decoupling 

In August 2010, the ACC approved new Gas Utility Energy Efficiency Standards (Gas EE Standards) designed to require UNS Gas 

and other affected utilities to implement cost-effective DSM programs. In 2011, the Gas EE Standards targeted total retail therm 

savings equal to 0.5% of 2010 sales; UNS Gas estimates its total savings in 2011 were 0.25%. 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 and existing DSM programs, renewable energy technology that displaces gas, and by a 

portion of energy efficient building codes. The Gas EE Standards provide for the recovery of costs incurred to implement DSM 

programs. UNS Gas’ DSM programs and Retail Rates charged to customers for these programs are subject to ACC approval. 

In December 2010, the ACC approved a policy statement recognizing the need to adopt rate decoupling or another mechanism to 

make Arizona’s Gas EE Standards viable. For more information about decoupling, see TEP, Rates and Regulation, Electric Energy 

Efficiency Standards and Decoupling , above. 

 

K-16 

Test year – 12 months ended Dec. 31, 2010 Initial Request by UNS Gas 

Original cost rate base $184 million 

Revenue deficiency $5.6 million 

Total rate increase (over test year revenues) 3.8% 

Cost of equity 10.5% 

Actual capital structure 51% equity / 49% debt 

Weighted average cost of capital 8.7% 
Table of Contents 

ENVIRONMENTAL MATTERS 

UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by 

federal, state and local authorities. UNS Gas’ facilities are in substantial compliance with existing regulations. See Item. 1 – 

Business, TEP, Environmental Matters , for more information. 

UNS ELECTRIC 

SERVICE TERRITORY AND CUSTOMERS 

UNS Electric is a vertically integrated electric utility company serving approximately 91,000 retail customers in Mohave and Santa 

Cruz counties. These counties have a combined population of approximately 240,000. The average number of retail customers 

grew by less than 1% in 2009, 2010 and 2011. We estimate that UNS Electric’s retail customer base will increase by less than 1% 

in 2012. UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial 

customers. Peak demand for 2011 was 438 MW. 

POWER SUPPLY AND TRANSMISSION 

Purchased Energy 

UNS Electric relies on a portfolio of long, intermediate and short-term purchases to meet customer load requirements. 

Generating Resources 

UNS Electric owns and operates Black Mountain Generating Station (BMGS), a 90 MW gas-fired facility located near Kingman, 

Arizona. In July 2011, UNS Electric purchased BMGS from UED. UNS Gas purchases and transports natural gas to BMGS for UNS 

Electric under long-term natural gas transportation and sales agreements. See Rates and Regulation, 2010 UNS Electric Rate 

Order , below for more information. 

UNS Electric also owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona. Valencia consists of four 

gas and diesel-fueled combustion turbine units and provides approximately 62 MW of peaking resources. The facility is directly 

interconnected with the distribution system serving the city of Nogales and the surrounding areas. 

Renewable Energy Resources 

UNS Electric has agreed to purchase the output of a combined wind farm and solar generating facility located near Kingman. The 

above-market cost of energy purchased through the 20-year PPA will be recovered through the RES surcharge. For more 

information see Rates and Regulation, Renewable Energy Standard and Tariff below. 

Future Generating Resources 

UNS Electric invested $5 million in 2011 in company-owned solar PV capacity and expects to invest approximately $5 million 

annually from 2012 through 2014 to build about 1.25 MW per year in company-owned solar PV capacity. See Item 7. – 

Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results 

of Operations, Renewable Energy Standard and Tariff for more information. 

Transmission 

UNS Electric imports the power generated at BMGS into its Mohave County and Santa Cruz County service territories over 

Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has a network transmission service agreement for 

its primary transmission capacity with WAPA for the Parker-Davis system that expires in August 2016. UNS Electric also has a 

long-term electric point-to-point transmission capacity agreement with WAPA for the Southwest Intertie system that expires in June 

2016. 

UNS Electric plans to upgrade the existing 115 kV transmission line serving Santa Cruz County to 138 kV by October 2014 to 

improve service reliability. This upgrade is included in UNS Electric’s current capital expenditures forecast. See Item 7. – 

Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital 

Resources for more information. 

 

K-17 
Table of Contents 

RATES AND REGULATION 

2010 UNS Electric Rate Order 

In 2010, the ACC authorized a Base Rate increase of $7.4 million, or 4%, effective October 1, 2010. 

The 2010 UNS Electric Rate Order approved UNS Electric’s purchase of BMGS from UED, subject to FERC approval and other 

conditions. FERC approved the purchase in June 2011. 

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. See Item 7. – Management’s Discussion and Analysis of Financial Condition 

and Results of Operations, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff , for more 

information. 

In compliance with the 2010 Rate Order, UNS Electric expects to file a rate case in the second half of 2012. 

Purchased Power and Fuel Adjustment Clause 

The PPFAC allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges, and the 

prudent costs of contracts for hedging fuel and purchased power costs from its retail customers. The PPFAC consists of a forward 

component and a true-up component. 

 

 

Renewable Energy Standard and Tariff 

The ACC’s RES requires UNS Electric, TEP and other affected utilities to increase their use of renewable energy each year until it 

represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES 

implementation plans for review and approval by the ACC. The approved costs of carrying out those plans are recovered from retail 

customers through the RES surcharge. Any surcharge collections above or below the costs incurred to implement the plans are 

deferred and reflected in UNS Electric’s financial statements as a regulatory asset or liability. 

In 2011, UNS Electric spent $5 million on RES implementation and met the 2011 renewable energy target of 3%. UNS Electric 

expects to collect $8 million in surcharges from retail customers in 2012 to implement its RES plan and expects to meet the 2012 

renewable energy target of 3.5%. 

For more information see Power Supply and Transmission , Renewable Energy Resources, above, and Item 7. Management’s 

Discussion and Analysis, UNS Electric, Factors Affecting Results of Operations, Renewable Energy Standard and Tariff. 

Energy Efficiency Standards and Decoupling 

In 2010, the ACC approved EE Standards designed to require UNS Electric, TEP, and other affected electric utilities to implement 

cost effective DSM programs. For more information, see TEP, Rates and Regulation, Electric Energy Efficiency Standards and 

Decoupling , above. 

 

K-18 

 

• The forward component is updated on June 1 of each year. The forward component is based on the forecasted fuel, 

transmission, and purchased power costs for the 12-month period from June 1 of the current year to May 31 of the 

following year, less the base fuel, transmission, and purchased power costs embedded in Base Rates. The cap on the 

PPFAC forward component, over the 6.77 cents per kWh in Base Rates, is 1.845 cents per kWh. 

 

• The true-up component will reconcile any over/under collected amounts from the preceding 12 month period and will be 

credited to or recovered from customers in the subsequent year. 
Table of Contents 

ENVIRONMENTAL MATTERS 

UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by 

federal, state and local authorities. UNS Electric believes that its facilities are in substantial compliance with all existing regulations 

and will be in compliance with expected environmental regulations. See Item. 1 – Business, TEP, Environmental Matters , for more 

information. 

OTHER NON-REPORTABLE SEGMENTS 

Millenniu m 

As of December 31, 2011, Millennium had assets of $20 million including a $15 million note receivable (see Sabinas below), and 

cash and cash equivalents of $5 million. In total, Millennium’s assets represented less than 1% of UniSource Energy’s total 

consolidated assets. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other 

Non-Reportable Business Segments, for more information. 

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, which matures in June 2012. 

SES 

SES, a wholly owned subsidiary of Millennium, provides electrical contracting and meter reading services in Arizona, as well as 

other services at the Springerville Generating Station. 

EMPLOYEES (As of December 31, 2011) 

TEP had 1,391 employees, of which approximately 51% are represented by the International Brotherhood of Electrical Workers 

(IBEW) Local No. 1116. A collective bargaining agreement between the IBEW and TEP expires in January 2013. 

UNS Gas had 187 employees, of which 108 employees were represented by IBEW Local No. 1116 and 5 employees were 

represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2012 and 

February 2014, respectively. 

UNS Electric had 154 employees, of which 27 employees were represented by the IBEW Local No. 387 and 96 employees were 

represented by the IBEW Local No. 769. The existing agreements with the IBEW Local No. 387 and No. 769 expire in February 

2014 and June 2013, respectively. 

SES had 272 employees, of which approximately 96% are represented by unions. Of the employees represented by unions, 236 

are represented by IBEW Local No. 1116 and 25 by IBEW Local No. 570; these agreements expire on December 31, 2012, and 

May 31, 2012, respectively. 

 

K-19 
Table of Contents 

EXECUTIVE OFFICERS OF THE REGISTRANTS 

Executive Officers – UniSource Energy and TEP 

Executive Officers of UniSource Energy and TEP, who are elected annually by UniSource Energy’s Board of Directors and TEP’s 

Board of Directions, respectively, are as follows: 

 

 

 

 

 

K-20 

Name Age Position(s) Held 

Executive 

Officer Since 

Paul J. Bonavia 60 Chairman and Chief Executive Officer 2009 

David G. Hutchens 45 President 2007 

Michael J. DeConcini 47 Senior Vice President, Operations 1999 

Kevin P. Larson 55 Senior Vice President and Chief Financial Officer(1) 2000 

Philip J. Dion III 43 Vice President, Public Policy 2008 

Kentton C. Grant 53 Vice President, Finance and Rates(2) 2007 

Todd C. Hixon 45 Vice President and General Counsel 2011 

Arie Hoekstra 64 Vice President, Generation 2007 

Karen G. Kissinger 57 Vice President, Controller and Chief Compliance Officer 1998 

Thomas A. McKenna 63 Vice President, Engineering 2007 

Catherine E. Ries 52 Vice President, Human Resources 2007 

Herlinda H. Kennedy 50 Corporate Secretary 2006 

(1) Mr. Larson is also Treasurer at UniSource Energy. 

(2) Mr. Grant is also Treasurer at TEP. 

Paul J. Bonavia 

 

Mr. Bonavia has served as Chairman and Chief Executive Officer of UniSource Energy and TEP since 

January 2009; he also served as President from January 2009 to December 2011. Prior to joining 

UniSource 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 UniSource Energy and TEP since December 2011. In March 

2011, Mr. Hutchens was named Executive Vice President of UniSource 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 UniSource Energy 

and TEP. Mr. Hutchens joined TEP in 1995. 

Michael J. DeConcini 

 

Mr. DeConcini has served as Senior Vice President, Operations of UniSource 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. 

Kevin P. Larson 

 

Mr. Larson has served as Senior Vice President and Chief Financial Officer of UniSource Energy and 

TEP since September 2005. Mr. Larson is also Treasurer of UniSource 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.

Philip J. Dion III 

 

Mr. Dion has served as Vice President of Public Policy of UniSource Energy and TEP since April 

2010. Mr. Dion joined UniSource Energy in February 2008 as Vice President of Legal and 

Environmental Services. Prior to joining UniSource 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 FERC. 
Table of Contents 

 

 

 

 

 

SEC REPORTS AVAILABLE ON UNISOURCE ENERGY’S WEBSIT E 

UniSource Energy and TEP make available their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on 

Form 8-K, and all amendments to those reports as soon as reasonably practical after they electronically file them with, or furnish 

them to, the Securities and Exchange Commission (SEC). These reports are available free of charge through UniSource Energy’s 

website address: http://www.uns.com . A link from UniSource Energy’s website to these SEC reports is accessible as follows: At 

the UniSource Energy main page, select Investors from the menu shown at the top of the page; next select SEC filings from the 

menu shown on the Investor Relations page. UniSource Energy’s code of ethics, which applies to the Board of Directors and all 

officers and employees of UniSource Energy and its subsidiaries, and any amendments or any waivers made to the code of ethics, 

is also available on UniSource Energy’s website. 

Information contained at UniSource Energy’s website is not part of any report filed with the SEC by UniSource Energy or TEP. 

 

The business and financial results of UniSource Energy and TEP are subject to a number of risks and uncertainties, including those 

set forth below and in other documents we file with the SEC. These risks and uncertainties fall primarily into five major categories: 

revenues, regulatory, environmental, financial and operational. 

 

K-21 

Kentton C. Grant 

 

Mr. Grant has served as Vice President of Finance and Rates of UniSource Energy and TEP since 

January 2007. Mr. Grant also serves as Treasurer of TEP. Mr. Grant joined TEP in 1995. 

Todd C. Hixon 

 

Mr. Hixon has served as Vice President and General Counsel of UniSource 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 UniSource Energy and TEP since January 

2007. Mr. Hoekstra joined TEP in 1979 and thereafter served in various positions at TEP’s generating 

stations in Tucson and Springerville. 

Karen G. Kissinger 

 

Ms. Kissinger has served as Vice President, Controller and Principal Accounting Officer of UniSource 

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. 

Thomas A. McKenna 

 

Mr. McKenna has served as Vice President of Engineering of UniSource Energy and TEP since 

January 2007. Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of 

Millennium) in 1998. 

Catherine E. Ries 

 

Ms. Ries has served as Vice President of Human Resources of UniSource Energy and TEP since June 

2007. Prior to joining UniSource 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 UniSource Energy and TEP since September 2006. 

Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999. 

ITEM 1A. – RISK FACTORS 
Table of Contents 

REVENUES 

National and local economic conditions can have a significant impact on the results of operations, net income and cash 

flows at TEP, UNS Gas and UNS Electric. 

Economic conditions have contributed significantly to a reduction in TEP’s retail customer growth and lower energy usage by the 

company’s residential, commercial and industrial customers. As a result of weak economic conditions, TEP’s average retail 

customer base grew by less than 1% per year in 2008 through 2011 compared with average increases of approximately 2% per 

year from 2003 to 2007. In 2011, total retail kWh sales were 0.4% above 2010 levels. TEP estimates that a 1% decrease in annual 

retail sales could reduce pre-tax net income and pre-tax cash flows by approximately $6 million. 

Similar impacts were felt at UNS Gas and UNS Electric. Annual increases in the number of retail customers at both companies 

remained below 1% in 2008 through 2011 compared with average annual growth rates of 3% from 2003 to 2007. We estimate that 

a 1% decrease in annual retail sales at UNS Gas and UNS Electric could reduce pre-tax net income and pre-tax cash flows by less 

than $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. New Base Rates would not be in effect until approval by the ACC, which is not anticipated to occur before the third quarter of 

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 may have a significant 

impact on retail sales, which could negatively impact UniSource 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. Conversely, TEP’s first quarter net income is typically limited by 

relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales 

peak in the winter during home heating season. Cool summers or warm winters may reduce customer usage at all three 

companies, adversely affecting operating revenues, cash flows and net income by reducing sales. TEP estimates that a 1% 

decrease in annual retail sales could reduce pre-tax net income and pre-tax cash flows by approximately $6 million. We estimate 

that a 1% decrease in annual retail sales at UNS Gas and UNS Electric could reduce pre-tax net income and pre-tax cash flows by 

less than $1 million. 

REGULATORY 

TEP, UNS Gas and UNS Electric are subject to regulation by the ACC, which sets the companies’ Retail Rates and 

oversees many aspects of their business in ways that could negatively affect the companies’ results of operations, net 

income and cash flows. 

The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for 

staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and 

therefore its policies, are subject to change every two years. 

 

K-22 
Table of Contents 

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. UniSource 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 

UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations that may increase 

their cost of operations or expose them to environmentally-related litigation and liabilities. Many of these regulations 

could have a significant impact on TEP due to its reliance on coal as its primary fuel for energy generation. 

Numerous federal, state and local environmental laws and regulations affect present and future operations. Those laws and 

regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste and 

management of coal combustion residuals. 

These laws and regulations can contribute to higher capital, operating and other costs, particularly with regard to enforcement 

efforts focused on existing power plants and new compliance standards related to new and existing power plants. These laws and 

regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations and 

other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. 

Failure to comply with applicable laws and regulations may result in litigation, and the imposition of fines, penalties and a 

requirement for costly equipment upgrades by regulatory authorities. 

We cannot provide assurance that existing environmental laws and regulations will not be revised or that new environmental laws 

and regulations will not be adopted or become applicable to our facilities. Increased compliance costs or additional operating 

restrictions from revised or additional regulation could have an adverse effect on our results of operations, particularly if those costs 

are not fully recoverable from our ratepayers. TEP’s obligation to comply with the EPA’s BART determinations as a participant in 

the San Juan, Four Corners and Navajo plants, coupled with the financial impact of future climate change legislation, other 

environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of 

individual participants to meet their obligations and continue their participation in these plants. TEP cannot predict the ultimate 

outcome of these matters. 

TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which 

it has a minority interest and is obligated to pay similar costs at the mines that supply these generating stations. While TEP has 

recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown 

and could be substantial. 

New federal regulations to limit greenhouse gas emissions could increase TEP’s cost of operations and result in a change 

in the composition of TEP’s coal-dominated generating fleet. 

Based on the finding by the EPA in December 2009 that emissions of greenhouse gases endanger public health and welfare, the 

agency is in the process of regulating greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, 

federal and international levels to address global climate change that could also result in the regulation of carbon dioxide (CO ) 

and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our 

operations. In 2011, 73% of TEP’s total energy resources came from its coal-fueled generating facilities. 

Reductions in CO 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.

 

K-23 

2 

2 
Table of Contents 

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. 

FINANCIAL 

Volatility or disruptions in the financial markets may increase our financing costs, limit our access to the credit markets 

and increase our pension funding obligations, which may adversely affect our liquidity and our ability to carry out our 

financial strategy. 

We rely on access to the bank markets and capital markets as a significant source of liquidity and for capital requirements not 

satisfied by the cash flow from our operations. Market disruptions such as those experienced over the last four years in the United 

States and abroad may increase our cost of borrowing or adversely affect our ability to access sources of liquidity needed to 

finance our operations and satisfy our obligations as they become due. These disruptions may include turmoil in the financial 

services industry, including substantial uncertainty surrounding particular lending institutions and counterparties we do business 

with, unprecedented volatility in the markets where our outstanding securities trade, and general economic downturns in our utility 

service territories. If we are unable to access credit at competitive rates, or if our borrowing costs dramatically increase, our ability 

to finance our operations, meet our short-term obligations and execute our financial strategy could be adversely affected. 

Changing market conditions could negatively affect the market value of assets held in our pension and other postretirement 

pension plans and may increase the amount and accelerate the timing of required future funding contributions. 

UniSource Energy’s net income and cash flows can be adversely affected by rising interest rates. 

As of February 21, 2012, TEP had $215 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a 

fixed for floating interest rate swap through September 2014. The interest rates are set weekly with maximum interest rates of 20% 

on $178 million of debt obligations and 10% on the remaining $37 million. The average weekly interest rate ranged from 0.05% to 

0.34% in 2011. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase 

TEP’s interest expense by approximately $2 million.

UniSource 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 LIBOR or an Alternate 

Base Rate. Each of these agreements is a committed facility and expires in November 2016. 

If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would 

negatively impact UniSource Energy’s, TEP’s, UNS Gas’ and UNS Electric’s results of operations, net income and cash flows. 

TEP, UNS Gas and UNS Electric may be required to post margin under their power and fuel supply agreements, which 

could negatively impact their liquidity. 

TEP, UNS Gas and UNS Electric secure power and fuel supply resources to serve their respective retail customers. The 

agreements under which TEP, UNS Gas and UNS Electric contract for such resources include requirements to post credit 

enhancement in the form of cash or letters of credit under certain circumstances, including changes in market prices which affect 

contract values, or a change in 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 credit under their revolving credit agreements. 

The maximum amount TEP may use under its revolving credit facility is $200 million. As of February 21, 2012, TEP had $114 

million available to borrow under its revolving credit facility. The maximum amount UNS Gas or UNS Electric may use under their 

revolving credit facility is $70 million, so long as the combined amount drawn by 

 

K-24 
Table of Contents 

both companies does not exceed $100 million. As of February 21, 2012, UNS Gas and UNS Electric had $64 million and $70 

million, respectively, 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, 2011, TEP and UNS Electric had posted $1 

million, and $6 million, respectively, with counterparties in the form of cash or letters of credit. 

UniSource Energy and its subsidiaries have debt which could adversely affect their business and results of operations. 

UniSource Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. At December 31, 

2011, the ratio of total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UniSource 

Energy and its subsidiaries was 67%. This debt level: 

 

 

The cost of purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power 

in 2015, could require significant outlays of cash in one year, which could be difficult to finance. 

TEP leases the following generation facilities under separate sale and leaseback arrangements that expire in 2015: 

 

TEP may renew the leases or purchase the assets when the leases expire in 2015. The renewal and purchase options for 

Springerville Unit 1 are for fair market value, with the fair market value purchase price having been determined in December 2011 

through an appraisal process to be $159 million. The Springerville Coal Handling Facilities can be purchased in 2015 for a fixed 

price of $120 million. TEP also leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending 

in 2017 and 2021. Upon expiration of the Springerville Coal Handling and Common Facilities Leases (whether at the end of the 

initial term or any renewal term), TEP has the obligation under agreements with the owners of Springerville Units 3 and 4 to 

purchase such facilities. Upon acquisition by TEP, the owner of Springerville Unit 3 has the option and the owner of Springerville 

Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities and a 17% interest in the Coal Handling 

Facilities. 

Regulatory rules and other restrictions limit the ability of TEP, UNS Gas and UNS Electric to make distributions to 

UniSource Energy. 

As a holding company, UniSource Energy is dependent on the earnings and distributions of funds from its subsidiaries to service its 

debt and pay dividends to shareholders. 

Restrictions include: 

 

 

 

K-25 

 

• requires UniSource 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 UniSource 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. 

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, UNS Gas and UNS Electric are restricted from lending to affiliates or issuing securities without ACC approval; 

 

• The Federal Power Act restricts electric utilities’ ability to pay dividends out of funds that are properly included in their 

capital account. TEP has an accumulated deficit rather than positive retained earnings. Although the terms of the Federal 

Power Act are unclear, we believe there is a reasonable basis for TEP to pay dividends from current year earnings; and 
Table of Contents 

Unanticipated financing needs or reductions to net income could adversely impact our ability to comply with financial 

covenants in the UniSource Energy, TEP and UES Credit Agreements. 

The UniSource Energy, TEP and UES credit and reimbursement agreements include a maximum leverage ratio. The leverage 

ratios are calculated as the ratio of total indebtedness to total capital. The ability to comply with these covenants could be adversely 

impacted by unanticipated borrowing needs or unexpected charges to earnings or shareholder equity. In the event that we seek to 

renegotiate these provisions to provide additional flexibility, we may need to pay fees or increased interest rates on borrowings as a 

condition to any amendments or waivers. 

OPERATIONAL 

The operation of electric generating stations involves risks that could result in unplanned outages or reduced generating 

capability that could adversely affect TEP’s or UNS Electric’s results of operations, net income and cash flows. 

The operation of electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel 

supply and lower than expected levels of efficiency or operational performance. Unplanned outages, including extensions of 

planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of our business. If 

TEP’s or UNS Electric’s generating stations operate below expectations, TEP or UNS Electric could be adversely affected. 

The operation of electric transmission and distribution systems involves a risk of significant unplanned outages that 

could adversely affect TEP’s and UNS Electric’s businesses, results of operations, net income and cash flows. 

The operation of electric transmission and distribution systems involves certain risks, including equipment failure and damage 

caused by storms, fires or other hazards. Unplanned outages occur from time to time and are an inherent risk of our business. If 

TEP’s or UNS Electric’s transmission and distribution systems experience a significant failure, TEP or UNS Electric could be 

adversely affected. 

TEP could be subject to higher costs and the possibility of significant penalties as a result of mandatory transmission 

standards. 

As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including TEP, are subject 

to mandatory transmission standards developed and enforced by NERC and subject to the oversight of FERC. Compliance with 

modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply 

with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties. 

We may be subject to cyber attacks and information security risks. 

As operators of critical energy infrastructure, we may face a heightened risk of cyber attack, and our corporate and informational 

technology systems may be vulnerable to disability or failures as a result of unauthorized access due to hacking, viruses, acts of 

war or terrorism and other causes. In addition, our utility business requires access to sensitive customer data, including personal 

and credit information, in the ordinary course of business. If, despite our security measures, a significant or widely publicized 

breach occurred, we could have our operations disrupted, property damaged and customer information stolen; experience 

substantial loss of revenues, response costs and other financial loss; and be subject to increased regulation, litigation and damage 

to our reputation, any of which could have a negative impact on our business and results of operations. 

TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission lines and distributionrelated facilities, and could be required to find alternate ways to provide adequate sources of energy and maintain reliable 

service for their customers. 

TEP and UNS Electric rely on federal, state and local governmental agencies to secure right-of-way and siting permits to construct 

transmission lines and distribution-related facilities. If adequate right-of-way and siting permits to build new transmission lines 

cannot be secured: 

 

K-26 

 

• TEP, UNS Gas and UNS Electric must be in compliance with their respective debt agreements to make dividend 

payments to UniSource Energy. 
Table of Contents 

 

 

 

None. 

 

TEP PROPERTIES 

TEP’s transmission facilities, located in Arizona and New Mexico, transmit the output from TEP’s remote electric generating 

stations at Four Corners, Navajo, San Juan, Springerville and Luna to the Tucson area for use by TEP’s retail customers (see 

Item 1. Business, TEP, Generating and Other Resources ). The transmission system is interconnected at various points in Arizona 

and New Mexico with other regional utilities. TEP has arrangements with approximately 140 companies to interchange generation 

capacity and transmission of energy. 

As of December 31, 2011, TEP owned or participated in an overhead electric transmission and distribution system consisting of: 

 

 

 

 

 

TEP’s underground electric distribution system includes 4,389 cable-miles. TEP owns approximately 76% of the poles on which its 

lower voltage lines are located. Electric substation capacity consists of 103 substations with a total installed transformer capacity of 

13,266,850 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, is not subject to the lien. 

The electric generating stations (except as noted below), administrative headquarters, warehouse and service center are located 

on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located: 

 

 

 

 

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. 

Springerville is located on property owned by TEP under a long-term surface ownership agreement with the State of Arizona. 

Four Corners and Navajo are located on properties held under easements from the United States and under leases from the 

Navajo Nation, respectively. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired easements 

and leases for transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP also has acquired 

easements for transmission facilities related to San Juan, Four Corners, and Navajo across the Zuni, Navajo and Tohono O’dham 

Indian Reservations. TEP, in conjunction with PNM and Phelps Dodge, holds an undivided ownership interest in the property on 

which Luna is located. 

 

K-27 

 • 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. – UNRES OLVED STAFF COMMENTS 

ITEM 2. – PROPERTIES 

 • 512 circuit-miles of 500-kV lines; 

 • 1,088 circuit-miles of 345-kV lines; 

 • 405 circuit-miles of 138-kV lines; 

 • 479 circuit-miles of 46-kV lines; and 

 • 2,615 circuit-miles of lower voltage primary lines.

 • 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. 
Table of Contents 

TEP’s rights under these various easements and leases may be subject to defects such as: 

 

 

 

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): 

 

 

 

See Note 6 and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric 

Power Company, Liquidity and Capital Resources, Contractual Obligations , for additional information on TEP’s capital lease

obligations. 

UES PRO PERTIES 

UNS Gas 

As of December 31, 2011, UNS Gas’ transmission and distribution system consisted of approximately 31 miles of steel 

transmission mains, 4,220 miles of steel and plastic distribution piping, and 137,160 customer service lines. 

UNS Electric 

As of December 31, 2011, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-

kV transmission lines, 274 circuit-miles of 69-kV transmission lines, and 3,616 circuit-miles of underground and overhead 

distribution lines. UNS Electric also owns the 65 MW Valencia plant, the 90 MW BMGS as well as 39 substations having a total 

installed capacity of 1,494,000 kilovolt amperes. 

The gas and electric distribution and transmission facilities owned by UNS Gas and UNS Electric are located: 

 

 

 

 

Right of Way Matters 

TEP was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by 

members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines 

on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were 

requesting, among other things, that the transmission lines on these lands be removed. In June 2009, TEP and the other 

defendants filed motions to dismiss the lawsuit on procedural grounds. In March 2010, the Court granted several of the defendants’ 

motions to dismiss and entered a final judgment dismissing the case in April 2010. The plaintiffs filed a Notice of Appeal with the 

Bureau of Indian 

 

K-28 

 

• possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record 

systems of the Bureau of Indian Affairs and the American Indian tribes; 

 

• possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without 

Congressional consent; or 

 

• failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by 

the U.S. Congress, Secretary of the Interior, or other adverse claimants. 

 • 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. 

 • 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. 

ITEM 3. – LEGAL PROCEEDINGS 
Table of Contents 

Affairs (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. 

In addition, see legal proceedings described in Note 4 . 

 

Not applicable. 

PART II 

 

Stock Trading 

UniSource Energy’s common stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On 

February 21, 2012, the closing price was $37.76, with 8,339 shareholders of record. 

TEP’s common stock is wholly-owned by UniSource Energy and is not listed for trading on any stock exchange. 

Dividends 

UniSource Energy 

UniSource Energy’s Board of Directors expects to continue to pay regular quarterly cash dividends on our common stock; however, 

such dividends are subject to the Board’s evaluation of our financial condition, earnings, cash flows and dividend policy. 

On February 24, 2012, UniSource Energy declared a first quarter cash dividend of $0.43 per share on its common stock. The first 

quarter dividend, totaling approximately $16 million, will be paid March 22, 2012, to shareholders of record at the close of business 

March 12, 2012. The table below summarizes UniSource Energy’s dividends paid in 2009 through 2011. 

 

UniSource Energy is the sole shareholder of TEP’s common stock and relies on dividends from its subsidiaries, primarily TEP, to 

declare and pay dividends. The TEP Board of Directors typically declares a dividend at the end of each year. 

TEP 

TEP did not pay any dividends to UniSource Energy in 2011. TEP declared and paid cash dividends to UniSource Energy of $60 

million in 2010 and $60 million in 2009. 

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of 

December 31, 2011, 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. 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. 

 

K-29 

ITEM 4. – MINE SAFETY DISCLOSURES 

ITEM 5. – MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER 

PURCHASES OF COMMON EQUITY 

 2011 2010 2009 

Quarterly Dividend Per Common Share $ 0.42 $ 0.39 $ 0.29 

Annual Dividend Per Common Share $ 1.68 $ 1.56 $ 1.16 

Common Stock Dividends Paid $ 62 million $ 57 million $ 41 million 
Table of Contents 

UNS Gas 

UNS Gas paid dividends to UniSource Energy of $10 million in both 2011 and 2010. In February 2012, UNS Gas paid a $10 million 

dividend to UniSource Energy. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and 

various other factors. 

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no 

default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2011, 

UNS Gas was in compliance with the terms of its note purchase agreement. 

UNS Electric 

As of December 31, 2011, UNS Electric had not paid dividends to UniSource Energy. UNS Electric’s ability to pay 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, 

2011, UNS Electric was in compliance with the terms of its note purchase agreement. 

Other Non-Reportable Segments 

In 2011, 2010, and 2009 UED paid dividends to UniSource Energy of $39 million, $9 million and $30 million, respectively. Of those 

dividends paid by UED, the portions representing a return of capital were $28 million in 2011, $4 million in 2010 and $30 million in 

2009. 

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy 

Consolidated, Liquidity and Capital Resources, Dividends on Common Stock 

Common Stock Dividends and Price Ranges 

 

 

Convertible Senior Notes 

In March 2005, UniSource Energy issued $150 million of 4.50% convertible bonds due 2035. Each $1,000 of convertible bonds can 

be converted into 28.814 shares of UniSource Energy common stock at any time. The conversion ratio represents a conversion 

price of approximately $34.71 per share of common stock and is subject to adjustments including an adjustment to reduce the 

conversion price upon the payment of quarterly dividends in excess of $0.19 per share. As of February 21, 2012, there were $115 

million of convertible bonds outstanding. See Item 7.- Management’s Discussion and Analysis of Financial Condition and Results of 

Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Convertible Senior Notes, below, for more 

information. 

Issuer Purchases of Common Equity 

UniSource Energy did not purchase any of its common stock during 2011, 2010, or 2009. 

 

K-30 

 2011 2010 

Quarter: Market Price per Market Price per 

 

Share of Common 

Stock Dividends 

Share of Common 

Stock Dividends 

 High Low Declared High Low Declared 

First $ 37.74 $ 34.84 $ 0.42 $ 33.54 $ 29.13 $ 0.39 

Second 38.71 35.47 0.42 34.42 29.04 0.39 

Third 38.55 34.36 0.42 33.75 29.85 0.39 

Fourth 39.25 34.28 0.42 36.92 33.19 0.39 

 

Total $ 1.68 $ 1.56 

 

 

 

 

 UniSource Energy’s common stock price as reported by the New York Stock Exchange. 

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Table of Contents 

 

 

K-31 

ITEM 6. – SELECTED CONSOLIDATED FINANCIAL DATA 

UniSource Energy 2011 2010* 2009* 2008* 2007* 

 - In Thousands - 

 (except per share data) 

Summary of Operations 

Operating Revenues $ 1,509,515 $ 1,453,966 $ 1,397,052 $ 1,410,407 $ 1,381,660 

Net Income $ 109,975 $ 112,984 $ 105,901 $ 16,955 $ 60,712 

Basic Earnings per Share: 

Net Income $ 2.98 $ 3.10 $ 2.95 $ 0.47 $ 1.70 

Diluted Earnings per Share: 

Net Income $ 2.75 $ 2.86 $ 2.73 $ 0.53 $ 1.62 

Shares of Common Stock Outstanding 

Average 36,962 36,415 35,858 35,632 35,486 

End of Year 36,918 36,542 35,851 35,458 35,315 

Year-end Book Value per Share $ 24.07 $ 22.73 $ 21.18 $ 19.35 $ 19.65 

Cash Dividends Declared per Share $ 1.68 $ 1.56 $ 1.16 $ 0.96 $ 0.90 

 

Financial Position 

Total Utility Plant – Net $ 3,182,263 $ 2,961,498 $ 2,785,714 $ 2,617,693 $ 2,407,295 

Investments in Lease Debt and Equity $ 65,829 $ 103,844 $ 132,168 $ 126,672 $ 152,544 

Other Investments and Other Property $ 34,205 $ 61,676 $ 60,239 $ 64,096 $ 70,677 

Total Assets $ 3,985,231 $ 3,791,243 $ 3,610,065 $ 3,503,821 $ 3,189,747 

Long-Term Debt $ 1,517,373 $ 1,352,977 $ 1,307,795 $ 1,313,615 $ 993,870 

Non-Current Capital Lease Obligations 352,720 429,074 488,349 513,517 530,973 

Common Stock Equity 888,474 830,756 759,329 686,090 693,958 

 

Total Capitalization $ 2,758,567 $ 2,612,807 $ 2,555,473 $ 2,513,222 $ 2,218,801 

 

Selected Cash Flow Data 

 

Net Cash Flows From Operating Activities $ 337,320 $ 346,920 $ 347,310 $ 273,767 $ 320,642 

 

Capital Expenditures $ (374,122 ) $ (330,629 ) $ (294,020 ) $ (354,080 ) $ (243,242 ) 

Other Investing Cash Flows 47,034 25,569 (2,624 ) (95,493 ) 27,961 

 

Net Cash Flows From Investing Activities $ (327,088 ) $ (305,060 ) $ (296,644 ) $ (449,573 ) $ (215,281 ) 

 

Net Cash Flows From Financing Activities $ (1,441 ) $ (51,183 ) $ (28,916 ) $ 140,605 $ (119,229 ) 

 

Ratio of Earnings to Fixed Charges 2.46 2.64 2.48 1.28 1.71 

 

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Table of Contents 

 

 

 

 

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations. 

 

K-32 

TEP 2011 2010* 2009* 2008* 2007* 

 -Thousands of DollarsSummary of Operations 

Operating Revenues $ 1,156,386 $ 1,125,267 $ 1,099,338 $ 1,092,148 $ 1,070,789 

Net Income $ 85,334 $ 108,260 $ 90,688 $ 7,206 $ 55,591 

 

Financial Position 

Total Utility Plant – Net $ 2,650,652 $ 2,410,077 $ 2,261,325 $ 2,120,619 $ 1,957,506 

Investments in Lease Debt and Equity 65,829 103,844 132,168 126,672 152,544 

Other Investments and Other Property 32,313 43,588 31,813 31,291 35,460 

Total Assets $ 3,275,484 $ 3,075,978 $ 2,922,062 $ 2,847,408 $ 2,567,808 

Long-Term Debt $ 1,080,373 $ 1,003,615 $ 903,615 $ 903,615 $ 682,870 

Non-Current Capital Lease Obligations 352,720 429,074 488,311 513,370 530,714 

Common Stock Equity 824,943 709,884 650,591 589,613 580,512 

 

Total Capitalization $ 2,258,036 $ 2,142,573 $ 2,042,517 $ 2,006,598 $ 1,794,096 

 

Selected Cash Flow Data 

Net Cash Flows From Operating Activities $ 268,294 $ 302,483 $ 268,064 $ 265,756 $ 262,714 

 

Capital Expenditures $ (351,890 ) $ (277,309 ) $ (240,079 ) $ (291,990 ) $ (161,141 ) 

Other Investing Cash Flows 39,879 24,273 (9,522 ) (95,814 ) 25,414 

 

Net Cash Flows From Investing Activities $ (312,011 ) $ (253,036 ) $ (249,601 ) $ (387,804 ) $ (135,727 ) 

 

Net Cash Flows From Financing Activities $ 51,452 $ (51,882 ) $ (29,320 ) $ 128,713 $ (120,088 ) 

 

Ratio of Earnings to Fixed Charges 2.42 2.76 2.58 1.18 1.78 

 

* As revised. See Note 1 to the financial statements for more information. 

 Other Investing Cash Flows in 2008 includes the $133 million deposit to Trustee for Repayment of Collateral Trust Bonds. 

 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. 

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(2) 

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Table of Contents 

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for 

UniSource Energy and its three primary business segments and includes the following: 

 

 

 

 

 

 

UniSource Energy Corporation (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the 

electric generation and energy delivery business. Each of UniSource Energy’s subsidiaries is a separate legal entity with its own 

assets and liabilities. UniSource 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 UniSource Energy’s largest operating subsidiary, representing approximately 82% of 

UniSource Energy’s total assets as of December 31, 2011. TEP generates, transmits and distributes electricity to approximately 

404,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and 

power marketing entities, located primarily in the western U.S. In addition, TEP operates Springerville Unit 3 on behalf of Tri-State 

Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture 

Improvement and Power District (SRP). 

UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas 

distribution company with approximately 148,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern 

Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a regulated vertically integrated public utility with 

approximately 91,000 retail customers in Mohave and Santa Cruz counties. 

UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired 

combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In 

July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no 

impact on UniSource Energy’s consolidated financial statements. 

Millennium’s investments in unregulated businesses represent less than 1% of UniSource Energy’s assets as of December 31, 

2011. 

Our business is comprised of three reporting segments – TEP, UNS Gas, and UNS Electric. 

References to “we” and “our” are to UniSource Energy and its subsidiaries, collectively. 

UNISOURCE ENE RGY CONSOLIDATED 

OUTLOOK AND STRAT EGIES 

Our financial prospects and outlook are affected by many factors including: the TEP 2008 Rate Order that freezes Base Rates 

through 2012; national and regional economic conditions; volatility in the financial markets; environmental laws and regulations; and 

other regulatory factors. Our plans and strategies include the following: 

 

 

K-33 

ITEM 7. – MANAGEMEN T’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 

 • outlook and strategies; 

 • operating results during 2011 compared with 2010, and 2010 compared with 2009; 

 • factors which affect our results and outlook; 

 • liquidity, capital needs, capital resources, and contractual obligations; 

 • dividends; and 

 • critical accounting policies. 

 

• Focusing on our core utility businesses through operational excellence, investing in utility rate base, emphasizing customer 

satisfaction, maintaining a strong community presence, and achieving constructive regulatory outcomes.
Table of Contents 

 

 

RESULT S OF OPERATIONS 

Contribution by Business Segment 

We conduct our business through three primary business segments – TEP, UNS Gas, and UNS Electric. The table below shows 

the contributions to our consolidated after-tax earnings by these business segments. 

 

 

Revision of Prior Period Financial Statements 

In the second and third quarters of 2011, we identified errors related to amounts recorded, at their dollar value, owed to or payable 

by TEP for electricity deliveries settled in-kind or to be settled in-kind during prior years under three of our transmission 

agreements. In the second quarter of 2011, we also identified errors in prior years in the calculation of income tax expense arising 

from not treating Allowance for Equity Funds Used During Construction (AFUDC) as a permanent book to tax difference. 

We assessed the materiality of these errors on prior period financial statements and concluded they were not material to any prior 

annual or interim periods; however, the cumulative impact, if recognized in 2011, could be material to results in 2011. In 

accordance with Staff Accounting Bulletin 108 and as set forth in Note 1 to the Financial Statements in our Quarterly Report on 

Form 10-Q for the quarters ended June 30, 2011, and September 30, 2011, we revised our prior period financial statements to 

correct these errors. See Note 1 for more information. 

Executive Overview 

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; a decrease in wholesale transmission revenues; an increase in Base O&M; 

higher depreciation expense; and an increase in interest expense. Those factors were partially offset by the recognition of a gain 

related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations below for more 

information. 

 

K-34 

• 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. 

• Expanding TEP’s and UNS Electric’s portfolio of renewable energy resources and programs to meet Arizona’s Renewable 

Energy Standard 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. 

 2011 2010 2009 

TEP $ 85 $ 108 $ 91 

UNS Gas 10 9 7 

UNS Electric 18 15 11 

Other Non-Reportable Segments and Adj. (3 ) (19 ) (3 ) 

 

Consolidated Net Income $ 110 $ 113 $ 106 

 

 

 

 

 

 

Includes: UniSource Energy parent company expenses; Millennium; and UED. 

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Table of Contents 

UNS Gas and UNS Electric 

UNS Gas reported net income of $10 million in 2011 compared with net income of $9 million in 2010. See UNS Gas, Results of 

Operations, below for more information. 

UNS Electric reported net income of $18 million in 2011 compared with net income of $15 million in 2010. The increase is due in 

part to a Base Rate increase that took effect in October 2010. See UNS Electric, Results of Operations, below for more information. 

Other Non-Reportable Segments 

Millennium’s financial results are included in UniSource Energy’s Other Non-Reportable Segments. Millennium reported net income

of $2 million in 2011 compared with a net loss of $13 million in 2010. Millennium’s results in the 2010 reflect losses related to the 

write-off of deferred taxes and impairment losses. See Other Non-Reportable Segments, Results of Operations, below, for more 

information. 

2010 Compared with 2009 

TEP 

TEP reported net income of $108 million in 2010 compared with net income of $91 million in 2009. The increase was due primarily 

to: a $17 million decrease in depreciation and amortization expense resulting from a change in depreciation rates for TEP’s 

transmission assets, the purchase of Sundt Unit 4, and a decline in amortization on capital lease obligations (the decrease 

excludes adjustments made to depreciation and amortization in 2009 related to an investment in Springerville Unit 1 lease equity); 

operating benefits of $11 million related to the start of commercial operation of Springerville Unit 4 in December 2009; a $3 million 

decrease in Base O&M resulting from a decline in planned power plant maintenance outages, cost-containment efforts and lower 

pension and post retirement medical expense; and a $5 million decrease in retail margin revenues resulting from a 0.8% decrease 

in retail kWh sales. 

UNS Gas and UNS Electric 

UNS Gas reported net income of $9 million in 2010 compared with $7 million in 2009. The increase was due primarily to an 

increase in retail sales due to colder winter weather and an increase in Base Rates that took effect in April 2010. 

UNS Electric reported net income of $15 million in 2010 compared with $11 million in 2009. The increase was due primarily to an 

increase in demand from a mining customer; the addition of a new industrial customer; and an increase in Base 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. 

Other Non-Reportable Segments 

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. 

 

K-35 
Table of Contents 

O&M 

The table below summarizes the items included in UniSource Energy’s O&M expense. 

 

 

 

LIQUIDITY AND CA PITAL RESOURCES 

Liquidity 

Dividends from UniSource Energy’s subsidiaries, primarily TEP, represent the parent company’s main source of liquidity. Under 

UniSource Energy’s tax sharing agreement, subsidiaries make income tax payments to UniSource Energy, which makes payments 

on behalf of the consolidated group. The table below provides a summary of the liquidity position of UniSource Energy and each of 

its segments. 

 

 

 

 

Short-term Investments 

UniSource Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update 

this policy in response to market conditions. As of December 31, 2011, UniSource Energy’s short-term investments included highlyrated and liquid money market funds, certificates of deposit, and commercial paper. These short-term investments are classified as 

Cash and Cash Equivalents on the Balance Sheet. 

 

K-36 

 2011 2010 2009 

 -Millions of DollarsTEP Base O&M (non-GAAP) $ 237 $ 228 $ 231 

UNS Gas Base O&M (non-GAAP) 24 25 25 

UNS Electric Base O&M (non-GAAP) 20 21 21 

Consolidating Adjustments and Other (11 ) (9 ) (7 ) 

 

UniSource Energy Base O&M (non-GAAP) 270 265 270 

Reimbursed Expenses Related to Springerville Units 3 & 4 63 65 41 

Expenses Related to Customer-Funded Renewable Energy and Demand Side 

Management Programs 46 40 23 

 

Total UniSource Energy O&M (GAAP) $ 379 $ 370 $ 334 

 

 

 

 

 

 

Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in 

accordance with GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental 

level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly 

offset by revenues collected from customers and other third parties. 

 Includes Millennium, UED, and UniSource Energy stand-alone O&M, and inter-company eliminations. 

Balances as of February 21, 2012 

Cash and Cash 

Equivalents 

Borrowings under 

Revolving Credit 

Facility 

Amount Available 

under Revolving 

Credit Facility 

 -Millions of DollarsUniSource Energy Stand-Alone $ 5 $ 52 $ 73 

TEP 21 86 114 

UNS Gas 40 — 70 

UNS Electric 6 6 64 

Other 6 N/A N/A 

 

Total $ 78 

 

 

 

 Includes LOCs issued under revolving credit facilities. 

Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both 

companies cannot exceed $100 million. 

Includes cash and cash equivalents at Millennium and UED. 

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Access to Revolving Credit Facilities 

UniSource Energy and its three primary subsidiaries have access to working capital through revolving credit agreements with 

lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP and UNS Gas/UNS Electric 

Credit Agreements may be used for revolving borrowings as well as to issue letters of credit. TEP, UNS Gas, and UNS Electric 

each issue letters of credit from time to time to provide credit enhancement to counterparties for their power or gas procurement 

and hedging activities. The UniSource Credit Agreement also may be used to issue letters of credit for general corporate purposes. 

We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to 

provide credit enhancement as necessary under energy procurement and hedging agreements. See Item 7A . Quantitative and 

Qualitative Disclosures about Market Risk, Credit Risk , below. 

Liquidity Outlook 

In November 2011, UniSource Energy, TEP, UNS Gas, and UNS Electric each amended and extended their respective Credit 

Agreements that were due to expire in 2014 to extend the expiration dates to November 2016. 

UniSource Energy Consolidated Cash Flows 

 

UniSource Energy’s operating cash flows are generated primarily by the retail and wholesale energy sales at TEP, UNS Gas and 

UNS Electric, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first 

quarter and highest in the third quarter due to TEP’s summer-peaking load. UniSource Energy, TEP, UNS Gas and UNS Electric 

use their revolving credit facilities to fund their business activities during periods when sales are seasonally lower. 

Capital expenditures at TEP, UNS Gas and UNS Electric represent the primary use of cash for investing activities. Cash used for 

investing and financing activities can fluctuate year-to-year depending on: capital expenditures, repayments and borrowings under 

revolving credit facilities; debt issuances or retirements; capital lease payments by TEP; and dividends paid by UniSource Energy 

to its shareholders. 

Operating Activities 

In 2011, net cash flows from operating activities were $10 million lower than they were in 2010 due to: 

 

 

partially offset by 

 

 

 

K-37 

 2011 2010 2009 

 -Millions of DollarsOperating Activities $ 337 $ 347 $ 347 

Investing Activities (327 ) (305 ) (297 ) 

Financing Activities (1 ) (51 ) (29 ) 

 

• a $32 million increase in O&M costs due in part to higher planned generating plant outage costs, higher up-front 

incentive payments for customer-installed solar systems, and higher DSM payments; and 

 

• a $17 million increase in taxes other than income taxes paid due to a higher sales tax rate effective in June 2010 and 

sales taxes paid on higher retail kWh sales; 

 

• a $14 million increase in cash receipts from electric and gas sales, net of fuel and purchased energy costs. The increase 

was due in part to: a Base Rate increase at UNS Gas in April 2010; a Base Rate increase at UNS Electric in October 

2010; an increase in retail electric sales; higher fuel and purchased power cost recoveries from UNS Electric customers; 

and higher sales tax collections from customers resulting from a 1% increase in the sales tax rate that took effect in June 

2010; and 

 

• a $26 million decrease in income taxes paid net of income tax refunds due to lower taxable income resulting from bonus 

depreciation deductions. 
Table of Contents 

Investing Activities 

Net cash flows used for investing activities increased by $22 million in 2011. Capital expenditures during 2011 were $374 million 

compared with $331 million last year. TEP’s 2011 capital expenditures include $85 million related to construction of a new 

administrative headquarters. Capital expenditures in 2010 included the purchase of Sundt Unit 4 by TEP for $51 million. Investing 

activities in 2011 included a $13 million increase in proceeds from investments in Springerville lease debt. 

Capital Expenditures Forecast 

 

 

 

TEP’s estimated capital expenditures 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. 

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, see Tucson Electric Power Company, Liquidity and Capital Resources, 

Investing Activities, Capital Expenditures, below. 

Financing Activities 

Net cash flows used for financing activities were $50 million lower in 2011 compared with 2010 primarily due to: 

 

 

partially offset by 

 

 

 

Capital Contributions 

In July 2011, UniSource Energy contributed $20 million in capital to UNS Electric to help fund its purchase of BMGS from UED. 

In December 2011, UniSource Energy contributed $30 million in capital to TEP. 

 

K-38 

 Actual Estimated 

 2011 2012 2013 2014 2015 2016 

 -Millions of DollarsTEP $ 352 $ 289 $ 346 $ 379 $ 331 $ 418 

UNS Gas 13 11 12 13 14 14 

UNS Electric (1) 33 34 41 41 31 35 

Consolidating Adjustments (2) (24 ) — — — — — 

 

UniSource Energy Consolidated $ 374 $ 334 $ 399 $ 433 $ 376 $ 467 

 

 

 

 

 

 

 

 

 

 

 

 

(1) UNS Electric purchased BMGS from UED for approximately $63 million in 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. See UNS Electric , 

Factors Affecting Results of Operations, Rates, below, for more information. 

(2) Consolidating adjustments of approximately $24 million represent costs incurred during 2010 at UniSource Energy for the 

construction of a new administrative headquarters building. These costs were reimbursed to UniSource Energy when TEP 

purchased the building in November 2011. 

 

• a $16 million increase in proceeds from the issuance of long-term debt (net of long-term debt repayments and 

issuance/retirement costs); 

 • a $70 million increase in borrowings (net of repayments) under revolving credit facilities; 

 • an $18 million increase in payments on capital lease obligations; 

 • a $5 million increase in common stock dividends paid; and 

 • a $7 million decrease in cash from other financing activities. 
Table of Contents 

In 2010, UED paid UniSource Energy a $9 million dividend, of which $4 million represented a return of capital distribution. 

UniSource Energy contributed $15 million in capital to TEP in 2010 to help fund the purchase of Sundt Unit 4. 

See Other Non-Reportable Business Segments, UED and Tucson Electric Power Company, Liquidity and Capital Resources , 

below for more information. 

UniSource Credit Agreement 

In November 2011, UniSource Energy amended its existing credit agreement (the UniSource Credit Agreement). The UniSource 

Credit Agreement consists of a $125 million revolving credit and revolving letter of credit facility. The amendment extended the term 

of the UniSource Credit Agreement by two years to November 2016. As of December 31, 2011, there was $57 million outstanding 

at a weighted average interest rate of 2.0%. 

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers and sales of assets. The UniSource Credit 

Agreement also requires UniSource Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSource 

Energy stand-alone basis. Additionally, UniSource Energy cannot exceed a maximum leverage ratio determined on a consolidated 

basis. Under the terms of the UniSource Credit Agreement, UniSource Energy may pay dividends so long as it maintains 

compliance with the agreement. 

As of December 31, 2011, we were in compliance with the terms of the UniSource Credit Agreement. 

Interest Rate Risk 

UniSource 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. UniSource Energy may be required to pay higher rates of 

interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. See Item 7A. 

Quantitative and Qualitative Disclosures about Market Risk, Credit Risk , below. 

Convertible Senior Notes 

In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035. Each $1,000 of Convertible 

Senior Notes can be converted into 28.814 shares of UniSource Energy common stock at any time. The conversion ratio 

represents a conversion price of approximately $34.71 per share of common stock and is subject to adjustments including an 

adjustment to reduce the conversion price upon the payment of quarterly dividends in excess of $0.19 per share. 

On December 28, 2011, UniSource Energy gave notice of a partial redemption of the Convertible Senior Notes by calling $35 

million of the $150 million outstanding. The redemption period ended on January 12, 2012. Holders of the called Convertible Senior 

Notes had the option of converting their interests to common stock or redeeming the Convertible Senior Notes at par plus accrued 

interest. The notes were convertible into shares of UniSource Energy’s common stock at a conversion rate of 28.814 shares per 

$1,000 principal amount of Convertible Senior Notes. Approximately $33.5 million of the Convertible Senior Notes selected for 

redemption converted their interests into approximately 964,000 shares of UniSource Energy’s common stock. The remaining $1.5 

million was redeemed for cash on January 12, 2012. 

The closing price of UniSource Energy’s Common Stock was $37.76 on February 21, 2012. 

UniSource Energy has the option to redeem the remaining Convertible Senior Notes, in whole or in part, for cash, at a price equal 

to 100% of the principal amount plus accrued and unpaid interest. Holders of the Convertible Senior Notes will have the right to 

require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 

and 2030, or if certain specified fundamental changes involving UniSource Energy occur. The repurchase price will be 100% of the 

principal amount of the remaining notes plus accrued and unpaid interest. 

 

K-39 
Table of Contents 

Contractual Obligations 

The following chart displays UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of 

December 31, 2011. 

 

 

 

 

 

 

 

 

 

 

K-40 

UniSource Energy’s Contractual Obligations 

- Millions of Dollars - 

Payment Due in Years 

Ending December 31, 2012 2013 2014 2015 2016 

2017 

and after Other Total 

Long Term Debt 

Principal $ — $ — $ 37 $ 130 $ 235 $ 1,115 $ — $ 1,517 

Interest 73 73 73 73 67 728 — 1,087 

Capital Lease Obligations 118 122 195 23 18 61 — 537 

Operating Leases 2 2 2 1 1 10 — 18 

Purchase Obligations: 

Fuel 107 71 68 50 47 96 — 439 

Purchased Power 83 61 48 16 16 227 — 451 

Transmission 7 5 5 4 4 23 — 48 

Other Long-Term Liabilities : 

Pension & Other Post Retirement Obligations 28 5 6 6 6 34 — 85 

Acquisition of Springerville Coal Handling and Common Facilities — — — 120 — 106 — 226 

Solar Equipment 12 12 — — — — — 24 

Unrecognized Tax Benefits — — — — — — 29 29 

 

Total Contractual Cash Obligations $ 430 $ 351 $ 434 $ 423 $ 394 $ 2,400 $ 29 $ 4,461 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 TEP’s variable rate IDBs are secured by letters of credit issued pursuant to the TEP Credit Agreement, which expires in 2016, 

and 2010 Reimbursement Agreement, which expires in 2014. Although the variable rate IDBs mature between 2018 and 

2032, the above maturity reflects a redemption or repurchase of such bonds as though the letters of credit terminate without 

replacement upon expiration of the TEP Credit Agreement in 2016 and the 2010 Reimbursement Agreement in 2014. 

 Excludes interest on revolving credit facilities. 

 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. 

 Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the San Juan and Four Corners 

generating stations as the timing of payment has not been determined. See Note 4 . 

 Excludes asset retirement obligations expected to occur through 2066. 

 These obligations represent TEP’s and UES’ expected contributions to pension plans in 2012, TEP’s expected benefit 

payments for its unfunded Supplemental Executive Retirement Plan and TEP’s expected postretirement benefit costs to cover 

medical and life insurance claims as determined by the plans’ actuaries. TEP and UES do not know and have not included 

pension contributions beyond 2012 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 postretirement benefit plan on a pay-asyou-go basis. In 2009, TEP established a VEBA Trust to partially fund expected future benefits for union employees. Benefit 

payments are not expected to be made from the Trust for several years. The 2012 obligation includes expected VEBA 

contributions. VEBA contributions for periods beyond 2012 cannot be determined at this time. 

 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. 

 TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. 6 MW were approved by the 

ACC, and 3 MW remain subject to ACC approval, which is expected in the fourth quarter of 2012. 

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We have reviewed our contractual obligations and provide the following additional information: 

 

 

Dividends on Common Stock 

On February 24, 2012, UniSource Energy declared a first quarter cash dividend of $0.43 per share on its common stock. The first 

quarter dividend, totaling approximately $16 million, will be paid March 22, 2012 to shareholders of record at the close of business 

March 12, 2012. The table below summarizes UniSource Energy’s dividends paid in 2009 through 2011. 

 

Income Tax Position 

As of December 31, 2011, UniSource Energy and TEP had the following carry-forward amounts: 

 

The 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. The same law makes qualified property placed in 

service during 2012 eligible for 50% bonus depreciation for tax purposes. This is an acceleration of tax benefits UniSource Energy 

otherwise would have received over 20 years. As a result of these provisions, UniSource Energy did not pay any federal income 

taxes for the tax year 2011 and does not expect to pay any federal income taxes for 2012. 

TUCSON ELECTRIC POWER CO MPANY 

RESULTS OF OPERATI ONS 

Executive Summary 

TEP’s financial condition and results of operations are the principal factors affecting the financial condition and results of operations 

of UniSource Energy. The following discussion relates to TEP’s utility operations, unless otherwise noted. 

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 net income: 

 

K-41 

 In January 2012, UniSource Energy redeemed $35 million of its convertible senior notes. Pursuant to the redemption, 

substantially all of the notes were converted into approximately 1 million shares of UniSource Energy Common Stock. 

 

• 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. 

 2011 2010 2009 

Quarterly Dividend Per Common Share $ 0.42 $ 0.39 $ 0.29 

Annual Dividend Per Common Share $ 1.68 $ 1.56 $ 1.16 

Common Stock Dividends Paid $ 62 million $ 57 million $ 41 million 

 UniSource Energy TEP 

 Amount Expiring Year Amount Expiring Year 

 -Amounts in Millions of DollarsCapital Loss $ 8 2015 $ — — 

Federal Net Operating Loss 230 2031 212 2031 

State Net Operating Loss — 2016 13 2016 

State Credits 1 2016 2 2016 

AMT Credit 43 None 25 None 

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Table of Contents 

 

 

 

partially offset by 

 

 

2010 Compared with 2009 

TEP recorded net income of $108 million in 2010 compared with net income of $91 million in 2009. The following factors 

contributed to the change in TEP’s net income: 

 

 

 

 

 

 

 

These factors were partially offset by: 

 

K-42 

 

• 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 the first quarter of 2010, transmission revenues benefitted 

from the temporary sale of transmission capacity to SRP; 

 

• an $9 million increase in Base O&M primarily due to TEP’s share of planned generating plant maintenance expense at 

San Juan; and 

 • a $5 million increase in depreciation expense as a result of an increase in plant-in-service; 

 • a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric; and 

 • a $3 million loss recorded in 2010 related to the settlement of disputed wholesale power transactions.

 

• $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. See Factors Affecting Results of Operations, Springerville Units 3 and 4 , below for more 

information; 

 

• 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. See 

Factors Affecting Results of Operations, 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. See Operating 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, and resulting interest income, also declines over 

time as TEP pays down its capital lease obligations; 

 

• a $3 million increase in long-term wholesale margin revenues due primarily to an increase in sales volumes to one of 

TEP’s long-term wholesale customers; and 

 

• a $2 million increase in wholesale transmission revenues as TEP temporarily provided transmission capacity for 

Springerville Unit 4 during the first quarter of 2010. 
Table of Contents 

 

 

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 adjustment 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. 

Utility Sales and Revenues 

Customer growth, weather, economic conditions 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. 

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. 

 

K-43 

 

• an $8 million decrease in total other 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 in 

Springerville Unit 1 lease equity; 

 

• a $6 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 2009. 
Table of Contents 

 

 

 

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. 

 

K-44 

Energy Sales, kWh (in millions) 2011 2010 

2011 vs. 

2010 

% Change* 2009 

2010 vs. 

2009 

% Change* 

Electric Retail Sales: 

Residential 3,888 3,870 0.5 % 3,906 (0.9 %) 

Commercial 1,973 1,963 0.5 % 1,988 (1.3 %) 

Industrial 2,145 2,139 0.3 % 2,161 (1.0 %) 

Mining 1,083 1,079 0.3 % 1,065 1.4 % 

Public Authorities 243 241 1.1 % 251 (4.1 %) 

 

Total Electric Retail Sales 9,332 9,292 0.4 % 9,371 (0.8 %) 

 

 

 

 

 

 

 

 

 

 

Retail Margin Revenues (in millions): 

Residential $ 252 $ 252 0.2 % $ 254 (0.9 %) 

Commercial 160 159 0.6 % 160 (0.5 %) 

Industrial 95 97 (2.1 %) 100 (3.1 %) 

Mining 32 31 1.9 % 30 3.0 % 

Public Authorities 12 12 0.8 % 12 (2.4 %) 

 

Total Retail Margin Revenues (Non-GAAP)** $ 551 $ 551 0.0 % $ 556 (1.0 %) 

PPFAC Revenues 307 279 9.6 % 287 (2.2 %) 

RES and DSM Revenues 46 38 23.3 % 25 48.8 % 

 

Total Retail Revenues (GAAP) $ 904 $ 868 4.1 % $ 868 0.1 % 

 

 

 

 

 

 

 

 

 

 

Avg. Retail Margin Revenue (cents / kWh): 

Residential 6.48 6.50 (0.3 %) 6.49 0.2 % 

Commercial 8.11 8.10 0.1 % 8.04 0.8 % 

Industrial 4.42 4.53 (2.4 %) 4.62 (2.1 %) 

Mining 2.92 2.87 1.7 % 2.82 1.6 % 

Public Authorities 5.05 5.07 (0.4 %) 4.98 1.7 % 

 

Avg. Retail Margin Revenue / kWh 5.90 5.93 (0.5 %) 5.93 (0.1 %) 

Avg. PPFAC Revenue / kWh 3.29 3.01 9.3 % 3.05 (1.4 %) 

Avg. RES & DSM Revenue / kWh 0.50 0.41 22.0 % 0.27 50.0 % 

 

Total Avg. Retail Revenue / kWh 9.69 9.35 3.7 % 9.25 0.9 % 

 

 

 

 

 

 

 

 

 

 

Cooling Degree Days 

Actual 1,528 1,543 (1.0 %) 1,599 (3.5 %) 

10-Year Average 1,473 1,468 NM 1,469 NM 

Heating Degree Days 

Actual 1,597 1,469 8.7 % 1,287 14.1 % 

10-Year Average 1,417 1,430 NM 1,434 NM 

 

* 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 Electric Retail 

Sales, which is determined in accordance with GAAP. Retail Margin Revenues excludes: (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 Margin Revenues between periods provides 

useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility 

business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating 

expenses of our core utility business. 
Table of Contents 

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 by 1.9% over 2010, due to higher energy consumption 

and changing usage patterns which resulted in higher demand charges paid to TEP. 

2010 Compared with 2009 

Residential 

Residential kWh sales were 0.9% lower in 2010 compared with 2009, which led to a decrease in residential margin revenues of $2 

million. The decline in residential kWh sales can be attributed to a 3.5% decrease 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 lower demand charges, led to a decline in commercial 

margin revenues 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. 

Mining 

Higher copper prices led to increased mining activity resulting in a 1.4% increase in sales volumes in 2010 compared with 2009. 

Margin revenues from mining customers increased $1 million, or 3.0%, compared with the prior year due to changing usage 

patterns that increased demand charges. 

Wholesale Sales and Transmission Revenues 

 

 

Long-term wholesale margin revenues from long-term wholesale contracts were $15 million lower than in 2010. The decrease was 

due primarily to a change in pricing under the SRP contract. See Factors Affecting Results of Operations, Long-Term Wholesale 

Sales, Salt River Project, below, for more information. 

 

K-45 

 2011 2010 2009 

Long-Term Wholesale Revenues: -Millions of DollarsLong-Term Wholesale Margin Revenues (Non-GAAP)* $ 13 $ 28 $ 25 

Fuel and Purchased Power Expense Allocated to Long- Term Wholesale 

Revenues 28 28 23 

 

Total Long-Term Wholesale Revenues $ 41 $ 56 $ 48 

Transmission Revenues 16 21 19 

Short-Term Wholesale Revenues 73 64 86 

 

Electric Wholesale Sales (GAAP) $ 130 $ 141 $ 153 

 

 

 

 

 

 

* Long-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 in Long-Term Wholesale 

Margin Revenues between periods provides useful information to 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. 
Table of Contents 

Wholesale transmission revenues in 2011 decreased by $5 million compared with 2010. In 2010, TEP 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 PPFAC. There was no wholesale trading activity in 2009, 2010 and 2011. 

In April 2010, TEP settled all remaining claims arising from 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. 

Other Revenues 

 

 

In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include: inter-company revenues from 

UNS Gas and UNS Electric for corporate services provided by TEP; and miscellaneous service-related revenues such as power 

pole attachments, damage claims and customer late fees. 

Operating Expenses 

2011 Compared with 2010 

Fuel and Purchased Power Expense 

TEP’s fuel and purchased power expense and energy resources for 2011, 2010 and 2009 are detailed below: 

 

 

K-46 

 2011 2010 2009 

 -Millions of DollarsRevenue related to Springerville Units 3 and 4 $ 97 $ 97 $ 60 

Other Revenue 26 22 23 

 

Total Other Revenue $ 123 $ 119 $ 83 

 

 

 

 

 

 

 Represents reimbursements for expenses incurred by TEP related to the operation of Springerville Units 3 and 4. 

TEP Generation and Purchased Power 

Fuel and Purchased Power 

Expense 

 2011 2010 2009 2011 2010 2009 

 -Millions of kWh- -Millions of DollarsCoal-Fired Generation 9,946 9,481 9,272 $ 254 $ 217 $ 198 

Gas-Fired Generation 929 1,078 992 55 60 76 

Renewable Generation 37 32 30 — — — 

 

Total Generation 10,912 10,591 10,294 309 277 274 

Purchased Power 2,687 2,846 3,810 106 119 145 

Reimbursed Fuel Expense — — — 8 7 5 

Transmission — — — (1 ) 3 3 

Increase (Decrease) to Reflect PPFAC 

Treatment — — — (6 ) (21 ) (18 ) 

 

Total Resources 13,599 13,437 14,104 $ 416 $ 385 $ 409 

 

 

 

 

 

 

Less Line Losses and Company Use (795 ) (876 ) (941 ) 

 

Total Energy Sold 12,804 12,561 13,163 

 

 

 

 

 

 

 

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Table of Contents 

Generation 

Total generating output increased during 2011 compared with 2010. The higher output was primarily due to the increased 

availability of TEP’s largest coal-fired generating plants, Springerville Units 1 and 2. In 2010, Springerville Units 1 and 2 

experienced unplanned outages, in addition to a planned maintenance outage at Springerville Unit 1. 

Purchased Power 

Purchased power volumes decreased in 2011 compared with 2010. The lower volume of power purchases was primarily due to the 

increased availability of TEP’s coal-fired generating resources. 

The table below summarizes TEP’s cost per kWh generated or purchased. 

 

Market Prices 

As a participant in the western U.S. wholesale power markets, TEP is affected by changes in market conditions. We cannot predict 

whether changes in various factors that influence demand and supply will cause prices to change during 2012. 

 

 

O&M 

The table below summarizes the items included in TEP’s O&M expense. 

 

 

TEP’s base O&M expense in 2011 was $237 million, or $9 million above 2010. The increase is due primarily to unplanned outages 

at San Juan in 2011. 

 

K-47 

 2011 2010 2009 

 -cents per kWh generatedCoal 2.56 2.29 2.14 

Gas 5.99 5.58 7.66 

Purchased Power 3.94 4.17 3.79 

Average Market Price for Around-the-Clock Energy $/MWh 

2011 $ 30 

2010 34 

2009 $ 30 

Average Market Price for Natural Gas $/MMBtu 

2011 $ 3.89 

2010 4.18 

2009 $ 3.34 

 2011 2010 2009 

 -Millions of DollarsBase O&M (Non-GAAP) $ 237 $ 228 $ 231 

O&M recorded in Other Expense (8 ) (7 ) (7 ) 

Reimbursed expenses related to Springerville Units 3 and 4 63 65 41 

Expenses related to customer funded renewable energy and DSM programs 39 31 18 

 

Total O&M (GAAP) $ 331 $ 317 $ 283 

 

 

 

 

 

 

Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in 

accordance with GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental 

level of operating and maintenance expense related to our business. Base O&M excludes expenses that are directly offset by 

revenues collected from customers and other third parties. 

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(1) 
Table of Contents 

Income Tax Expense 

In 2011, TEP’s effective tax rate was 38% compared with 36% in 2010. The increase is primarily due to a decrease in federal 

deductions along with federal and state tax credits. See Note 8 for more information. 

2010 Compared with 2009 

Generation 

Coal-related fuel expense in 2010 increased by $19 million compared with 2009 due primarily to the switching of fuel at Sundt Unit 

4 from 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. 

Purchased Power 

Purchased power volumes and expense during 2010 were lower than 2009 due to a decrease in short-term wholesale sales 

activity, an increase in coal-fired generating output, and a decline in retail sales volumes. 

O&M 

TEP’s base O&M expense in 2010 was $228 million, or $3 million below 2009. The decline is due primarily to fewer plant 

maintenance outages and a decrease in pension and postretirement medical expense in 2010 compared with 2009. 

FACTORS AFFECTING RESULTS OF OPERATIONS 

Base Rate Increase Moratorium 

Pursuant to the 2008 TEP Rate Order, TEP’s Base Rates are frozen through at least December 31, 2012. 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 

cannot end earlier than December 31, 2011. 

Notwithstanding the rate increase moratorium, Base Rates and adjustor mechanisms may change under emergency conditions 

beyond TEP’s control if the ACC concludes such changes are required to protect the public interest. 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. 

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 pre-tax income of $24 million in 2011 and 2010, and $13 million in 2009 related to the 

operation of these units. The table below summarizes the income statement line items where TEP records revenues and expenses 

related to Springerville Units 3 and 4. 

 

 

K-48 

 2011 2010 2009 

 -Millions of DollarsOther Revenues $ 97 $ 97 $ 60 

Fuel Expense (8 ) (7 ) (5 ) 

Operations and Maintenance Expense (63 ) (65 ) (41 ) 

Taxes Other Than Income Taxes (2 ) (1 ) (1 ) 

 

Total Pre-Tax Income $ 24 $ 24 $ 13 

 

 

 

 

 

 
Table of Contents 

Pension and Postretirement Benefit Expense 

The table below summarizes TEP’s pension and other postretirement benefit expenses charged to O&M in 2009, 2010, and 2011. 

See Note 9 for more information. 

 

In 2012, TEP expects to charge $10 million of pension and $5 million of other postretirement benefit expense to O&M. 

Long-Term Wholesale Sales 

In 2011 and 2010, TEP’s margin on long-term wholesale sales was $13 million and $28 million, respectively. TEP’s two primary 

long-term wholesale contracts are with SRP and NTUA. 

Salt River Project 

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 Palo Verde Market Index. As of February 21, 2012, the average 

forward price of on-peak power on the Palo Verde Market Index for the calendar year 2012 was $30.33 MWh. 

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 2011, approximately 12% 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, see Item. 1 Business, TEP, Service Area and Customers, Wholesale Business. 

Electric Energy Efficiency Standards (EE 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 programs to reduce customers’ energy consumption. In 2011, TEP’s programs saved energy equal to 

approximately 1.4% of its 2010 sales. In 2012, the EE Standards target total kWh savings of 3% of 2011 sales. The EE Standards 

increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020. 

The EE Standards can be met by new and existing DSM programs, direct load control programs and energy efficient building 

codes. The EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP’s programs and Retail 

Rates charged to customers for such programs are subject to annual approval by the ACC. 

In January 2012, TEP filed a modification to its Energy Efficiency Implementation Plan with the ACC. The proposal includes a 

request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 2013. TEP’s 

proposed annual performance incentive for 2012 and 2013 ranges from $6 million to $8 million. TEP expects the ACC to issue a 

decision on this matter in the first quarter of 2012. 

 

K-49 

 2011 2010 2009 

 -Millions of DollarsPension Expense Charged to O&M $ 10 $ 9 $ 12 

Other Postretirement Benefit Expense Charged to O&M 4 4 4 

 

Total $ 14 $ 13 $ 16 

 

 

 

 

 

 
Table of Contents 

Decoupling 

In December 2010, the ACC issued a policy statement recognizing the need to adopt rate decoupling or another mechanism to 

make Arizona’s EE Standards viable. A decoupling mechanism is designed to encourage energy conservation by restructuring 

utility Retail 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 general rate case on or after 

June 30, 2012. 

Competition 

New technological developments and the implementation of 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. See Item 1. Business, TEP, Rates and Regulation, Electric Energy Efficiency Standards and Decoupling for 

more information. 

Renewable Energy Standard and Tariff 

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. 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. During 2011, TEP earned approximately $1 million pre-tax on its 2010 investment in solar projects. In 

accordance with the funding mechanism approved by the ACC in 2010, TEP could earn approximately $1 million pre-tax in 2012 on 

solar investments made in 2010 and 2011. 

In December 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 2011, TEP’s renewable energy investments totaled $28 million. In accordance with 

the funding mechanism approved by the ACC, TEP could earn approximately $1 million pre-tax in 2012 on solar investments made 

in 2010 and 2011 and approximately $4 million pre-tax in 2013. For more information see Item 1. Business, TEP, Rates and 

Regulation, Renewable Energy Standard and Tariff. 

Sales to Mining Customers 

The continuation of copper prices of $3 per pound has led to increased 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 2011, sales to TEP’s mining customers increased 0.3% compared with 2010 and represented 11% of TEP’s total retail kWh 

sales and 6% of total retail margin revenues. 

In addition to the mining customers TEP currently serves, in 2007, Augusta Resources Corporation (Augusta) filed a plan of 

operations with the United States Forest Service (USFS) for the proposed Rosemont Copper Mine near Tucson, Arizona. The 

Rosemont mine requires electric service from TEP via a 138kV transmission line for the construction and ongoing operation of the 

mine. A certificate of environmental compatibility (CEC) from the ACC’s line siting committee was approved in December 2011 for 

the 138 kV transmission line. Appeals have been filed relative to the issuance of the CEC. If the Rosemont Copper Mine reaches 

full production, it would become TEP’s largest retail customer. TEP would serve approximately 100 MW of the Rosemont Copper 

Mine’s total estimated load of approximately 110 MW. 

TEP cannot predict if or when existing mines will expand operations or new or re-opened mines will commence operations. 

 

K-50 
Table of Contents 

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, 2011 TEP had $215 million in taxexempt 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 10% on the $37 million of bonds and 20% 

on the other $178 million. During 2011, the average rates paid ranged from 0.05% to 0.34%. At February 21, 2012, the average 

rate on the debt was 0.26%. 

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 , below. 

San Juan Mine Fire 

In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. TEP 

owns approximately 20% of San Juan, which is operated by PNM. As we are unable to predict when operations will resume at the 

mine, we and the other owners of San Juan are considering alternatives for operating the facility. 

However, based on information we have received to date, we do not expect the mine fire to have a material effect on our financial 

condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price 

of wholesale power. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers 

through the PPFAC, subject to ACC approval. 

Fair Value Measurements 

TEP’s income statement exposure to risk is mitigated as TEP reports the change in fair value of energy contract derivatives as a 

regulatory asset or a regulatory liability, or as a component of AOCI rather than in the income statement. See Note 11 for more 

information. 

LIQUIDITY AND CAPITAL RESOURCES 

TEP Cash Flows 

The table below shows the cash available to TEP after capital expenditures, scheduled debt payments and payments on capital 

lease obligations: 

 

 

 

K-51 

 2011 2010 2009 

Net Cash Flows – Operating Activities (GAAP) $ 268 $ 302 $ 268 

Amounts from Statements of Cash Flows: 

Less: Capital Expenditures (352 ) (277 ) (240 ) 

 

Net Cash Flows after Capital Expenditures (Non-GAAP)* (84 ) 25 28 

Amounts From Statements of Cash Flows: 

Less: Retirement of Capital Lease Obligations (74 ) (56 ) (24 ) 

Plus: Proceeds from Investment in Lease Debt 38 26 13 

 

Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital 

Lease Obligations (Non-GAAP)* $ (120 ) $ (5 ) $ 17 

 

 

 

 

 

 

(1) 2010 includes a $51 million payment for the purchase of Sundt Unit 4 lease equity. 

(1) 
Table of Contents 

 

 

Liquidity Outlook 

During 2012, TEP expects to generate sufficient internal cash flows to fund the majority of its capital expenditures and operating 

activities. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in 

the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its 

revolving credit facility to fund its business activities. 

Operating Activities 

In 2011, net cash flows from operating activities decreased by $34 million compared with 2010. Net cash flows were impacted by: 

 

 

 

partially offset by 

 

Investing Activities 

Net cash flows used for investing activities increased by $59 million in 2011 compared with 2010. Capital expenditures during 2011 

were $75 million higher than in 2010, which was partially offset by a $13 million increase in proceeds from the return of investment 

in Springerville lease debt. 

Capital Expenditures 

TEP’s forecasted capital expenditures are summarized below: 

 

 

K-52 

 2011 2010 2009 

Net Cash Flows – Operating Activities (GAAP) $ 268 $ 302 $ 268 

Net Cash Flows – Investing Activities (GAAP) (312 ) (253 ) (250 ) 

Net Cash Flows – Financing Activities (GAAP) 51 (52 ) (29 ) 

Net Cash Flows after Capital Expenditures (Non-GAAP)* (84 ) 25 28 

Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital 

Lease Obligations (Non-GAAP)* (120 ) (5 ) 17 

* 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 - Operating Activities, which is determined in accordance with 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 TEP’s ability to fund capital requirements, make 

required principal payments on debt and capital lease obligations (net), and pay dividends to UniSource Energy. 

 

• a $38 million increase in O&M costs due in part to higher generating plant outage costs, higher up-front incentive 

payments for customer-installed solar systems, and higher DSM payments; 

 

• a $5 million increase in taxes other than income taxes due to a higher sales tax rate effective in June 2010 and sales 

taxes paid on higher retail kWh sales; and 

 

• a $10 million decrease in cash receipts from electric sales, net of fuel and purchased power costs. This decrease was 

due to higher coal costs and lower long-term wholesale margins compared with 2010; 

 • a $17 million decrease in income taxes paid due to lower taxable income resulting from bonus depreciation deductions. 

 2012 2013 2014 2015 2016 

 -Millions of DollarsTransmission and Distribution $ 158 $ 179 $ 129 $ 99 $ 118 

Generation Facilities 57 80 93 72 169 

Renewable Energy Generation 32 30 30 30 30 

Environmental 2 19 89 94 64 

General and Other 40 38 38 36 37 

 

Total $ 289 $ 346 $ 379 $ 331 $ 418 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

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. See Capital Lease Obligations , below for more information. 

TEP’s capital expenditures also exclude the estimated cost to construct a proposed Tucson to Nogales, Arizona 345 KV 

transmission line of $120 million. See Item 1. Business, TEP, Transmission Access, Tucson to Nogales Transmission Line 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. 

Investments in Springerville Lease Debt 

At December 31, 2011, TEP had $29 million of investments in lease debt on its balance sheet. 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 its capital lease obligations. The Springerville Unit 1 and Springerville Coal Handling 

Facilities leases expire in 2015. 

See Note 6 for more information . 

Financing Activities 

In 2011, net cash from financing activities was $103 million higher than in 2010 due to: a $45 million increase in borrowings (net of 

repayments) under TEP’s revolving credit facility; a $15 million increase in capital contributions from UniSource Energy in 2011; 

and a $60 million reduction in dividends paid to UniSource Energy during 2011; partially offset by an $18 million increase in 

payments on capital lease obligations. 

TEP Credit Agreement 

In November 2011, TEP amended and extended its existing credit agreement (the TEP Credit Agreement). The TEP Credit 

Agreement consisted of a $200 million revolving credit and revolving letter of credit facility and a $341 million letter of credit facility 

to support variable rate tax-exempt bonds. The amendment extended the term of the TEP Credit Agreement by two years to 

November 2016. 

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 IDBs and the cancellation of $155 million of LOCs supporting those bonds. The TEP Credit Agreement is secured 

by $386 million of Mortgage Bonds. See 2011 Bond Issuances, Purchase and Redemptions, below. 

At December 31, 2011, TEP had $10 million in borrowings outstanding and $1 million of letters of credit issued under the revolving 

credit facility. 

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 UniSource Energy. As of December 31, 2011, TEP was in compliance with the terms of the TEP Credit Agreement. 

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 IDBs that were issued on behalf of TEP in December 2010. 

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement 

described above. As of December 31, 2011, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement. 

 

K-53 
Table of Contents 

Capital Contribution from UniSource Energy 

In December 2011, UniSource Energy contributed $30 million of capital to TEP. 

In March 2010, UniSource Energy contributed $15 million of capital to TEP. TEP used the proceeds to help fund the purchase of 

Sundt Unit 4. 

In March 2009, UniSource Energy contributed $30 million of capital to TEP. TEP used the proceeds to purchase Springerville Unit 1 

lease debt. 

2011 Bond Issuances, Purchases and Redemptions 

In November 2011, TEP issued $250 million in unsecured notes due in November 2021 (TEP Notes). The TEP Notes bear interest 

at 5.15% and are callable prior to August 2021 with a make-whole redemption premium. The TEP Notes contain a limitation on the 

amount of secured debt that TEP may have outstanding. TEP used the net proceeds from the sale of the TEP Notes to 

(i) repurchase $150 million of its tax-exempt variable rate bonds, (ii) redeem approximately $22 million of fixed rate bonds with a 

coupon of 6.1% and (iii) repay $78 million on its revolving credit facility. 

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. 

2010 Bond Issuances 

In 2010, $137 million of tax-exempt bonds were issued on behalf of TEP, with $37 million of such bonds being applied to redeem a 

corresponding amount of outstanding tax-exempt bonds. In addition, in 2010 TEP converted the interest rate mode on $100 million 

of tax-exempt bonds from a variable rate to a fixed rate. 

Tax-Exempt Bonds 

TEP has financed a substantial portion of utility plant assets with revenue bonds issued by governmental entities on TEP’s behalf. 

The interest on these bonds is excluded from gross income of the bondholder for federal income tax purposes. The proceeds of the 

bonds are loaned to TEP, with TEP agreeing to repay the loans by making payments in amounts and at times to enable payments 

of principal of and interest on the tax-exempt bonds to be paid when due. Of the $831 million of tax-exempt bonds outstanding as of 

December 31, 2011, $616 million are unsecured and bear interest at fixed rates and $215 million are variable rate bonds. The 

variable rate bonds accrue interest at a weekly rate, with bondholders having the right to require their bonds to be purchased upon 

demand at a purchase price of par plus accrued interest. Variable rate bonds which have been put for purchase are generally 

remarketed to third parties to pay the purchase price. Payments of principal, interest and purchase price on the variable rate bonds 

are supported by direct-pay letters of credit, with TEP being required to reimburse the letter of credit banks for drawings on the 

letters of credit. See TEP Credit Agreement and TEP Reimbursement Agreement for more information. 

Mortgage Indenture 

TEP’s mortgage indenture creates a lien on and security interest in most of TEP’s utility plant assets. Springerville Unit 2, which is 

owned by San Carlos, is not subject to this lien and security interest. The mortgage indenture allows TEP to issue additional 

mortgage bonds on the basis of (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, 2011, TEP had a total of $423 million in outstanding Mortgage Bonds, consisting of $386 million in bonds securing 

the TEP Credit Agreement, and $37 million in bonds securing the 2010 TEP Reimbursement Agreement. 

 

K-54 
Table of Contents 

Capital Lease Obligations 

At December 31, 2011, TEP had $430 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. 

 

 

 

 

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. 

Contractual Obligations 

The following chart displays TEP’s contractual obligations as of December 31, 2011 by maturity and by type of obligation. 

TEP’s Contractual Obligations 

- Millions of Dollars - 

 

 

 

K-55 

Leases 

Capital Lease Obligation 

Balance Expiration 

Renewal/Purchase 

Option 

 -Millions of DollarsSpringerville Unit 1 

 

$ 253 

 

 2015 

 

Fair market value 

purchase option of $159 million 

Springerville Coal Handling Facilities Lease 

 

 65 

 

 2015 

 

Fixed price 

purchase option 

of $120 million 

Springerville Common Facilities 

 

 112 

 

 

 

2017 and 

2021 

 

 

 

Fixed price purchase 

option of $106 million 

 

Total Capital Lease Obligations $ 430 

 

 

 

(1) The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common 

Facilities. 

(2) TEP agreed with Tri-State, the owner of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville 

Coal Handling Facilities and Common 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. 

(3) The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities. 

Payment Due in Years 

Ending December 31, 2012 2013 2014 2015 2016 

2017 

and after Other Total 

Long Term Debt 

Principal $ — $ — $ 37 $ — $ 178 $ 866 $ — $ 1,081 

Interest 53 53 53 53 53 551 — 816 

Capital Lease Obligations 118 122 195 23 18 61 — 537 

Operating Leases 2 2 2 1 1 10 — 18 

Purchase Obligations: 

Fuel (including Transportation) 84 59 58 44 41 75 — 361 

Purchased Power 29 21 17 13 13 184 — 277 

Transmission 3 3 3 3 3 23 — 38 

Other Long-Term Liabilities: 

Pension & Other Post 

Retirement Obligations 26 5 6 6 6 34 — 83 

Acquisition of Springerville 

Coal Handling and Common Facilities — — — 120 — 106 — 226 

Solar Equipment 12 12 — — — — — 24 

Unrecognized Tax Benefits — — — — — — 24 24 

 

Total Contractual Cash Obligations $ 327 $ 277 $ 371 $ 263 $ 313 $ 1,910 $ 24 $ 3,485 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Purchased Power includes two long-term Power Purchase Agreements (PPAs) with renewable energy generation producers 

to meet compliance under the RES tariff. The facilities achieved commercial operation in 2011. TEP is 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 2031. TEP has entered into additional long-term renewable PPAs to comply with the 

RES tariff; however, TEP’s obligation to accept and pay for electric power under these agreements does not begin until the 

facilities are constructed and operational. 

(1) 

(2) 

(3) 

(2) 

1 

1 
Table of Contents 

See UniSource 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: 

 

 

 

Dividends on Common Stock 

TEP did not pay any dividends to UniSource Energy in 2011. TEP declared and paid dividends to UniSource Energy of $60 million 

in 2010 and $60 million in 2009. 

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement, the 2010 Reimbursement Agreement, and 

certain financial covenants. As of December 31, 2011, TEP was in compliance with the terms of the TEP Credit Agreement and the 

2010 Reimbursement Agreement. 

The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. Although the terms 

of the Federal Power Act are unclear, we believe that there is a reasonable basis for TEP to pay dividends from current year 

earnings. 

UNS GAS 

RESULTS OF OPERATIONS 

UNS Gas reported net income of $10 million in 2011, $9 million in 2010 and $7 million in 2009. 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. 

 

 

K-56 

 

• 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 credit 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, 2011, TEP was in compliance with these covenants. See TEP Credit Agreement above. 

 

• TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP 

may be required to post credit enhancements in the form of cash or a letter of credit 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, 2011, TEP had posted a $1 million letter of credit as 

collateral with counterparties for credit enhancement. 

 2011 2010 2009 

 -Millions of DollarsGas Revenues $ 148 $ 146 $ 149 

Other Revenues 3 4 4 

 

Total Operating Revenues 151 150 153 

 

Purchased Gas Expense 90 91 99 

Other Operations and Maintenance Expense 25 26 25 

Depreciation and Amortization 9 8 7 

Taxes Other Than Income Taxes 3 3 3 

 

Total Other Operating Expenses 127 128 134 

 

Operating Income 24 22 19 

Total Interest Expense 7 7 6 

Income Tax Expense 7 6 6 

 

Net Income $ 10 $ 9 $ 7 

 

 

 

 

 

 
Table of Contents 

The table below shows UNS Gas’ therm sales and revenues for 2011, 2010 and 2009. 

 

 

 

Retail therm sales during 2011 increased by 1.9% compared with 2010 due in part to a 1.3% increase in heating degree days and 

an increase in the number of retail customers. Retail margin revenues increased by 3.1%, or $2 million, during 2011 due in part to 

colder winter weather and a Base Rate increase that was implemented in April 1, 2010. As of December 31, 2011, UNS Gas had 

approximately 148,000 retail customers, which represents an increase of less than 1% compared with the end of 2010. 

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 PGA mechanism which 

reduces the gas commodity price. 

FACTORS AFFECTING RESULTS OF OPERATIONS 

Competition 

New technological developments and the implementation of Gas EE Standards may reduce energy consumption by UNS Gas’ 

retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce 

their reliance on services provided by UNS Gas. See Item 1. Business, UNS Gas, Rates and Regulation, Gas Utility Energy 

Efficiency Standards and Decoupling for more information. 

 

K-57 

 Increase (Decrease) 

 2011 2010 Amount Percent* 2009 

Energy Sales, Therms (in millions) 

Gas Retail Sales: 

Residential 74 73 1 1.2 % 70 

Commercial 31 30 1 2.9 % 30 

Industrial 2 2 — 22.9 % 2 

Public Authorities 7 7 — (0.2 %) 6 

 

Total Gas Retail Sales 114 112 2 1.9 % 108 

Negotiated Sales Program (NSP) 26 28 (2 ) (8.4 %) 30 

 

Total Gas Sales 140 140 — (0.2 %) 138 

 

 

 

 

 

 

 

 

 

 

Gas Revenues (in millions): 

Retail Margin Revenues: 

Residential $ 40 $ 39 $ 1 2.6 % $ 36 

Commercial 11 10 1 4.9 % 10 

Industrial — — — 21.9 % — 

Public Authorities 2 2 — 4.8 % 2 

 

Total Retail Margin Revenues (Non-GAAP)** 53 51 2 3.1 % 48 

Transport and NSP 17 17 — (4.6 %) 16 

DSM 1 1 — 10.0 % 1 

Retail Fuel Revenues 77 77 — 1.0 % 84 

 

Total Gas Revenues (GAAP) $ 148 $ 146 $ 2 1.2 % $ 149 

 

Weather Data: 

Heating Degree Days 

Year Ended December 31 25,794 25,457 337 1.3 % 24,305 

10-Year Average 24,894 24,828 NM NM 24,739 

* Percent change calculated on unrounded data and may not correspond exactly to data shown in table. 

** Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, 

which is determined in accordance with GAAP. Retail Margin Revenues excludes revenues collected from retail customers 

that are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between 

periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our 

core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the 

operating expenses of our core utility business. 
Table of Contents 

Rates 

See Item 1. Business, UNS Gas, Rates and Regulation, 2011 UNS Gas Rate Filing. 

Interest Rates 

UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. 

The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be 

required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative and Qualitative 

Disclosures about Market Risk, Interest Rate Risk , below. 

Fair Value Measurements 

UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract 

derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11 for more information. 

LIQUIDITY AND CAPITAL RESOURCES 

Liquidity Outlook 

UNS Gas’ capital requirements consist primarily of capital expenditures. In 2011, capital expenditures were $13 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 UniSource 

Energy. 

Operating Cash Flow and Capital Expenditures 

The table below provides summary cash flow information for UNS Gas. 

 

Operating cash flows increased in 2011 due in part to the temporary over-collection of PGA gas costs from customers. 

UNS Gas/UNS Electric Revolver 

In November 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement. The UNS Electric/UNS Gas 

Revolver consists of a $100 million unsecured revolving credit and revolving letter of credit facility. Either company can borrow up 

to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The amendment extended 

the term of the UNS Electric/UNS Gas Revolver by two years to 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 and UNS Electric. 

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, 2011, UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver. 

 

K-58 

 2011 2010 2009 

 -Millions of DollarsCash Provided By (Used In): 

Operating Activities $ 32 $ 18 $ 37 

Investing Activities (12 ) (9 ) (13 ) 

Financing Activities (11 ) (11 ) — 

 

Net Increase (Decrease in Cash) 9 (2 ) 24 

Beginning Cash 29 31 7 

 

Ending Cash $ 38 $ 29 $ 31 

 

 

 

 

 

 
Table of Contents 

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 December 31, 2011, UNS Gas had no outstanding borrowings or letters of credit under the UNS 

Gas/UNS Electric Revolver. 

Senior Unsecured Notes 

UNS Gas has $100 million of senior unsecured notes outstanding, of which $50 million matures in 2015 and $50 million matures in 

2026. 

All of UNS Gas’ senior unsecured notes are guaranteed by UES. The note purchase agreements for UNS Gas restrict transactions 

with affiliates, mergers, liens, restricted payments and incurrence of indebtedness. The agreements also contain a minimum net 

worth test. As of December 31, 2011, UNS Gas was in compliance with the terms of its note purchase agreements. 

UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas 

may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt. 

Note Issuance 

In August 2011, UNS Gas issued $50 million of 5.39% senior unsecured notes. The proceeds were used to pay off $50 million of 

senior unsecured notes that matured in August 2011.

Contractual Obligations 

UNS Gas Supply Contracts 

UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period 

during which the commodity is purchased. UNS Gas has firm transportation agreements with capacity sufficient to meet its current 

load requirements. These contracts expire in various years between 2012 and 2023. 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% of its expected monthly consumption for the 2011/2012 winter season (November through March). 

Additionally, UNS Gas has approximately 38% of its expected gas consumption hedged for April through October 2012, and 32% 

hedged for the period November 2012 through March 2013. 

 

K-59 
Table of Contents 

The following table displays UNS Gas’ contractual obligations as of December 31, 2011 by maturity and by type of obligation. 

 

UNS Gas conducts certain of its gas procurement and risk management activities under agreements whereby UNS Gas may be 

required to post margin due to changes in contract values, a change in UNS Gas’ creditworthiness or exposures exceeding credit 

limits provided to UNS Gas. As of December 31, 2011, UNS Gas had not posted any such credit enhancements. 

Dividends on Common Stock 

UNS Gas paid dividends to UniSource Energy of $10 million in 2010, 2011, and in February 2012. UNS Gas’ ability to pay future 

dividends will depend on the cash needs for capital expenditures and various other factors. 

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no 

default or event of default exists and (b) it could incur additional debt under the debt incurrence test. As of December 31, 2011, 

UNS Gas was in compliance with the terms of its note purchase agreement. See Senior Unsecured Notes , above. 

UNS ELECTRIC 

RESULTS OF OPERATIONS 

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC 

approval and other conditions. FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for 

$63 million on July 1, 2011. In accordance with accounting rules related to the transfer of a business held under common control, 

we reflect UNS Electric’s purchase of BMGS as if it occurred on January 1, 2009. The transaction had no impact on UniSource 

Energy’s consolidated financial statements for 2009 or 2010. 

UNS Electric had net income of $18 million in 2011, compared with net income of $15 million in 2010. The increase is due primarily 

to a rate increase that was implemented in October 2010. 

Results in 2010 included $3 million of pre-tax income related to a settlement with Arizona Public Service Company for refunds 

related to transactions with the California Power Exchange. 

As with TEP, UNS Electric’s operations are generally seasonal in nature, with peak energy demand occurring in the summer 

months. 

The table below provides summary financial information for UNS Electric. 

 

K-60 

UNS Gas Contractual Obligations 

-Millions of DollarsPayment Due in Years 

Ending December 31, 2012 2013 2014 2015 2016 

2017 

and 

after Other Total 

Long Term Debt 

Principal $ — $ — $ — $ 50 $ — $ 50 $ — $ 100 

Interest 6 6 6 6 3 27 — 54 

Purchase Obligations—Fuel 23 12 10 6 6 21 — 78 

Pension & Other Post Retirement Obligations 1 — — — — — — 1 

Unrecognized Tax Benefits — — — — — — 1 1 

 

Total Contractual Cash Obligations $ 30 $ 18 $ 16 $ 62 $ 9 $ 98 $ 1 $ 234 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

 

 

K-61 

 2011 2010 2009 

 -Millions of DollarsRetail Electric Revenues $ 182 $ 183 $ 180 

Wholesale Electric Revenues 37 31 5 

Other Revenues 2 2 2 

 

Total Operating Revenues 221 216 187 

Purchased Energy and Fuel Expense 137 137 116 

Other Operations and Maintenance Expense 27 29 26 

Depreciation and Amortization Expense 17 17 16 

Taxes Other Than Income Taxes 4 4 4 

 

Total Other Operating Expenses 185 187 162 

 

Operating Income 36 29 25 

Other Income — 3 — 

Total Interest Expense 7 7 7 

Income Tax Expense 11 10 7 

 

Net Income $ 18 $ 15 $ 11 

 

 

 

 

 

 
Table of Contents 

The table below summarizes UNS Electric’s kWh sales and margin revenues for 2011, 2010 and 2009. 

 

 

 

 

In 2011, retail kWh sales decreased by 0.2% compared with 2010. A 4% Base Rate increase that took effect in October 2010, 

contributed to a $7 million increase in retail margin revenues in 2011 compared with 2010. 

As of December 31, 2011, UNS Electric had approximately 91,000 retail customers, which was an increase of less than 1% 

compared with 2010. 

Wholesale revenues increased by $6 million in 2011 due to an increase in short-term wholesale sales. All revenues from wholesale 

sales are credited against costs recovered through UNS Electric’s PPFAC. 

FACTORS AFFECTING RESULTS OF OPERATIONS 

Competition 

New technological developments and the implementation of EE Standards may reduce energy consumption by UNS Electric’s retail 

customers. UNS Electric’s customers also have the ability to install renewable energy technologies and conventional generation 

units that could reduce their reliance on UNS Electric’s services. Self-generation by UNS Electric’s customers has not had a 

significant impact to date. See Item 1. Business, UNS Electric, Rates and Regulation, Energy Efficiency Standards and Decoupling 

for more information. 

 

K-62 

 Increase (Decrease) 

 2011 2010 Amount Percent* 2009 

Energy Sales, kWh (in millions) 

Electric Retail Sales: 

Residential 828 820 8 0.9 % 814 

Commercial 602 606 (4 ) (0.7 %) 608 

Industrial 221 219 2 0.8 % 197 

Mining 200 210 (10 ) (4.2 %) 163 

Public Authorities 2 2 — (16.3 %) 2 

 

Total Electric Retail Sales 1,853 1,857 (4 ) (0.2 %) 1,784 

 

 

 

 

 

 

 

 

 

 

Electric Retail Revenues (in millions): 

Retail Margin Revenues: 

Residential $ 31 $ 27 $ 4 13.9 % $ 21 

Commercial 29 27 2 5.9 % 22 

Industrial 9 9 — 4.7 % 7 

Mining 7 6 1 22.2 % 3 

Public Authorities — — — (25.0 %) — 

 

Total Retail Margin Revenues (Non-GAAP)** $ 76 $ 69 $ 7 10.0 % $ 53 

Retail Fuel Revenues 99 105 (6 ) (5.6 %) 121 

DSM and RES Revenues 7 9 (2 ) (22.4 %) 6 

 

Total Retail Revenues (GAAP) $ 182 $ 183 $ (1 ) (0.5 %) $ 180 

 

 

 

 

 

 

 

 

 

 

Weather – Cooling Degree Days 2011 2010 2009 

Year Ended December 31 9,092 8,821 271 3.1 % 9,183 

10-Year Average 8,994 9,031 NM NM 9,059 

* Percent change calculated on unrounded data and may not correspond exactly to data shown in table. 

** Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, 

which is determined in accordance with GAAP. Retail Margin Revenues exclude revenues collected from retail customers that 

are directly offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between 

periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our 

core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the 

operating expenses of our core utility business. 
Table of Contents 

Rates 

See Item 1. Business, UNS Electric, Rates and Regulation, 2010 UNS Electric Rate Order for more information. 

Mining Customer 

UNS Electric’s largest customer, a copper mine located near Kingman, Arizona, began generating a portion of its own electricity 

needs in 2011. In 2012, UNS Electric expects its mining kWh sales to decrease by approximately 50% compared with 2011; 

however, due to UNS Electric’s retail rate structure, UNS Electric expects the margin revenues from this customer to be near the 

same level as 2011. In 2011, UNS Electric’s mining-related margin revenues were $7 million. 

Renewable Energy Standard and Tariff 

As part of the 2010 UNS Electric rate order, the ACC authorized UNS Electric to recover operating costs, depreciation, property 

taxes and a return on its investment in company-owned solar projects through RES funds until these costs are reflected in its Base 

Rates. Under these terms, UNS Electric expects to invest $5 million annually in 2012 through 2014 in solar photovoltaic projects. 

We estimate that each $5 million investment would build approximately 1.25 MW of solar capacity. For more information, see 

Item 1. Business, UNS Electric, Rates and Regulation, Renewable Energy Standard and Tariff. 

Interest Rates 

UNS Electric is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit 

facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS 

Electric may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative 

and Qualitative Disclosures about Market Risk, Interest Rate Risk , below. 

Fair Value Measurements 

UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract 

derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11 for more information. 

LIQUIDITY AND CAPITAL RESOURCES 

Liquidity Outlook 

In 2011, UNS Electric’s capital expenditures were $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 UniSource Energy. 

Operating Cash Flow 

The table below provides summary cash flow information for UNS Electric. 

 

 

K-63 

 2011 2010 2009 

 -Millions of DollarsCash Provided By (Used In): 

Operating Activities $ 43 $ 34 $ 48 

Investing Activities (93 ) (23 ) (28 ) 

Financing Activities 44 (10 ) (19 ) 

 

Net Increase (Decrease in Cash) (6 ) 1 1 

Beginning Cash 11 10 9 

 

Ending Cash $ 5 $ 11 $ 10 

 

 

 

 

 

 
Table of Contents 

Operating cash flows increased in 2011 due in part to a Base Rate increase that became effective in October 2010 as well as an 

increase in wholesale sales. 

UNS Gas/UNS Electric Revolver 

See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for description of UNS Electric’s unsecured 

revolving credit agreement. 

UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, 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 21, 2012, UNS Electric had $6 million outstanding 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 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, 2011, UNS Electric was in compliance with the terms of 

its note purchase agreement. 

UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS 

Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt. 

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 1.25%. 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 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt in 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, 2011, 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, 2011, UNS Electric had posted $6 million of 

such credit enhancements in the form of letters of credit. 

UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines. See Item 1. 

Business, UNS Electric, Power Supply and Transmission, Transmission for more information. 

The following table displays UNS Electric’s contractual obligations as of December 31, 2011 by maturity and by type of obligation. 

 

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Dividends on Common Stock 

As of December 31, 2011, UNS Electric had not paid dividends to UniSource Energy. UNS Electric’s ability to pay 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, 

2011, UNS Electric was in compliance with the terms of its note purchase agreement. See Senior Unsecured Notes , above. 

OTHER NON-REPORTABLE BUSINESS SEGMENTS 

RESULTS OF OPERATIONS 

The table below summarizes the income (loss) for the other non-reportable segments in the last three years. 

 

 

Millennium 

Millennium recorded net income of $2 million in 2011 compared with a net loss of $13 million in 2010. 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 2011 and December 2010, Millennium received annual interest payments of $1 million on its $15 million note 

receivable from Mimosa. 

 

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UNS Electric Contractual Obligations 

-Millions of DollarsPayment Due in Years 

Ending December 31, 2012 2013 2014 2015 2016 

2017 

and 

after Other Total 

Long Term Debt: 

Principal $ — $ — $ — $ 80 $ — $ 50 $ — $ 130 

Interest 7 7 7 7 4 25 — 57 

Purchase Obligations: 

Purchased Power 54 40 31 3 3 43 — 174 

Transmission 4 2 2 1 1 — — 10 

Pension & Other Post Retirement Obligations 1 — — — — — — 1 

Unrecognized Tax Benefits — — — — — — 4 4 

 

Total Contractual Cash Obligations $ 66 $ 49 $ 40 $ 91 $ 8 $ 118 $ 4 $ 376 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Purchased Power includes a long-term Power Purchase Agreement (PPA) with a renewable energy generation producer to 

meet compliance under the RES tariff. The facility achieved commercial operation in September 2011. UNS Electric is 

obligated to purchase 100% of the output from this facility. The table above includes estimated future payments based on 

expected power deliveries under the contract through 2031. UNS Electric has entered into additional long-term renewable 

PPAs to comply with the RES tariff; however, UNS Electric’s obligation to accept and pay for electric power under these 

agreements does not begin until the facilities are constructed and operational. 

 2011 2010 2009 

 - Millions of Dollars - 

Millennium $ 2 $ (13 ) $ 2 

Other (1) (5 ) (6 ) (5 ) 

 

Total Other Net Loss $ (3 ) $ (19 ) $ (3 ) 

 

 

 

 

 

 

(1) Includes parent company expenses, UED and reconciling adjustments. 

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UniSource Energy Parent Company 

UniSource Energy parent company expenses primarily include interest expense (net of tax) related to the UniSource Energy 

Convertible Senior Notes and the UniSource Credit Agreement. 

UED 

In its September 2010 UNS Electric rate order, the ACC approved UNS Electric’s purchase of BMGS from UED, subject to FERC 

approval and other conditions. FERC approved the purchase in June 2011, and UNS Electric completed the purchase of BMGS for 

$63 million on July 1, 2011. 

In 2011, UED paid dividends of $39 million to UniSource Energy of which $28 million represented a return of capital. In 2010, UED 

paid a $9 million dividend to UniSource Energy, of which $4 million represented a return of capital. In 2009, UED paid a $30 million 

dividend to UniSource Energy which also represented a return of capital. 

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, 2011, 

Millennium had assets of $20 million including a $15 million note receivable and a cash balance of $5 million. 

In July 2011, Millennium sold a building for $3 million resulting in an after-tax gain of approximately $1 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 $3 million in dividend payments to UniSource Energy in 2011, $8 million in 2010 and $3 million in 2009. All of 

these dividends represented return of capital distributions. Millennium’s remaining commitment for all of its investments combined is 

less than $1 million. 

CRITICAL ACCOUNTING POLICIES 

The preparation of the financial statements in accordance with U.S. Generally Accepted Accounting Principles (GAAP) requires 

management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial 

statements and accompanying notes. UniSource Energy considers the areas described in the Critical Accounting Policies as those 

that could yield materially different financial statement results based on application and interpretation of accounting policy. Since 

making estimates and assumptions are subjective and complex, actual results could differ in subsequent periods. For additional 

information on UniSource Energy’s other significant accounting policies and recently issued accounting standards see Note 1. 

Accounting for Rate Regulation 

We generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. 

However, sometimes these principles require special accounting treatment for regulated companies to show the effect of regulation. 

For example, the ACC can determine that we are allowed to recover certain expenses at a designated time in the future. In this 

situation, we defer these items as regulatory assets on the balance sheet and then reflect the costs as expenses when we are 

allowed to recover the costs from ratepayers. Similarly, certain revenue items may be deferred as regulatory liabilities and not 

reflected as revenue until Retail Rates to customers are reduced. We evaluate regulatory assets each period and believe recovery 

is probable. 

If in the future a portion of operations no longer meets regulatory accounting criteria, the impact would be material to the financial 

statements. If we stopped applying regulatory accounting to all our regulated operations, we would write off the related balances of 

regulatory assets as an expense and record the regulatory liabilities as revenue on the income statement or in accumulated other 

comprehensive income (AOCI). 

 

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At December 31, 2011, regulatory assets net of regulatory liabilities totaled $4 million at TEP and $15 million at UNS Electric. 

Regulatory liabilities net of regulatory assets totaled $26 million at UNS Gas. We regularly assess whether we can continue to 

apply regulatory accounting to cost-based rate regulated operations. Expectations of future recovery are generally based on orders 

issued by regulatory commissions and historical experience. There are no current or expected proposals or changes in the 

regulatory environment that impact the probability of future recovery of these assets. See Note 2. 

Accounting for Asset Retirement Obligations 

TEP 

TEP is required to record the fair value of a liability for a legal obligation to retire an 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 an 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 longlived assets. The asset retirement cost is subsequently charged to depreciation expense over its useful life. 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 a ground lease agreement with Campus Research Corporation for the installation of photovoltaic (PV) assets. The 

provisions of the PV ground lease require TEP to remove the PV facilities upon expiration of the lease in 2031. The legal retirement 

obligation related to the PV assets is estimated to be approximately $4 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 $160 million at the retirement dates. No other legal obligations to retire generation plant assets 

were identified. 

TEP has various transmission and distribution lines that operate under leases and rights-of-way that contain end dates and 

restrictive 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 application of the accounting 

requirements for asset retirement obligations. Nevertheless, included in the revenue requirement underlying the Company’s electric 

service Retail 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. The accumulated balance of such accruals, less actual removal costs incurred, net of salvage 

proceeds realized, is reported as a regulatory liability. See Note 2 for details regarding net cost of removal for interim retirements. 

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. See Note 

2. 

 

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Pension and Other Postretirement Benefit Plan Assumptions 

TEP, UNS Gas and UNS Electric record plan assets, obligations and expenses related to pension and other postretirement benefit 

plans based on actuarial valuations, which include key assumptions on discount rates, expected returns on plan assets, 

compensation increases and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as 

appropriate. The effect of modifications is generally recorded or amortized over future periods. We believe that the assumptions 

used in recording obligations 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 postretirement plan obligations for 

TEP, UNS Gas and UNS Electric. 

TEP is required to recognize the underfunded status of its defined benefit pension and other postretirement plans as a liability. The 

underfunded status is the difference between the fair value of the plans assets and the projected benefit obligation for pension 

plans or accumulated postretirement benefit obligation for other postretirement 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 postretirement obligations as a liability and a regulatory asset to reflect expected recovery of pension and other 

postretirement obligations through Retail Rates. 

At December 31, 2011, TEP discounted its future pension plan obligations at 5.0% and its other postretirement plan obligations at a 

rate of 4.7%. The discount rate for future pension plan and other postretirement 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 60 and 90 percentile of AA-graded U.S. corporate bonds with future cash flows that match 

the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point change in the discount rate 

would increase or decrease the projected benefit obligation (PBO) by approximately $9 million and the 2012 plan expense by $1 

million. For TEP’s other postretirement benefit plan, a 25-basis point change in the discount rate would increase or decrease the 

accumulated postretirement benefit obligation (APBO) by approximately $2 million. A 25-basis point change in the discount rate 

would impact plan expense by 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 7.0% at December 31, 2011. In establishing its 

assumption as to the expected return on assets, TEP reviews the asset allocation and develops return assumptions for each asset 

class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis 

and forward-looking views of the financial markets. Pension expense decreases as the expected rate of return on assets increases. 

A 25-basis point change in the expected return on assets would impact pension expense in 2012 by less than $1 million. 

TEP used a current year health care cost trend rate of 6.9% in valuing its postretirement benefit obligation at December 31, 2011. 

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 postretirement benefit obligation by approximately $5 million and the related plan expense in 2012 by less than $1 

million. 

In 2012, TEP will incur pension and other postretirement benefit costs of approximately $14 million and $6 million, respectively. 

TEP expects to charge approximately $15 million of these costs to O&M expense, $3 million to capital and $2 million to Other 

Expense. TEP expects to make pension plan contributions of $20 million in 2012. In 2009, TEP established a Voluntary Employee 

Beneficiary Association (VEBA) trust to fund its other postretirement benefit plan. In 2012, TEP expects to make benefit payments 

to retirees under the postretirement benefit plan of approximately $4 million and contributions to the VEBA trust of $2 million. 

UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 4.9% at December 31, 2011. For UNS 

Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2012 

pension expense by less than $1 million. UNS Gas and UNS Electric will record pension expense of $2 million in 2012, of which 

less than $1 million will be capitalized. UNS Gas and UNS Electric expect to make combined pension plan contributions of $3 

million in 2012. 

UNS Gas and UNS Electric discounted their other postretirement plan obligations using a rate of 4.7% at December 31, 2011. UNS 

Gas and UNS Electric will record postretirement medical benefit expense and make benefit payments to retirees under the 

postretirement benefit plan of less than $1 million in 2012. 

 

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Accounting for Derivative Instruments and Hedging Activities 

Commodity Derivative Contracts 

TEP, UNS Gas and UNS Electric enter into forward contracts to purchase or sell capacity or energy at contract prices over a given 

period of time, typically for one month, three months, or one year, within established limits to take advantage of favorable market 

opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase 

energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during 

plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it has excess supply 

and the market price of energy exceeds its marginal cost. TEP and UNS Gas enter into forward gas commodity price swap 

agreements to lock in fixed prices on a portion of forecasted summer gas purchases. 

Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a 

regulatory asset or regulatory liability on the balance sheets of TEP, UNS Gas and UNS Electric. There are no current or expected 

proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the 

PPFAC or PGA mechanisms. 

The market prices used to determine fair values for TEP, UNS Gas and UNS Electric’s derivative instruments at December 31, 

2011, 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 related to LIBOR on the 

Springerville Common Facilities Lease. At December 31, 2011, TEP hedged approximately $29 million and $34 million of variable 

rate lease debt payments for the Springerville Common Facilities Lease to a fixed rate through July 1, 2014, and 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. 

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. 

See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk. 

Unbilled Revenue 

TEP, UNS Gas and UNS Electric’s retail revenues, which are recognized in the period that electricity or energy is delivered and 

consumed by customers, include unbilled revenue based on an estimate of MWh/therms delivered at the end of each period. 

Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales 

and customer usage patterns. The unbilled revenue is estimated by comparing the estimated MWh/therms delivered to the 

MWh/therms billed to TEP, UNS Gas and UNS Electric’s 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 Electric then record revenue for each customer class based on the various Retail Rates for each customer class. 

Due to the seasonal fluctuations of TEP and UNS Electric’s actual load, the unbilled revenue amount increases during the spring 

and summer and decreases during the fall and winter. Conversely the unbilled revenue amount for UNS Gas sales increases 

during the fall and winter and decreases during the spring and summer. A provision for uncollectible accounts is recorded as a 

component of operations and maintenance expense. 

 

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Plant Asset Depreciable Lives 

TEP, UNS Gas and UNS Electric have significant investments in electric generation assets and electric and natural gas 

transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant 

assets and expected net removal costs. Useful life of plant assets is further detailed in Note 5. Changes to depreciation estimates 

resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation 

expense recorded on the income statement. The estimated useful lives and depreciation rates presently used to calculate 

depreciation expense for electric generation and distribution assets for TEP, UNS Gas and UNS Electric have been approved by 

the ACC in prior rate decisions. Depreciation rates for such assets cannot be changed without ACC approval. For current approved 

ACC depreciation rates see Note 1. Depreciation rates for electric transmission assets fall under the jurisdiction of the FERC. 

In January 2010, TEP obtained an updated depreciation study which indicated that its transmission assets’ depreciable lives should 

be extended. As a result, TEP adopted new transmission depreciation rates effective January 2010, which have the effect of 

reducing depreciation expense by approximately $14 million annually. 

Income Taxes 

Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than 

they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the 

effective income tax rate at our balance sheet date. 

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income and deductions as reported in the 

consolidated tax return. 

A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the 

deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to 

objective verifiable evidence. At December 31, 2011, UniSource Energy had a $7 million valuation allowance. The valuation 

allowances related to unregulated investments’ losses are treated as capital losses for income tax purposes. If UniSource 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: 

 

 

 

 

K-70 

 

• The Financial Accounting Standards Board (FASB) issued authoritative guidance that will eliminate the current option to 

report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net 

income and other comprehensive income in one continuous statement, or in two separate but consecutive statements. 

We will be required to comply in the first quarter of 2012 and plan to present a separate statement of other 

comprehensive income. 

 

• The FASB issued authoritative guidance that changed some fair value measurement principles and disclosure 

requirements. The most significant disclosure change is expansion of required information for unobservable inputs. We 

will be required to comply in the first quarter of 2012, and we do not expect this pronouncement to have a material impact 

on the valuation techniques used to estimate the fair value of assets and liabilities. 

 

• The FASB issued authoritative guidance that requires entities to disclose both gross and net information about 

instruments and transactions eligible for offset in the statement of financial position as well as instruments and 

transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires 

disclosure of collateral received and posted in connection with master netting arrangements. We will be required to 

comply in the first quarter of 2013. 
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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. UniSource 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 

UniSource 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 UniSource Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary 

statements which may accompany the forward-looking statements. In addition, UniSource Energy and TEP disclaim any obligation 

to update any forward-looking statements to reflect events or circumstances after the date of this report. 

Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from 

those expressed in the forward-looking statements. We express our expectations, beliefs and projections in good faith and believe 

them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be 

achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from 

those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in Item 1A. 

Risk Factors , Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations , and other parts of 

this report: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could 

affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and 

access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of 

our pension and other postretirement benefit plan assets and the related contribution requirements and expense; unexpected 

increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting 

estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; 

cyber attacks or challenges to our information security; and the performance of TEP’s generating plants. 

ITEM 7A. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Market Risks 

We are exposed to various forms of market risk. Changes in interest rates, returns on marketable securities, and changes in 

commodity prices may affect our future financial results. 

For additional information concerning risk factors, including market risks, see Safe Harbor for Forward-Looking Statements , above. 

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 

UniSource 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. 

 

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Interest Rate Risk 

Long-Term Debt 

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. At 

December 31, 2011 and December 31, 2010, TEP had $215 million and $365 million, respectively, in tax-exempt variable rate debt 

outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum 

interest rate payable under the indentures for these bonds is 10% for $37 million of variable rate IDBs, and 20% on the remaining 

$178 million in variable rate IDBs. The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 0.18% 

in 2011 and 0.26% in 2010. The average weekly interest rate ranged from 0.05% to 0.34% in 2011 and 0.17% to 0.39% during 

2010. Although short-term interest rates have been relatively low and stable in 2011 and 2010, TEP may still be subject to volatility 

in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve month period, 

would result in a decrease in TEP’s pre-tax net income of approximately $2 million. 

TEP manages its exposure to variable interest rate risk by entering into interest rate swaps and financing transactions to rebalance 

its mix of variable rate and fixed rate long-term debt. 

TEP has fixed-for-floating interest rate swaps in place to hedge floating rate interest rate risk associated with $63 million of 

Springerville Common Facilities lease debt and $50 million of its variable rate IDBs. In addition, in 2010 and 2011, TEP entered into 

the following transactions to change its mix of fixed and floating rate debt. 

 

 

 

As a result of these transactions, TEP’s variable rate debt comprised approximately 15% and 31% of its total long-term debt at 

December 31, 2011 and 2010, respectively. 

In August 2011, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% 

and receive a three-month LIBOR rate on a $30 million notional amount through August 2015 to hedge the interest rate risk 

associated with its $30 million credit agreement. 

Interest Rate Swaps 

To adjust the value of TEP’s interest rate swaps, classified as a cash flow hedge, to fair value in Other Comprehensive Income, 

TEP recorded the following net unrealized gains (losses): 

 

Revolving Credit Facilities 

UniSource 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, UniSource 

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 

UniSource Energy has a short-term investment policy which governs the investment of excess cash balances by UniSource 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, 2011, UniSource Energy’s short-term 

investments consisted of liquid, highly-rated money market funds, commercial paper, and certificates of deposit. These short-term 

investments are classified as Cash and Cash Equivalents on the balance sheet. 

 

K-72 

 

• In 2010, TEP converted the interest rate on its $130 million IDBs from a variable rate to an unsecured fixed rate of 5.75% 

through maturity in 2029; 

 • In 2010, TEP refinanced $37 million of its 7.125% unsecured fixed rate IDBs with variable rate IDBs; and 

 

• TEP issued $250 million of 5.15% unsecured notes in 2011, and repurchased $150 million of variable rate IDBs to hold 

in treasury, and redeemed $22 million of its 6.1% unsecured fixed-rate IDBs. 

 2011 2010 2009 

 - Millions of Dollars - 

Unrealized Gains (Losses) $ (5 ) $ (8 ) $ 1 
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TEP had marketable securities comprised of investments in lease debt and equity with an estimated fair value of $50 million at 

December 31, 2011, and $111 million at December 31, 2010. At December 31, 2011, the carrying value exceeded fair value by $16 

million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future Retail 

Rates. At December 31, 2010, the fair value exceeded the carrying value by $6 million. These securities represent TEP’s 

investments in lease debt and equity underlying certain of TEP’s capital lease obligations. Changes in the fair value of such debt 

securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity. 

Commodity Price Risk 

TEP 

TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, and coal. This 

risk is mitigated through a PPFAC mechanism which fully recovers the actual retail fuel and purchased power costs incurred on a 

timely basis from TEP’s retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward 

component of the PPFAC rate is based on forecasted fuel and purchased power costs. The true-up component reconciles actual 

fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected 

from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, TEP is exposed to the price 

difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference. 

Purchases and Sales of Energy 

To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future 

delivery period. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and 

generation costs, using a diversified market approach to provide a balance between long-term, mid-term and spot energy sales. 

TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve 

requirements, and account for other contracts and resource contingencies. TEP also enters into limited forward purchases and 

sales to optimize its resource portfolio and take advantage of locational differences in price. These positions are managed on both 

a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk 

Management Committee. For example, the risk management policies provide that TEP should not take a short physical position in 

the third quarter and must have owned generation backing up all physical forward sales positions at the time the sale is made. 

TEP’s risk management policies also restrict entering into forward positions with maturities extending beyond the end of the next 

calendar year except for approved hedging purposes.

TEP’s risk management policies also allow for financial purchases and sales of energy subject to specified risk parameters 

established and monitored by the Risk Management Committee. These include financial trades in a futures account on an 

exchange, with the intent of optimizing market opportunities. 

The majority of TEP’s 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 enters into forward contracts that are not considered to be “normal 

purchases and sales” and therefore are accounted for as derivatives. When TEP has derivative forward contracts, it marks them to 

market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other 

Southwestern U.S. trading hubs. TEP believes that these broker quotations used to calculate the mark-to-market values represent 

accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk 

management policies, and the liquidity in the short-term market. 

Long-Term Wholesale Sales 

Prior to June 1, 2011, under the terms of the SRP contract, TEP received a monthly demand charge of approximately $1.8 million, 

or $22 million annually, and sold the energy at a price based on TEP’s average fuel cost. From June 1, 2011 to December 31, 

2011, SRP was required to purchase 73,000 MWh per month. From January 1, 2012 through the end of the contract in May 2016, 

SRP is required to purchase 500,000 MWh of 

 

K-73 
Table of Contents 

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 onpeak power on Palo Verde Market Index. As of February 21, 2012, the average forward price of on-peak power on the Palo Verde 

Market Index for the calendar year 2012 was $30.33 MWh. 

The chart below summarizes the annual change in pre-tax income if the market price of power on the Palo Verde Market Index 

changes by $5 per MWh. 

 

Natural Gas 

TEP is also subject to commodity price risk from changes in the price of natural gas. In addition to energy from its coal-fired 

facilities, TEP typically uses power purchases, supplemented by generation from its gas-fired units to meet the summer peak 

demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are price indexed to 

natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its 

increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gasindexed 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, 2011, TEP considered the impact of non-performance 

risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The adjustment 

required for TEP was less than $0.5 million at December 31, 2011. 

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, TEP recorded the 

following net unrealized gains (losses): 

 

The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts. 

 

Sensitivity Analysis of Derivatives 

TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its 

derivative forward contracts. TEP records unrealized gains and losses as either a regulatory asset or regulatory liability. As 

contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. The chart 

below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%. 

 

 

K-74 

 Change in Per MWh Price 

 $5 Increase $5 Decrease 

 -Millions of DollarsChange in Pre-Tax Income $ 3 $ (3 ) 

 2011 2010 2009 

 - Millions of Dollars - 

Unrealized Gains (Losses) $ (2 ) $ 4 $ 11 

 

Unrealized Gain (Loss) of TEP’s 

Hedging Activities 

 - Millions of Dollars - 

Source of Fair Value at Dec. 31, 2011 

Maturity 0 –6 

months 

Maturity 6 –12 

months 

Maturity 

over 1 yr. 

Total 

Unrealized 

Gain 

(Loss) 

Prices actively quoted $ (3 ) $ (5 ) $ (3 ) $ (11 ) 

Prices based on models and other valuation methods — 1 1 2 

 

Total $ (3 ) $ (4 ) $ (2 ) $ (9 ) 

 

 

 

 

 

 

 

 

 - Millions of Dollars - 

Change in Market Price As of December 31, 2011 10% Increase 10% Decrease 

Non-Cash Flow Hedges 

Forward power sales and purchase contracts $ 2 $ (2 ) 
Table of Contents 

Coal 

TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants. 

In 2003, TEP amended and extended the long-term coal supply contract for Springerville Units 1 and 2 through 2020 and expects 

coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives. 

During the extension period from 2011 through 2020, the coal price is determined by the cost of Powder River Basin coal delivered 

to Springerville Unit 3 subject to a floor and ceiling. This range would be from $19.30 to $26.15 per ton. TEP estimates its future 

minimum annual payments under this contract to be $14 million from 2012 through 2020. 

TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for Sundt Unit 4 on the spot market and 

can supply that unit with natural gas when the price is competitive with coal. Coal burned at Sundt Unit 4 represents less than 10% 

of TEP’s total coal consumption. In December 2011, the take-or-pay obligations under a coal transportation agreement previously 

effective through December 2015 were terminated. As a result, TEP is relieved of a $4 million obligation recognized under this 

contract in December 2010. TEP reversed a $4 million regulatory asset. TEP has a short-term coal supply contract for Sundt Unit 4 

ending December 31, 2012, and has hedged gas costs through September 2012. 

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan, where coal supplies are under 

long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned 

generating facilities to be sufficient for the remaining lives of the stations. 

The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an 

estimated average annual cost of $21 million for the next five years. See Item 7. – Management’s Discussion and Analysis of 

Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual 

Obligations and Note 4. 

UNS Gas 

UNS Gas is subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its customers. This 

risk is mitigated through the PGA mechanism which provides an adjustment to UNS Gas’ Retail Rates to recover the actual costs of 

gas and transportation. UNS Gas further reduces this risk by purchasing forward fixed price contracts or entering into financial gas 

swaps for a portion of its projected gas needs under its Price Stabilization Plan. UNS Gas purchases at least 45% of its estimated 

gas needs in this manner. 

As required by fair value accounting rules, for the year ended December 31, 2011, UNS Gas considered the impact of nonperformance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted. The 

adjustment required for UNS Gas was less than $0.5 million at December 31, 2011. 

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, UNS Gas recorded the 

following net unrealized gains (losses): 

 

For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net 

losses reported as a regulatory asset of $2 million, while a 10% increase in market prices would result in a decrease in unrealized 

net losses reported as a reduction in regulatory assets of $2 million. 

UNS Electric 

UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated 

through a PPFAC mechanism which allows for the recovery of costs from retail customers. The PPFAC mechanism has a forward 

component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased power 

costs. The true-up component reconciles actual fuel and 

 

K-75 

 2011 2010 2009 

 - Millions of Dollars - 

Unrealized Gains (Losses) $ (1 ) $ (2 ) $ 6 
Table of Contents 

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 $51 million in 2012, $37 million in 2013, and $28 million in 2014 based on natural gas prices at December 31, 2011. 

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 gains reported as a regulatory asset of $5 million, while a 10% increase in market prices would result in a decrease 

in unrealized net gains reported as a reduction in regulatory assets of $5 million. 

UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchased power agreements with fixed price 

contracts. In addition, UNS Electric hedges a portion of its anticipated natural gas exposure from plant fuel. UNS Electric currently 

has approximately 53% of this aggregate summer exposure hedged for the summer of 2012. 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. 

UNS Electric considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative 

liabilities net of collateral posted. The adjustment required for UNS Electric was less than $0.5 million at December 31, 2011. 

To adjust the value of its commodity derivatives to fair value in Regulatory Assets or Regulatory Liabilities, UNS Electric recorded 

the following net unrealized gains (losses): 

 

For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in an increase in unrealized net 

losses reported as a regulatory asset of $1 million, while a 10% increase in market prices would result in a decrease in unrealized 

net losses reported as a reduction in regulatory assets of $1 million. 

Credit Risk 

UniSource Energy is exposed to credit risk in its energy-related marketing activities related to potential nonperformance by 

counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring 

exposures, requiring collateral when needed, and using 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. 

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, 2011, the combined credit exposure to TEP, 

UNS Gas and UNS Electric from financial institution counterparties was approximately $4 million. 

 

K-76 

 2011 2010 2009 

 - Millions of DollarsUnrealized Gains (Losses) $ 1 $ (2 ) $ 12 
Table of Contents 

As of December 31, 2011, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was 

approximately $17 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit 

exposure, totaling approximately $4 million. TEP’s total exposure to non-investment grade counterparties was $4 million. 

At December 31, 2011, TEP posted no cash collateral and $1 million in letters of credit as credit enhancements with its 

counterparties, and did not hold any collateral from its counterparties. 

UNS Gas is subject to credit risk from non-performance by its supply and hedging counterparties to the extent that these contracts 

have a mark-to-market value in favor of UNS Gas. As of December 31, 2011, UNS Gas had purchased under fixed price contracts 

approximately 32% of its expected consumption for the 2012/2013 winter season. At December 31, 2011, UNS Gas had no markto-market credit exposure under its supply and hedging contracts . As of December 31, 2011, UNS Gas had posted no cash

collateral and no letters of credit 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, 2011, UNS Electric had $1 million in credit exposure under such contracts. As of 

December 31, 2011, UNS Electric had posted $6 million in letters of credit 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 

UniSource Energy—Management’s Report on Internal Controls Over Financial Reporting 

UniSource 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 UniSource Energy’s internal control over financial reporting as of December 31, 2011. 

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, 2011, UniSource 

Energy’s internal control over financial reporting was effective. 

The effectiveness of UniSource Energy’s internal control over financial reporting as of December 31, 2011, has been audited by 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report in Item 8 of this Annual 

Report on Form 10-K. 

Tucson Electric Power Company—Management’s Report on Internal Controls Over Financial Reporting 

Tucson Electric Power Company’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’s internal control over financial reporting as of 

December 31, 2011. 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, 2011, Tucson 

Electric Power Company’s internal control over financial reporting was effective. 

 

K-77 
Table of Contents 

Report of Independent Registered Public Accounting Firm 

To the Board of Directors and Stockholders of 

UniSource 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 UniSource Energy Corporation and its subsidiaries at December 31, 2011 and December 31, 

2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in 

conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial 

statement schedule listed in the Index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth 

therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, 

in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in 

Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 

(COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for 

maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over 

financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our 

responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s 

internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards 

of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 

to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective 

internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting 

principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our 

audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, 

assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal 

control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the 

circumstances. We believe that our audits provide a reasonable basis for our opinions. 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability 

of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted 

accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to

the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of 

the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial 

statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are 

being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable 

assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that 

could have a material effect on the financial statements. 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 

projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate 

because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 

 

 

K-78 

/s/PricewaterhouseCoopers LLP 

PricewaterhouseCoopers LLP 

Phoenix, Arizona 

February 27, 2012 
Table of Contents 

Report of Independent Registered Public Accounting Firm 

To the Board of Directors and Stockholder of 

Tucson Electric Power Company: 

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material 

respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2011 and December 31, 

2010 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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. 

 

 

K-79 

/s/PricewaterhouseCoopers LLP 

PricewaterhouseCoopers LLP 

Phoenix, Arizona 

February 27, 2012 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF INCOME 

 

See Notes to Consolidated Financial Statements. 

 

K-80 

 Years Ended December 31, 

 2011 2010 2009 

 - Thousands of Dollars - 

 (Except Per Share Amounts) 

Operating Revenues 

Electric Retail Sales $ 1,085,822 $ 1,051,002 $ 1,047,619 

Electric Wholesale Sales 163,159 151,962 131,255 

California Power Exchange (CPX) Provision for Wholesale Refunds — (2,970 ) (4,172 ) 

Gas Revenue 145,053 141,036 144,609 

Other Revenues 115,481 112,936 77,741 

 

Total Operating Revenues 1,509,515 1,453,966 1,397,052 

 

Operating Expenses 

Fuel 324,520 295,652 296,248 

Purchased Energy 307,423 307,288 296,861 

Transmission 7,334 10,945 10,181 

Decrease to Reflect PPFAC/PGA Recovery Treatment (4,932 ) (29,622 ) (14,553 ) 

 

Total Fuel and Purchased Energy 634,345 584,263 588,737 

Other Operations and Maintenance 379,220 370,037 333,579 

Depreciation 133,832 128,215 144,960 

Amortization 30,983 28,094 31,058 

Taxes Other Than Income Taxes 49,463 46,243 45,858 

 

Total Operating Expenses 1,227,843 1,156,852 1,144,192 

 

Operating Income 281,672 297,114 252,860 

 

Other Income (Deductions) 

Interest Income 4,568 7,779 12,072 

Other Income 8,293 11,038 18,063 

Other Expense (5,249 ) (15,202 ) (5,292 ) 

 

Total Other Income (Deductions) 7,612 3,615 24,843 

 

Interest Expense 

Long-Term Debt 73,217 65,020 58,134 

Capital Leases 40,359 46,740 49,270 

Other Interest Expense 2,535 1,651 3,468 

Interest Capitalized (3,753 ) (2,587 ) (2,302 ) 

 

Total Interest Expense 112,358 110,824 108,570 

 

Income Before Income Taxes 176,926 189,905 169,133 

Income Tax Expense 66,951 76,921 63,232 

 

Net Income $ 109,975 $ 112,984 $ 105,901 

 

 

 

 

 

 

Weighted-Average Shares of Common Stock Outstanding (000) 

Basic 36,962 36,415 35,858 

 

 

 

 

 

 

Diluted 41,609 41,041 40,450 

 

 

 

 

 

 

Earnings per Share 

Basic $ 2.98 $ 3.10 $ 2.95 

 

 

 

 

 

 

Diluted $ 2.75 $ 2.86 $ 2.73 

 

 

 

 

 

 

Dividends Declared per Share $ 1.68 $ 1.56 $ 1.16 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

 

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements. 

 Years Ended December 31, 

 2011 2010 2009 

 - Thousands of Dollars - 

Cash Flows from Operating Activities 

Cash Receipts from Electric Retail Sales $ 1,163,537 $ 1,142,364 $ 1,145,051 

Cash Receipts from Electric Wholesale Sales 183,151 194,580 175,679 

Cash Receipts from Gas Sales 159,529 157,397 162,725 

Cash Receipts from Operating Springerville Units 3 & 4 104,754 102,563 68,951 

Cash Receipts from Wholesale Gas Sales 12,404 422 716 

Performance Deposits Received 7,050 18,470 34,630 

Interest Received 6,334 10,026 13,470 

Income Tax Refunds Received 4,672 341 20,242 

Other Cash Receipts 23,937 32,011 26,176 

Purchased Energy Costs Paid (328,713 ) (364,132 ) (334,481 ) 

Payment of Other Operations and Maintenance Costs (291,607 ) (255,988 ) (246,895 ) 

Fuel Costs Paid (281,441 ) (247,484 ) (300,810 ) 

Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized (179,766 ) (163,037 ) (161,574 ) 

Wages Paid, Net of Amounts Capitalized (122,370 ) (125,893 ) (122,245 ) 

Interest Paid, Net of Amounts Capitalized (68,027 ) (59,749 ) (54,641 ) 

Capital Lease Interest Paid (32,103 ) (38,646 ) (38,598 ) 

Wholesale Gas Costs Paid (11,822 ) — — 

Performance Deposits Paid (4,550 ) (19,220 ) (22,260 ) 

Income Taxes Paid (700 ) (22,797 ) (9,050 ) 

Other Cash Payments (6,949 ) (14,308 ) (9,776 ) 

 

Net Cash Flows - Operating Activities 337,320 346,920 347,310 

 

Cash Flows from Investing Activities 

Capital Expenditures (374,122 ) (279,240 ) (294,020 ) 

Purchase of Intangibles - Renewable Energy Credits (5,992 ) (7,514 ) — 

Purchase of Sundt Unit 4 Lease Asset — (51,389 ) — 

Purchase of Springerville Lease Debt — — (31,375 ) 

Prepayment Deposits on UED Debt — (3,188 ) (3,625 ) 

Other Cash Payments (578 ) (2,302 ) (868 ) 

Return of Investments in Springerville Lease Debt 38,353 25,615 12,736 

Other Cash Receipts 15,251 12,958 20,508 

 

Net Cash Flows - Investing Activities (327,088 ) (305,060 ) (296,644 ) 

 

Cash Flows from Financing Activities 

Proceeds from Borrowings Under Revolving Credit Facilities 391,000 239,000 203,000 

Proceeds from Issuance of Long-Term Debt 340,285 127,815 — 

Proceeds from Stock Options Exercised 8,115 13,391 3,441 

Proceeds from Issuance of Short-Term Debt — — 30,000 

Other Cash Receipts 4,743 12,406 8,937 

Repayments of Borrowings Under Revolving Credit Facilities (351,000 ) (268,500 ) (198,000 ) 

Repayments of Long-Term Debt (252,125 ) (51,592 ) (6,000 ) 

Payments of Capital Lease Obligations (74,381 ) (55,997 ) (24,192 ) 

Common Stock Dividends Paid (61,904 ) (56,590 ) (41,429 ) 

Payments of Debt Issue/Retirement Costs (4,361 ) (8,341 ) (2,268 ) 

Other Cash Payments (1,813 ) (2,775 ) (2,405 ) 

 

Net Cash Flows - Financing Activities (1,441 ) (51,183 ) (28,916 ) 

 

Net Increase (Decrease) in Cash and Cash Equivalents 8,791 (9,323 ) 21,750 

Cash and Cash Equivalents, Beginning of Year 67,599 76,922 55,172 

 

Cash and Cash Equivalents, End of Year $ 76,390 $ 67,599 $ 76,922 

 

 

 

 

 

 

Non-Cash Financing Activity 

Repayment of UED Short-Term Debt $ — $ (3,188 ) $ (3,625 ) 

 

 

 

 

 

 
 

K-81 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED BALANCE SHEETS 

 

See Notes to Consolidated Financial Statements. 

(Consolidated Balance Sheets Continued) 

 

K-82 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

ASSETS 

Utility Plant 

Plant in Service $ 4,856,108 $ 4,452,928 

Utility Plant Under Capital Leases 582,669 583,374 

Construction Work in Progress 89,749 210,971 

 

Total Utility Plant 5,528,526 5,247,273 

Less Accumulated Depreciation and Amortization (1,869,300 ) (1,824,843 ) 

Less Accumulated Amortization of Capital Lease Assets (476,963 ) (460,932 ) 

 

Total Utility Plant - Net 3,182,263 2,961,498 

 

Investments and Other Property 

Investments in Lease Debt and Equity 65,829 103,844 

Other 34,205 61,676 

 

Total Investments and Other Property 100,034 165,520 

 

Current Assets 

Cash and Cash Equivalents 76,390 67,599 

Accounts Receivable - Customer 94,585 98,333 

Unbilled Accounts Receivable 51,464 53,084 

Allowance for Doubtful Accounts (5,572 ) (6,125 ) 

Fuel Inventory 33,263 29,216 

Materials and Supplies 82,649 65,832 

Derivative Instruments 11,966 5,214 

Regulatory Assets - Current 97,056 56,962 

Deferred Income Taxes - Current 23,158 30,822 

Other 32,577 30,091 

 

Total Current Assets 497,536 431,028 

 

Regulatory and Other Assets 

Regulatory Assets - Noncurrent 173,199 192,966 

Derivative Instruments 2,019 9,806 

Other Assets 30,180 30,425 

 

Total Regulatory and Other Assets 205,398 233,197 

 

Total Assets $ 3,985,231 $ 3,791,243 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED BALANCE SHEETS 

 

See Notes to Consolidated Financial Statements. 

(Consolidated Balance Sheets Concluded) 

 

K-83 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

CAPITALIZATION AND OTHER LIABILITIES 

Capitalization 

Common Stock Equity $ 888,474 $ 830,756 

Capital Lease Obligations 352,720 429,074 

Long-Term Debt 1,517,373 1,352,977 

 

Total Capitalization 2,758,567 2,612,807 

 

Current Liabilities 

Current Obligations Under Capital Leases 77,482 60,347 

Current Maturities of Long-Term Debt — 57,000 

Borrowing Under Revolving Credit Facility 10,000 — 

Accounts Payable - Trade 109,759 108,950 

Interest Accrued 38,302 39,120 

Accrued Taxes Other than Income Taxes 41,997 39,140 

Accrued Employee Expenses 24,917 26,969 

Customer Deposits 32,485 29,795 

Regulatory Liabilities - Current 41,911 69,483 

Derivative Instruments 36,467 30,574 

Other 5,151 1,678 

 

Total Current Liabilities 418,471 463,056 

 

Deferred Credits and Other Liabilities 

Deferred Income Taxes - Noncurrent 300,326 246,466 

Regulatory Liabilities - Noncurrent 234,945 201,329 

Derivative Instruments 20,403 22,969 

Pension and Other Postretirement Benefits 139,356 127,343 

Other 113,163 117,273 

 

Total Deferred Credits and Other Liabilities 808,193 715,380 

 

Commitments, Contingencies, and Proposed Environmental Matters (Note 4) 

 

Total Capitalization and Other Liabilities $ 3,985,231 $ 3,791,243 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF CAPITALIZATION 

 

See Notes to Consolidated Financial Statements. 

 

K-84 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

COMMON STOCK EQUITY 

Common Stock-No Par Value $ 725,903 $ 715,687 

 2011 2010 

Shares Authorized 75,000,000 75,000,000 

Shares Outstanding 36,918,024 36,541,954 

Accumulated Earnings 172,655 124,838 

Accumulated Other Comprehensive Loss (10,084 ) (9,769 ) 

 

Total Common Stock Equity 888,474 830,756 

 

PREFERRED STOCK 

No Par Value, 1,000,000 Shares Authorized, None Outstanding — — 

 

CAPITAL LEASE OBLIGATIONS 

Springerville Unit 1 253,481 302,229 

Springerville Coal Handling Facilities 65,022 76,583 

Springerville Common Facilities 111,699 110,571 

Other — 38 

 

Total Capital Lease Obligations 430,202 489,421 

Less Current Maturities (77,482 ) (60,347 ) 

 

Total Long-Term Capital Lease Obligations 352,720 429,074 

 

LONG-TERM DEBT 

Issue Maturity Interest Rate 

UniSource Energy: 

Convertible Senior Notes 2035 4.50% 150,000 150,000 

Credit Agreement 2016 Variable 57,000 27,000 

Tucson Electric Power Company: 

Variable Rate IDBs 2014 - 2016 Variable 215,300 365,300 

Unsecured Fixed Rate IDBs 2020 - 2040 3.25% to 6.375% 615,855 638,315 

Unsecured Notes 2021 5.15% 249,218 — 

UNS Gas and UNS Electric: 

Senior Unsecured Notes 2015 - 2026 5.39% to 7.1% 230,000 200,000 

UED: 

Secured Term Loan 2012 Variable — 29,362 

Total Stated Principal Amount 1,517,373 1,409,977 

Less Current Maturities — (57,000 ) 

 

Total Long-Term Debt 1,517,373 1,352,977 

 

Total Capitalization $ 2,758,567 $ 2,612,807 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME 

 

 

We describe limitations on our ability to pay dividends in Note 7. 

See Notes to Consolidated Financial Statements. 

 

 

Common 

Shares 

Outstanding* 

Common 

Stock 

Accumulated 

Earnings 

Accumulated 

Other 

Comprehensive 

Loss 

Total 

Stockholders’

Equity 

 - Thousands of Dollars - 

Balances at December 31, 2008 35,458 $ 687,360 $ 5,590 $ (6,855 ) $ 686,095 

 

Comprehensive Income: 

2009 Net Income 105,901 105,901 

Unrealized Loss on Cash Flow Hedges (net of $33 income taxes) 51 51 

Reclassification of Realized 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 106,954 

Dividends, Including Non-Cash Dividend Equivalents (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 Stock Compensation Plans 101 — — 

Other 4,490 4,490 

 

Balances at December 31, 2009 35,851 $ 696,206 $ 68,925 $ (5,802 ) $ 759,329 

 

Comprehensive Income: 

2010 Net Income 112,984 112,984 

Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes) (6,431 ) (6,431 ) 

Reclassification of Realized 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 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 Stock Compensation Plans 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 

Unrealized Loss on Cash Flow Hedges (net of $2,376 income taxes) (3,626 ) (3,626 ) 

Reclassification of Realized Losses on Cash Flow Hedges to Net Income (net 

of $1,412 income taxes) 2,153 2,153 

Employee Benefit Obligations Amortization of SERP Net Prior Service Cost 

Included in Net Periodic Benefit Cost (net of $804 income taxes) 1,158 1,158 

 

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 Stock Compensation Plans 57 — — 

Other 2,040 2,040 

 

Balances at December 31, 2011 36,918 $ 725,903 $ 172,655 $ (10,084 ) $ 888,474 

 

 

 

 

 

 

 

 

 

 

* UniSource Energy has 75 million authorized shares of Common Stock. 
K-85 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED STATEMENTS OF INCOME 

 

See Notes to Consolidated Financial Statements. 

 

K-86 

 Years Ended December 31, 

 2011 2010 2009 

 - Thousands of Dollars - 

Operating Revenues 

Electric Retail Sales $ 903,930 $ 868,188 $ 867,516 

Electric Wholesale Sales 129,861 141,103 153,306 

California Power Exchange (CPX) Provision for Wholesale Refunds — (2,970 ) (4,172 ) 

Other Revenues 122,595 118,946 82,688 

 

Total Operating Revenues 1,156,386 1,125,267 1,099,338 

 

Operating Expenses 

Fuel 318,268 284,744 279,303 

Purchased Power 105,766 118,716 144,529 

Transmission (1,435 ) 3,254 3,066 

Decrease to Reflect PPFAC Recovery Treatment (6,165 ) (21,541 ) (18,186 ) 

 

Total Fuel and Purchased Energy 416,434 385,173 408,712 

Other Operations and Maintenance 330,801 316,625 282,986 

Depreciation 104,894 99,510 116,970 

Amortization 34,650 32,196 35,931 

Taxes Other Than Income Taxes 40,226 37,732 37,406 

 

Total Operating Expenses 927,005 871,236 882,005 

 

Operating Income 229,381 254,031 217,333 

 

Other Income (Deductions) 

Interest Income 3,567 6,707 11,471 

Other Income 5,693 6,629 10,996 

Other Expense (12,037 ) (11,506 ) (9,589 ) 

 

Total Other Income (Deductions) (2,777 ) 1,830 12,878 

 

Interest Expense 

Long-Term Debt 49,858 42,378 36,226 

Capital Leases 40,358 46,734 49,258 

Other Interest Expense 1,127 433 1,571 

Interest Capitalized (2,073 ) (1,880 ) (1,752 ) 

 

Total Interest Expense 89,270 87,665 85,303 

 

Income Before Income Taxes 137,334 168,196 144,908 

Income Tax Expense 52,000 59,936 54,220 

 

Net Income $ 85,334 $ 108,260 $ 90,688 

 

 

 

 

 

 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

 

See Note 15 for supplemental cash flow information.

See Notes to Consolidated Financial Statements. 

 

K-87 

 Years Ended December 31, 

 2011 2010 2009 

 - Thousands of Dollars - 

Cash Flows from Operating Activities 

Cash Receipts from Electric Retail Sales $ 963,247 $ 947,498 $ 944,873 

Cash Receipts from Electric Wholesale Sales 152,618 190,779 199,918 

Cash Receipts from Operating Springerville Units 3 & 4 104,754 102,563 68,951 

Reimbursement of Affiliate Charges 18,448 18,356 19,998 

Cash Receipts from Wholesale Gas Sales 11,825 — — 

Income Tax Refunds Received 7,492 3,369 14,462 

Interest Received 5,367 8,998 12,768 

Performance Deposits Received 1,640 5,040 14,000 

Other Cash Receipts 17,971 18,389 19,440 

Payment of Other Operations and Maintenance Costs (283,560 ) (245,050 ) (233,075 ) 

Fuel Costs Paid (276,030 ) (236,436 ) (282,653 ) 

Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized (139,728 ) (134,540 ) (124,053 ) 

Purchased Power Costs Paid (117,224 ) (169,658 ) (185,129 ) 

Wages Paid, Net of Amounts Capitalized (100,942 ) (101,815 ) (97,289 ) 

Interest Paid, Net of Amounts Capitalized (45,433 ) (38,232 ) (33,128 ) 

Capital Lease Interest Paid (32,103 ) (38,640 ) (38,586 ) 

Wholesale Gas Costs Paid (11,822 ) — — 

Income Taxes Paid (2,346 ) (19,663 ) (14,606 ) 

Performance Deposits Paid (1,640 ) (5,040 ) (14,000 ) 

Other Cash Payments (4,240 ) (3,435 ) (3,827 ) 

 

Net Cash Flows - Operating Activities 268,294 302,483 268,064 

 

Cash Flows from Investing Activities 

Capital Expenditures (351,890 ) (225,920 ) (240,079 ) 

Purchase of Intangibles - Renewable Energy Credits (5,111 ) (7,903 ) — 

Purchase of Sundt Unit 4 Lease Asset — (51,389 ) — 

Purchase of Springerville Lease Debt — — (31,375 ) 

Other Cash Payments (558 ) (1,483 ) (411 ) 

Return of Investments in Springerville Lease Debt 38,353 25,615 12,736 

Other Cash Receipts 7,195 8,044 9,528 

 

Net Cash Flows - Investing Activities (312,011 ) (253,036 ) (249,601 ) 

 

Cash Flows from Financing Activities 

Proceeds from Issuance of Long-Term Debt 260,285 118,245 — 

Proceeds from Borrowings Under Revolving Credit Facility 220,000 177,000 171,000 

Equity Investment from UniSource Energy 30,000 15,000 30,000 

Other Cash Receipts 2,458 3,241 2,447 

Repayments of Borrowings Under Revolving Credit Facility (210,000 ) (212,000 ) (146,000 ) 

Repayments of Long-Term Debt (172,460 ) (30,000 ) — 

Payments of Capital Lease Obligations (74,343 ) (55,889 ) (24,091 ) 

Payments of Debt Issue/Retirement Costs (3,594 ) (5,988 ) (1,329 ) 

Dividends Paid to UniSource Energy — (60,000 ) (60,000 ) 

Other Cash Payments (894 ) (1,491 ) (1,347 ) 

 

Net Cash Flows - Financing Activities 51,452 (51,882 ) (29,320 ) 

 

Net Increase (Decrease) in Cash and Cash Equivalents 7,735 (2,435 ) (10,857 ) 

Cash and Cash Equivalents, Beginning of Year 19,983 22,418 33,275 

 

Cash and Cash Equivalents, End of Year $ 27,718 $ 19,983 $ 22,418 

 

 

 

 

 

 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED BALANCE SHEETS 

 

See Notes to Consolidated Financial Statements. 

(Consolidated Balance Sheets Continued) 

 

K-88 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

ASSETS 

Utility Plant 

Plant in Service $ 4,222,236 $ 3,863,431 

Utility Plant Under Capital Leases 582,669 582,669 

Construction Work in Progress 76,517 153,981 

 

Total Utility Plant 4,881,422 4,600,081 

Less Accumulated Depreciation and Amortization (1,753,807 ) (1,729,747 ) 

Less Accumulated Amortization of Capital Lease Assets (476,963 ) (460,257 ) 

 

Total Utility Plant - Net 2,650,652 2,410,077 

 

Investments and Other Property 

Investments in Lease Debt and Equity 65,829 103,844 

Other 32,313 43,588 

 

Total Investments and Other Property 98,142 147,432 

 

Current Assets 

Cash and Cash Equivalents 27,718 19,983 

Accounts Receivable - Customer 71,435 78,200 

Unbilled Accounts Receivable 32,386 32,217 

Allowance for Doubtful Accounts (3,766 ) (4,106 ) 

Accounts Receivable - Due from Affiliates 4,049 5,444 

Fuel Inventory 32,981 29,209 

Materials and Supplies 70,749 54,732 

Derivative Instruments 1,439 1,318 

Regulatory Assets - Current 71,747 34,023 

Deferred Income Taxes - Current 21,678 32,077 

Other 13,753 26,467 

 

Total Current Assets 344,169 309,564 

 

Regulatory and Other Assets 

Regulatory Assets - Noncurrent 157,386 182,304 

Derivative Instruments 1,398 1,834 

Other Assets 23,737 24,767 

 

Total Regulatory and Other Assets 182,521 208,905 

 

Total Assets $ 3,275,484 $ 3,075,978 

 

 

 

 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED BALANCE SHEETS 

 

See Notes to Consolidated Financial Statements. 

(Consolidated Balance Sheets Concluded) 

 

K-89 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

CAPITALIZATION AND OTHER LIABILITIES 

Capitalization 

Common Stock Equity $ 824,943 $ 709,884 

Capital Lease Obligations 352,720 429,074 

Long-Term Debt 1,080,373 1,003,615 

 

Total Capitalization 2,258,036 2,142,573 

 

Current Liabilities 

Current Obligations Under Capital Leases 77,482 60,309 

Borrowing Under Revolving Credit Facility 10,000 - 

Accounts Payable - Trade 84,508 77,021 

Accounts Payable - Due to Affiliates 4,827 3,990 

Interest Accrued 30,877 31,771 

Accrued Taxes Other than Income Taxes 32,155 29,873 

Accrued Employee Expenses 21,356 23,710 

Customer Deposits 23,743 21,191 

Derivative Instruments 9,040 7,288 

Regulatory Liabilities - Current 23,702 58,936 

Other 4,524 3,379 

 

Total Current Liabilities 322,214 317,468 

 

Deferred Credits and Other Liabilities 

Deferred Income Taxes - Noncurrent 263,225 227,615 

Regulatory Liabilities - Noncurrent 200,599 170,223 

Derivative Instruments 14,142 11,650 

Pension and Other Postretirement Benefits 130,660 120,590 

Other 86,608 85,859 

 

Total Deferred Credits and Other Liabilities 695,234 615,937 

 

Commitments, Contingencies, and Proposed Envirionmental Matters (Note 4) 

 

Total Capitalization and Other Liabilities $ 3,275,484 $ 3,075,978 

 

 

 

 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED STATEMENTS OF CAPITALIZATION 

 

See Notes to Consolidated Financial Statements. 

 

K-90 

 December 31, 

 2011 2010 

 - Thousands of Dollars - 

COMMON STOCK EQUITY 

Common Stock-No Par Value $ 888,971 $ 858,971 

 2011 2010 

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 (47,627 ) (132,961 ) 

Accumulated Other Comprehensive Loss (10,044 ) (9,769 ) 

 

Total Common Stock Equity 824,943 709,884 

 

PREFERRED STOCK 

No Par Value, 1,000,000 Shares Authorized, None Outstanding — — 

 

CAPITAL LEASE OBLIGATIONS 

Springerville Unit 1 253,481 302,229 

Springerville Coal Handling Facilities 65,022 76,583 

Springerville Common Facilities 111,699 110,571 

 

Total Capital Lease Obligations 430,202 489,383 

Less Current Maturities (77,482 ) (60,309 ) 

 

Total Long-Term Capital Lease Obligations 352,720 429,074 

 

LONG-TERM DEBT 

Issue Maturity Interest Rate 

Variable Rate IDBs 2014 - 2016 Variable 215,300 365,300 

Unsecured Fixed Rate IDBs 2020 - 2040 3.25% to 6.375% 615,855 638,315 

Unsecured Notes 2021 5.15% 249,218 — 

 

Total Long-Term Debt 1,080,373 1,003,615 

 

Total Capitalization $ 2,258,036 $ 2,142,573 

 

 

 

 
Table of Contents 

TUCSON ELECTRIC POWER COMPANY 

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME 

 

We describe limitations on our ability to pay dividends in Note 7. 

See Notes to Consolidated Financial Statements. 

 

K-91 

 

Common 

Stock 

Capital 

Stock 

Expense 

Accumulated 

Deficit 

Accumulated 

Other 

Comprehensive 

Loss 

Total 

Stockholder’s 

Equity 

 - Thousands of Dollars - 

Balances at December 31, 2008 $ 813,971 $ (6,357 ) $ (211,146 ) $ (6,855 ) $ 589,613 

 

Comprehensive Income: 

2009 Net Income 90,688 90,688 

Unrealized Loss on Cash Flow Hedges (net of $33 income taxes) 51 51 

Reclassification of Realized 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 91,741 

Capital Contribution from UniSource Energy 30,000 30,000 

Dividends (60,763 ) (60,763 ) 

 

Balances at December 31, 2009 843,971 (6,357 ) (181,221 ) (5,802 ) 650,591 

 

Comprehensive Income: 

2010 Net Income 108,260 108,260 

Unrealized Loss on Cash Flow Hedges (net of $4,216 income taxes) (6,431 ) (6,431 ) 

Reclassification of Realized 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 104,293 

Capital Contribution from UniSource 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 

Unrealized Loss on Cash Flow Hedges (net of $2,331 income taxes) (3,555 ) (3,555 ) 

Reclassification of Realized Losses on Cash Flow Hedges to Net Income 

(net of $1,390 income taxes) 2,122 2,122 

Employee Benefit Obligations Amortization of SERP Net Prior Service Cost 

Included in Net Periodic Benefit Cost (net of $804 income taxes) 1,158 1,158 

 

Total Comprehensive Income 85,059 

Capital Contribution from UniSource Energy 30,000 30,000 

 

Balances at December 31, 2011 $ 888,971 $ (6,357 ) $ (47,627 ) $ (10,044 ) $ 824,943 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 

NATURE OF OPERATIONS 

UniSource Energy Corporation (UniSource Energy) is a utility services holding company engaged, through its subsidiaries, in the 

electric generation and energy delivery business. Each of UniSource Energy’s subsidiaries is a separate legal entity with its own 

assets and liabilities. UniSource 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 UniSource Energy’s largest operating subsidiary, representing approximately 82% of 

UniSource Energy’s total assets as of December 31, 2011. TEP generates, transmits and distributes electricity to approximately 

404,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and 

power marketing entities, located primarily in the western U.S. In addition, TEP operates Springerville Unit 3 on behalf of Tri-State 

Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture 

Improvement and Power District (SRP). 

UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UNS 

Gas is a regulated gas distribution company, which services approximately 148,000 retail customers in Mohave, Yavapai, 

Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona. UNS Electric is a 

regulated public utility, which generates, transmits and distributes electricity to approximately 91,000 retail customers in Mohave 

and Santa Cruz counties. 

UED developed the Black Mountain Generating Station (BMGS) in northwestern Arizona. The facility includes two natural gas-fired 

combustion turbines. Prior to July 2011, UNS Electric received energy from BMGS through a power sales agreement with UED. In 

July 2011, UNS Electric purchased BMGS from UED, leaving UED with no significant remaining assets. The transaction had no 

impact on UniSource Energy’s consolidated financial statements. 

Millennium’s investments in unregulated businesses represent less than 1% of UniSource Energy’s assets as of December 31, 

2011. Millennium’s $13 million net loss for 2010, which reflected impairment losses, caused it to be a reportable segment at 

December 31, 2010. Millennium is not a reportable segment at December 31, 2011. 

Our business is comprised of three reporting segments – TEP, UNS Gas, and UNS Electric. 

References to “we” and “our” are to UniSource Energy and its subsidiaries, collectively. 

REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS 

In the second and third quarters of 2011, we identified errors related to amounts recorded as owed to or payable by TEP for 

electricity deliveries settled in-kind or to be settled in-kind during prior years under our transmission, interconnection and certain 

joint operating agreements. These agreements typically provide that the parties to such agreements will monitor transmission and 

delivery losses and other energy imbalances and make payments to each other to compensate for any losses and imbalances. 

Payments for such losses and imbalances are made in-kind with energy (MWh) rather than cash. The amount of these losses and 

imbalances is typically a very low portion of the energy flows subject to these agreements and is usually settled on a one day or 

one month lag. We also identified minor errors to prior year amounts billed to third parties for operations and maintenance expense. 

Separately, in the second quarter of 2011, we identified errors in prior years in the calculation of income tax expense arising from 

not treating Allowance for Equity Funds Used During Construction (AFUDC) as a permanent book to tax difference. 

We assessed the materiality of these errors on prior period financial statements and concluded they were not material to any prior 

annual or interim periods, but the cumulative impact, if recognized in 2011, could be material to the annual period ending 

December 31, 2011 and the interim period ended June 30, 2011. As a result, in accordance with Staff Accounting Bulletin 108, we 

revised our prior period financial statements to correct these 

 

K-92 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

errors. We assessed the materiality of the third quarter 2011 errors, together with the errors identified in the first half of 2011, on 

prior period financial statements and concluded that, while they were not material to any prior annual or interim periods, we should 

update the prior revision to reflect all of the errors identified in 2011. 

The income tax adjustment affected fiscal years 2003 through 2010 for UniSource Energy and fiscal years 2009 and 2010 for TEP. 

The adjustment for transmission and delivery losses and energy imbalances settled in-kind or to be settled in-kind affected fiscal 

years 2004 through 2010. The operations and maintenance expense adjustment affected fiscal years 2006 through 2010. The 

revision increased UniSource Energy’s net income by $2 million for each of the years ended December 31, 2010 and 2009. The 

revision increased TEP’s net income by $1 million for each of the years ended December 31, 2010 and 2009. UniSource Energy’s 

Accumulated Earnings increased by $7 million for the periods prior to January 1, 2009, as a result of the revisions. 

The revised amounts include reclassifications to conform to the current year presentation. TEP reclassified Other Operations and 

Maintenance costs of $7 million in 2010, and $6 million in 2009 to Other Expense to correctly account for the regulatory treatment 

of certain expenses. 

The revision and reclassifications impacted statements of income and balance sheets as shown in the tables below: 

 

 

K-93 

 UniSource Energy TEP 

 

Year Ended 

December 31, 2010 

 

As 

Reported 

As 

Revised 

As 

Reported 

As 

Revised 

 -Thousands of Dollars- (Except Per Share Amounts) 

Income Statement 

Electric Wholesale Sales $ 151,673 $ 151,962 $ 140,815 $ 141,103 

Fuel 296,980 295,652 286,071 284,744 

Purchased Energy 307,288 307,288 118,716 118,716 

Decrease to Reflect PPFAC/PGA Recovery Treatment (31,105 ) (29,622 ) (23,025 ) (21,541 ) 

Other Operations and Maintenance 370,067 370,037 323,537 316,625 

Income Tax Expense 78,266 76,921 61,057 59,936 

Net Income 111,477 112,984 106,978 108,260 

Basic EPS 3.06 3.10 N/A N/A 

Diluted EPS 2.82 2.86 N/A N/A 

Balance Sheet 

Accounts Receivable -Customer 91,556 98,333 71,425 78,200 

Deferred Income Taxes –Current Assets 32,386 30,822 33,640 32,077 

Regulatory Assets -Noncurrent 196,736 192,966 186,074 182,304 

Common Stock Equity 828,368 830,756 707,495 709,884 

Accounts Payable -Trade 109,896 108,950 77,967 77,021 

Deferred Income Taxes –Noncurrent Liabilities 246,466 246,466 227,615 227,615 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

BASIS OF PRESENTATION 

We consolidate our investments in subsidiaries when we hold a majority of the voting stock and we can exercise control over the 

operations and policies of the company. Consolidation means accounts of the parent and subsidiary are combined and 

intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not 

eliminated. 

We used the equity and cost methods to report Millennium’s investments until the assets became fully impaired in 2010. See Note 

13. 

USE OF ACCOUNTING ESTIMATES 

Management makes estimates and assumptions when preparing financial statements under generally accepted accounting 

principles (GAAP) in the U.S. These estimates and assumptions affect: 

 

 

 

Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual amounts may 

differ from the estimates. 

ACCOUNTING FOR RATE REGULATION 

We generally use the same accounting policies and practices used by unregulated companies. However, sometimes regulatory 

accounting requires that rate-regulated companies apply special accounting treatment to show the effect of rate regulation. For 

example, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory 

assets represent incurred costs that have been deferred because they are probable of future recovery in customer Retail Rates. 

Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are 

expected to be returned to customers through billing reductions. We evaluate regulatory assets each period and believe recovery is 

probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. 

We apply regulatory accounting as the following conditions exist: 

 

 

 

 

K-94 

 UniSource Energy TEP 

 

Year Ended 

December 31, 2009 

 

As 

Reported 

As 

Revised 

As 

Reported 

As 

Revised 

 -Thousands of Dollars- (Except Per Share Amounts) 

Income Statement 

Electric Wholesale Sales $ 130,904 $ 131,255 $ 152,955 $ 153,306 

Fuel 298,655 296,248 281,710 279,303 

Purchased Energy 296,861 296,861 144,528 144,529 

Decrease to Reflect PPFAC/PGA Recovery Treatment (17,091 ) (14,553 ) (20,724 ) (18,186 ) 

Other Operations and Maintenance 333,887 333,579 289,765 282,986 

Income Tax Expense 64,348 63,232 55,130 54,220 

Net Income 104,258 105,901 89,248 90,688 

Basic EPS 2.91 2.95 N/A N/A 

Diluted EPS 2.69 2.73 N/A N/A 

 • Assets and liabilities in 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. 

 • 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. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

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. 

UTILITY PLANT 

Utility Plant includes the business property and equipment that supports electric and gas services, consisting primarily of 

generation, transmission and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, 

contractor services, construction overhead (where applicable), and an Allowance for Funds Used During Construction (AFUDC). 

We record the cost of repairs and maintenance, including planned major overhauls to Other Operations and Maintenance Expense 

on the income statements 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 value. There is no income statement impact.

AFUDC and Capitalized Interest 

AFUDC reflects the cost of debt or equity funds used to finance construction and is capitalized as part of the cost of regulated utility 

plant. AFUDC amounts capitalized are included in rate base for establishing Retail Rates. For operations that do not apply 

regulatory accounting, we capitalize interest related only to debt as a cost of construction. The interest capitalized that relates to 

debt reduces Other Interest Expense on the income statements. The cost capitalized for equity funds is recorded as Other Income. 

 

UniSource Energy capitalized interest at a rate of 3.30% for 2011 and 1.96% for 2010 related to the development of a new 

corporate headquarters. 

Depreciation 

We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic 

lives of the assets. See Note 5. The ACC approves depreciation rates for all utility plant. TEP transmission assets are subject to 

FERC jurisdiction. Depreciation rates are based on average useful lives and reflect estimated removal costs, net of estimated 

salvage value for interim retirements. Below are the summarized average annual depreciation rates for all utility plants. 

 

 

K-95 

Average AFUDC Rate on Regulated Construction Expenditures 2011 2010 2009 

TEP 6.72 % 6.65 % 6.40 % 

UNS Gas 8.32 % 8.19 % 7.05 % 

UNS Electric 8.18 % 8.22 % 7.62 % 

 TEP UNS Gas UNS Electric UED 

2011 3.15 % 3.32 % 4.31 % 3.03 % 

2010 3.14 % 2.83 % 4.35 % 2.57 % 

2009 3.64 % 2.76 % 4.33 % 2.57 % 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Computer Software Costs 

We capitalize costs incurred to purchase and develop 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 under Capital Leases 

TEP financed the following generation assets with capital leases: Springerville Common Facilities, Springerville Unit 1 and the 

Springerville Coal Handling Facilities. The amount of lease expense incurred for TEP’s generation-related capital leases consists of 

amortization expense, as described in Note 5, and Interest Expense on Capital Leases as reflected on the income statements. The 

lease terms are described in Note 6. 

INVESTMENTS IN LEASE DEBT AND EQUITY 

TEP holds investments in lease debt in TEP’s Springerville Unit 1 capital leases. These holdings are considered held-to-maturity 

investments because TEP has the ability and intent to hold them until maturity. TEP records these investments at amortized cost 

and recognizes interest income. The fair value of these investments is described in Note 11. These investments do not reduce the 

capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a 

trustee who then distributes the payments to debt and equity holders. 

TEP accounts for its 14% equity interest in the Springerville Unit 1 lease trust using the equity method. 

JOINTLY-OWNED FACILITIES 

TEP has investments in several generation and transmission facilities jointly-owned with other companies. These projects are 

accounted for on a proportionate consolidation basis. See Note 5. 

ASSET RETIREMENT OBLIGATIONS 

TEP and UNS Electric record a liability for the estimated present value of a conditional asset retirement obligation as follows: 

 

 

When the liability is initially recorded at net present value, TEP and UNS Electric capitalize the cost by increasing the carrying 

amount of the related long-lived asset. TEP and UNS Electric adjust the liability to its present value by recognizing accretion 

expense in Other Operations and Maintenance expense, and the capitalized cost is depreciated in Depreciation and Amortization 

expense over the useful life of the related asset. 

TEP and UNS Electric record cost of removal for generation assets that are recoverable through Retail Rates charged to 

customers. See Note 2. We record cost of removal for transmission and distribution assets through depreciation rates and recover 

those amounts in Retail Rates charged to customers. There are no legal obligations associated with these assets. We have 

recorded an obligation for estimated costs of removal as regulatory liabilities. 

EVALUATION OF ASSETS FOR IMPAIRMENT 

We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the 

assets may be impaired. If discounted expected future cash flows are less than the carrying value of the asset, an impairment loss 

is recognized if the impairment is other than temporary and the loss is not recoverable through rates, and the asset is written down 

to the fair value of the asset. 

 

K-96 

 

• 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. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

DEFERRED FINANCING COSTS 

We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this 

approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other 

costs such as legal, accounting, regulatory fees and printing costs. 

We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the 

remaining life of the original debt. 

UTILITY OPERATING REVENUES 

We record utility operating revenues when services or commodities are delivered to customers. Operating revenues include an 

estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. 

We determine amounts delivered through periodic readings of customer meters. At the end of the month, the usage since the last 

meter reading is estimated and the corresponding unbilled revenue is calculated. Unbilled revenue is estimated based on daily 

generation or purchased volumes, estimated customer usage by class, estimated line losses and estimated average customer 

Retail Rates. Accrued unbilled revenues are reversed the following month when actual billings occur. The accuracy of the unbilled 

revenue estimate is affected by factors that include fluctuations in energy demands, weather, line losses, customer Retail Rates 

and changes in the composition of customer classes.

We are authorized a rate-adjustment mechanism that provides for the recovery of actual fuel, transmission and purchased 

power/energy cost. The revenue surcharge or surcredit adjusts the customers’ retail rate for delivered electricity or gas to collect or 

return under- or over- recovered energy costs. The ACC revises these rate-adjustment mechanisms periodically (annually for TEP 

and UNS Electric; monthly for UNS Gas) and may increase or decrease the level of costs recovered through Retail Rates for any 

difference between the total amount collected under the clauses and the recoverable costs incurred. See Note 2. 

Arizona’s mandatory Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy 

and allows recovery of RES compliance costs through a surcharge to customers. We charge customers a Demand Side 

Management (DSM) surcharge to recover the cost of ACC-approved energy efficiency programs. We defer differences between 

actual RES or DSM qualified costs incurred and the recovery of such costs through the RES and DSM surcharges. Cost overrecoveries (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 are 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 contracts that are not settled with energy, TEP nets the sales contracts with the purchase power contracts and reflects the net 

amount as Electric Wholesale Sales. The corresponding cash receipts are recorded in the statement of cash flows as Cash 

Receipts from Electric Wholesale Sales, while cash payments are recorded as Purchased Energy Costs Paid. 

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The 

allowance is determined based on historical bad debt patterns, retail sales and economic conditions. We refer uncollected accounts 

to external collection agencies after 90 days. 

TEP recognizes revenue from operating Springerville Unit 3 and 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, Tri-State and 

SRP reimburse TEP for various operating costs at the Springerville generating station. 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. 

Operating expenses are recorded in the respective line item of the income statements based on the nature of service or materials 

provided. 

 

K-97 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

INVENTORY 

Materials and supplies consist of transmission, distribution and generation construction and repair materials. We record fuel, 

materials and supply inventories at the lower of weighted average cost or market prices. We capitalize handling and procurement 

costs (such as materials, labor, overhead costs and transportation costs) as part of the cost of the inventory. 

RECOVERY OF FUEL AND PURCHASED ENERGY COSTS 

TEP and UNS Electric Purchased Power and Fuel Adjustment Clause (PPFAC) 

TEP and UNS Electric defer differences between actual fuel, transmission and purchased power costs and current PPFAC costs 

incurred and the recovery of such costs in base rates. Cost over-recoveries (the excess of fuel costs recoveries in Base Rates over 

actual costs incurred) are deferred as regulatory liabilities and cost under-recoveries (the excess of actual costs incurred over fuel 

costs recovered in Base Rates) are deferred as regulatory assets. See Note 2. 

UNS Gas Purchased Gas Adjustor (PGA) 

UNS Gas defers the difference between actual gas costs incurred and the recovery of such costs under a Purchased Gas Adjustor 

(PGA) mechanism. Gas cost over-recoveries (the excess of gas costs recovered under the PGA mechanism over actual gas costs 

incurred) are deferred as regulatory liabilities and under-recoveries (the excess of actual gas costs incurred over gas costs 

recovered via the PGA mechanism) are deferred as regulatory assets. See Note 2. 

RENEWABLE ENERGY CREDITS (RECs) 

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 purchase renewable energy, the premium paid above conventional power is the REC 

cost, a qualified cost recoverable through the RES surcharge, and the remaining cost is recoverable through the PPFAC. 

When RECs are purchased, TEP and UNS Electric record the cost of the RECs as Other Assets, and a corresponding regulatory 

liability, to reflect the obligation to use the RECs for future RES compliance. Unretired RECs are recorded as Other Assets on the 

balance sheet. RECs are expensed to the income statements when the RECs are reported to the ACC for compliance with the RES 

requirements. 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 the financial statements. 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 when we believe it is 

more likely than not that the deferred asset will not be realized. 

Tax benefits are recognized in the financial statements 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 positions taken on tax returns 

which have not been reflected in the financial statements. 

 

K-98 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were 

recognized on tax returns. Regulatory Assets – Noncurrent includes Income Taxes Recoverable Through Future Rates, which 

reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 2. 

We account for Federal Energy Credits 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 by the tax expense attributable to the reduction in tax basis 

required to be recognized. All other federal and state income tax credits are treated as a reduction to income tax expense in the 

year the credit arises. 

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax 

return. 

TAXES OTHER THAN INCOME TAXES 

We act as conduits or collection agents for sales taxes, utility taxes, franchise fees and regulatory assessments. As we bill 

customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to 

governmental agencies for these taxes and assessments. These amounts are not reflected in the income statements. 

DERIVATIVE FINANCIAL INSTRUMENTS 

Risks and Overview 

We are exposed to energy price risk associated with gas and purchased power requirements, volumetric risk associated with 

seasonal load, and operational risk associated with power plants, transmission and transportation systems. We reduce our energy 

price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: 

creating price stability; ensuring we can meet load and reserve requirements; and reducing exposure to price volatility that may 

result from delayed recovery under the PPFAC or PGA. See Note 2. 

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset 

position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We 

also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position 

and allocate the credit risk adjustment to all individual contracts. 

We present cash collateral and derivative assets and liabilities associated with the same counterparty separately in our financial 

statements, and we bifurcate all derivatives into current and long-term portions on the balance sheet.

Cash Flow Hedges 

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the Springerville 

Common Facilities Lease and variable rate industrial development bonds. 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 fix the UNS Electric term loan variable interest rate. TEP and UNS Electric account for cash flow hedges 

as follows: 

 

 

 

K-99 

 

• The effective portion of the changes in the fair value of the interest rate swaps and TEP’s six-year power purchase swap 

agreement are recorded in Accumulated Other Comprehensive Income (AOCI) and the ineffective portion, if any, is 

recognized in earnings; and 

 

• When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a 

hedged item, TEP and UNS Electric recognize the changes in fair value in earnings. The unrealized gains and losses at 

that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

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’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 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. Unrealized gains and losses are recorded as either a regulatory asset or regulatory liability to the extent they 

qualify for recovery through the PPFAC. 

In 2009 through 2011 we had no trading activity. 

 

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 UNS Gas 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 UNS Electric PPFAC mechanism allows recovery of the prudent 

costs of contracts for hedging fuel and purchased power costs. 

Normal Purchase and Normal Sale 

We enter into forward energy purchase and sales contracts, including call options, to support our current load forecasts, with 

counterparties for load serving requirements or counterparties with generating capacity. These contracts are not required to be 

marked-to-market and are accounted for on an accrual basis. We evaluate our counterparties on an ongoing basis for nonperformance risk to ensure it does not impact our ability to obtain the normal scope exception. 

PENSION AND OTHER POSTRETIREMENT BENEFITS 

We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits 

are based on employees’ years of service and average compensation. We also maintain a Supplemental Executive Retirement 

Plan for upper management. TEP also provides limited health care and life insurance benefits for retirees. 

Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that we evaluate 

annually. See Note 9. 

 

K-100 

 • TEP 

 • UNS Gas 

 • UNS Electric 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

NOTE 2. REGULATORY MATTERS 

RATES AND REGULATION 

The ACC and the FERC each regulate portions of the utility accounting practices and rates used by TEP, UNS Gas and UNS 

Electric. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of 

securities, and transactions with affiliated parties. The FERC regulates terms and prices of transmission services and wholesale 

electricity sales. 

TEP 2008 Rate Order 

The 2008 TEP Rate Order, issued by the ACC and effective December 1, 2008, provided an average base rate increase of 6% 

over TEP’s previous Base Rates; an 8% authorized rate of return on original cost rate base; a fuel rate included in Base Rates of 

2.9 cents per kilowatt-hour (kWh); a PPFAC effective January 1, 2009; and a base rate increase moratorium through January 1, 

2013. 

2010 UNS Gas Rate Order 

Effective April 2010, the ACC approved a base rate increase of 2% ($3 million), including an 8% authorized rate of return on 

original cost rate base. 

Pending UNS Gas Rate Case 

In April 2011, UNS Gas filed a general rate case (on a cost-of-service basis) with the ACC requesting a base rate increase of 3.8% 

to cover a revenue deficiency of $5.6 million. 

In February 2012, ACC Staff recommended a base rate increase of $2.7 million as well as a mechanism to enable UNS Gas to 

recover lost fixed-cost revenues as a result of implementing the ACC’s EE Standards. The ACC is expected to issue a final order in 

the second quarter of 2012. 

2008 UNS Electric Rate Order 

In May 2008, the ACC approved a base rate increase of 2.5% ($4 million) effective June 2008. 

2010 UNS Electric Rate Order 

In September 2010, the ACC approved a base rate increase of 4% ($7 million), including an 8% authorized rate of return on original 

cost rate base, effective October 1, 2010. The ACC approved new depreciation rates effective in October 2010. 

In July 2011, UNS Electric completed the ACC and FERC approved purchase of BMGS from UED for $63 million, UED’s book 

value for the assets. BMGS was included in UNS Electric’s rate base through a revenue-neutral rate reclassification of 

approximately 0.7 cents per kWh from base power supply rate to non-fuel Base Rates. 

COST RECOVERY MECHANISMS 

TEP, UNS Gas and UNS Electric have received regulatory decisions that allow for more timely recovery of certain costs through the 

following recovery mechanisms. 

 

K-101 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Purchased Power and Fuel Adjustment Clause (PPFAC) 

The PPFAC provides for the adjustment of Retail Rates to reflect variations in retail fuel, transmission and purchased power costs, 

including demand charges, and the prudent costs of contracts for hedging fuel. TEP and UNS Electric record deferrals for recovery 

or refund to the extent actual retail fuel, transmission and purchased power costs vary from the fuel rate and current PPFAC rates. 

The TEP PPFAC became effective in January 2009. A PPFAC rate adjustment is made annually each April 1st (unless otherwise 

approved by the ACC) and goes into effect for the subsequent 12-month period automatically unless suspended by the ACC. UNS 

Electric’s PPFAC rate adjustment is made annually each June 1 , effective for the subsequent 12-month period. 

The PPFAC rate includes (a) a “Forward Component,” under which TEP and UNS Electric recover or refund differences between 

forecasted fuel, transmission and purchased power costs for the upcoming calendar year and those embedded in the fuel rate and 

the current PPFAC rates; (b) a “True-up Component,” which reconciles differences between actual fuel, transmission and 

purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 

12-month period. 

The table below summarizes TEP’s and UNS Electric’s PPFAC rates in cents per kWh that are compared against actual fuel cost to 

create regulatory assets or liabilities: 

 

 

 

As part of the 2008 Rate Order, TEP was required to credit previously collected revenues to customers through the PPFAC. As a 

result, the PPFAC charge has been zero since it became effective in January 2009. In November 2011, the Fixed CTC revenue 

was fully refunded to customers and TEP began deferring the PPFAC eligible costs until a new PPFAC rate is approved by the 

ACC. 

The following table shows the changes in TEP’s PPFAC related accounts and the impacts on revenue and expense for the year 

ended December 31, 2011: 

 

For the year ended December 31, 2010, changes in the deferred PPFAC regulatory asset (liability) resulted in a $10 million 

increase to revenue and a $22 million decrease to fuel and purchased power expense. 

 

K-102 

 2011 2010 

 

June -

December 

April -

May 

January -

March 

June –

December 

April -

May 

January -

March 

TEP 

PPFAC 0.53 0.53 0.09 0.09 0.09 0.18 

CTC (0.53 ) (0.53 ) (0.09 ) (0.09 ) (0.09 ) (0.18 ) 

 

Total PPFAC Rate — — — — — — 

UNS Electric (0.88 ) 0.08 0.08 (0.28 ) (1.06 ) (1.06 ) 

(1) Competition Transition Charge 

(2) TEP’s first PPFAC rate began April 2009 at 0.18 cents per kWh. UNS Electric’s PPFAC rate from January to May 2009 was 

1.50 cents per kWh, and the PPFAC rate from June to December 2009 was (1.06) cents per kWh. 

 

Assets 

(Liability) at 

December 31, 

Year Ended 

December 31, 2011 

 2011 2010 

Increase to 

Revenue 

Reduction to 

Fuel and 

Purchased 

Power Expense 

 -Millions of DollarsPPFAC - Fixed CTC Revenue to be Refunded (current and 

noncurrent) $ — $ (36 ) $ 36 

 

 

 

 

 

 

 

PPFAC (current and noncurrent) $ 60 $ 54 $ 6 

 

 

 

 

 

 

st 

(2) 

(1) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

UNS Gas Purchased Gas Adjustor (PGA) 

The PGA mechanism provides for the adjustment of Retail Rates to reflect variations in natural gas costs. UNS Gas records 

deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, 

rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, 

but it is restricted from rising or falling more than $0.15 per therm in a twelve-month period. UNS Gas is required to request an 

additional surcredit if deferral balances reflect $10 million or more on a billed basis. 

The PGA rate ranged from $0.6593 to $0.7296 cents per therm in 2011, and ranged from $0.6433 to $0.7306 cents per therm in 

2010. 

RES and Energy Efficiency Standards 

The ACC has a mandatory RES that requires TEP and UNS Electric to expand their use of renewable energy through efforts 

funded by customer surcharges. TEP and UNS Electric are required to file five-year implementation plans with the ACC and 

annually seek approval for the upcoming year’s RES funding amount. Similarly, TEP, UNS Gas and UNS Electric recover the cost 

of ACC-approved energy efficiency programs through DSM surcharges established by the ACC. 

The following table shows RES and DSM tariffs collected: 

 

Renewable Energy Standard 

In 2010, the ACC approved: 

 

 

In 2011, the ACC approved TEP’s 2012 RES implementation plan. The plan allows TEP to invest $28 million in 2012, and $8 

million in 2013 for TEP-owned solar projects. 

The funding mechanism allows TEP and UNS Electric to use RES funds to recover operating costs, depreciation, and property 

taxes and to earn a return on company-owned solar projects until the projects can be incorporated in Base Rates. 

TEP and UNS Electric entered into multiple ACC approved long-term purchase power agreements with companies developing 

renewable energy generation facilities. TEP and UNS Electric are required to purchase the full output of each facility for 20 years. 

Both utilities are authorized to recover a portion of the cost of renewable energy through the PPFAC, with the balance of costs 

recoverable through the RES tariff. 

 

K-103 

 TEP RES UNS Electric RES TEP DSM UNS Gas DSM 

UNS Electric 

DSM 

 -Millions of Dollars2011 $ 35 $ 7 $ 11 $ 1 $ 2 

2010 32 7 10 1 2 

2009 29 5 7 1 1 

 

• A funding mechanism for approximately $14 million of TEP-owned renewable energy projects in 2010, and approximately 

$5 million in UNS Electric owned solar projects per year between 2011 and 2014. TEP’s projects were completed in 

2010, and TEP began recovering its costs through the RES tariff in January 2011. 

 

• TEP’s 2011 RES implementation plan. As approved by the plan, TEP invested $28 million in TEP-owned solar projects in 

2011. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Electric Energy Efficiency Standards 

In 2010, the ACC approved new Electric Energy Efficiency (EE) Standards designed to require TEP and UNS Electric to implement 

cost-effective Demand Side Management (DSM) programs, effective in 2011. In 2011, the EE Standards targeted total retail kWh 

savings equal to 1.25% of 2010 sales increasing to 22% by 2020. The EE Standards provide for a DSM surcharge to recover the 

costs to implement DSM programs. 

In January 2012, the ACC granted UNS Electric a waiver from complying with the 2011 and 2012 EE Standards. 

The ACC approved new Gas EE Standards which required UNS Gas to implement cost effective DSM programs to reduce total 

retail therm sales in 2011, by 701,113 therms, or 0.5% of 2010 sales. Targeted savings increase annually in subsequent years until 

they reach a cumulative annual reduction in retail therm sales of 6% by 2020. 

In January 2012, TEP filed a modification to its 2012/2013 Energy Efficiency Implementation Plan with the ACC. The proposal 

includes a request for an increase in the performance incentive based on TEP’s ability to meet the EE targets for 2012 and for 

2013. TEP’s proposed annual performance incentive in each of 2012 and 2013 ranges from $6 million to $8 million. 

Renewable Energy Credits 

The following table shows the REC activity for 2011 and 2010: 

 

 

K-104 

 UniSource Energy TEP 

 December 31, December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsBeginning Balance, included in Other Assets $ 3 $ — $ 2 $ — 

RECs Purchased 6 8 5 8 

RECs Recovered Through Revenues (RES surcharge) (8 ) (5 ) (7 ) (6 ) 

 

Ending Balance, included in Other Assets $ 1 $ 3 $ — $ 2 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Regulatory Assets and Liabilities 

The following tables summarize regulatory assets and liabilities: 

 

 

K-105 

 December 31, 2011 

 TEP 

UNS 

Gas 

UNS 

Electric 

UniSource 

Energy 

 -Millions of DollarsRegulatory Assets—Current 

Property Tax Deferrals $ 16 $ — $ — $ 16 

Derivative Instruments (Notes 11 and 16) 7 7 10 24 

Deregulation Costs 3 — — 3 

PPFAC 34 — 7 41 

DSM 8 — 1 9 

Other Current Regulatory Assets 4 — — 4 

 

Total Regulatory Assets—Current 72 7 18 97 

 

Regulatory Assets—Noncurrent 

Pension and Other Postretirement Benefits (Note 9) 107 3 4 114 

Income Taxes Recoverable through Future Revenues 10 — 2 12 

PPFAC/PGA 6 — — 6 

PPFAC—Final Mine Reclamation and Retiree Health Care Costs 20 — — 20 

Derivative Instruments (Notes 11 and 16) 2 2 3 7 

Other Regulatory Assets 12 1 1 14 

 

Total Regulatory Assets—Noncurrent 157 6 10 173 

 

Regulatory Liabilities—Current 

PPFAC/PGA — (15 ) — (15 ) 

RES (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 (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 ) 

 

 

 

 

 

 

 

 

(1) 

(2) 

(3) 

(3) 

(4) 

(5) 

(3) 

(6) 

(4) 

(7) 

(7) 

(8) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. 

We describe regulatory assets and state when we earn a return below: 

 

 

 

 

 

 

Regulatory liabilities represent items that TEP 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: 

 

K-106 

 December 31, 2010 

 TEP 

UNS 

Gas 

UNS 

Electric 

UniSource 

Energy 

 -Millions of DollarsRegulatory Assets—Current 

Property Tax Deferrals $ 16 $ — $ — $ 16 

Derivative Instruments (Notes 11 and 16) 5 8 12 25 

Deregulation Costs 4 — — 4 

PPFAC — — 3 3 

DSM 5 — — 5 

Other Current Regulatory Assets 4 — — 4 

 

Total Regulatory Assets—Current 34 8 15 57 

 

Regulatory Assets—Noncurrent 

Pension and Other Postretirement Benefits (Note 9) 90 2 2 94 

Income Taxes Recoverable through Future Revenues 22 — 1 23 

PPFAC/PGA 37 — — 37 

PPFAC—Final Mine Reclamation and Retiree Health Care Costs 17 — — 17 

Deregulation Costs 3 — — 3 

Derivative Instruments (Notes 11 and 16) — 2 2 4 

Other Regulatory Assets 13 2 — 15 

 

Total Regulatory Assets—Noncurrent 182 6 5 193 

 

Regulatory Liabilities—Current 

PPFAC/PGA — (9 ) — (9 ) 

PPFAC—Fixed CTC Revenue to be Refunded (36 ) — — (36 ) 

RES (22 ) — (1 ) (23 ) 

Other Current Regulatory Liabilities (1 ) — — (1 ) 

 

Total Regulatory Liabilities—Current (59 ) (9 ) (1 ) (69 ) 

 

Regulatory Liabilities—Noncurrent 

Net Cost of Removal for Interim Retirements (169 ) (22 ) (9 ) (200 ) 

Other Regulatory Liabilities (1 ) — — (1 ) 

 

Total Regulatory Liabilities—Noncurrent (170 ) (22 ) (9 ) (201 ) 

 

Total Net Regulatory Assets (Liabilities) $ (13 ) $ (17 ) $ 10 $ (20 ) 

 

 

 

 

 

 

 

 

(1) Property Tax is recovered over an approximately 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 earns a return on this asset and is recovering these costs through Retail Rates over a four-year 

period ending November 2012. 

(3) See Cost Recovery Mechanisms discussion. 

(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 San Juan, Four Corners 

and Navajo. 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 15 and 21 years. 

(1) 

(2) 

(3) 

(3) 

(4) 

(5) 

(3) 

(6) 

(2) 

(4) 

(7) 

(7) 

(7) 

(8) 
Table of Contents 

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: 

 

UNS Gas and UNS Electric 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. 

 

Future Implications of Discontinuing Application of Regulatory Accounting 

We regularly assess whether we can continue to apply regulatory accounting to regulated operations, and concluded regulatory 

accounting is applicable. If we stopped applying regulatory accounting to our regulated operations the following would occur: 

 

 

 

 

K-107 

(7) See Cost Recovery Mechanisms discussion above. 

(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 and UNS Electric have also collected 

amounts for generation plant, which they have not yet expended. 

 Years Ended December 31, 

 2011 2010 2009 

 -Millions of DollarsTEP 

Operating Revenues 

Amortization of the Fixed CTC Revenue to be Refunded $ 36 $ 10 $ 13 

Operating Expenses 

Depreciation (related to Net Cost of Removal for Interim 

Retirements) (29 ) (30 ) (41 ) 

Deferral of PPFAC Costs 6 22 18 

Other — (8 ) (16 ) 

Non-Operating Income/Expenses 

Long-Term Debt (Amortization of Loss on Reacquired Debt Costs) 1 1 — 

AFUDC—Equity 4 4 4 

Income Taxes—Deferral (8 ) 1 — 

Offset by the Tax Effect of the Above Adjustments (4 ) — 9 

 

Net (Decrease)/Increase to Net Income $ 6 $ — $ (13 ) 

 

 

 

 

 

 

 Years Ended December 31, 

 2011 2010 2009 

 -Millions of DollarsUNS Gas 

Net (Decrease)/Increase to Net Income $ (5 ) $ (1 ) $ 6 

UNS Electric 

Net (Decrease)/Increase to Net Income 3 (7 ) 7 

 • 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 

statements; 

 • At December 31, 2011, based on the regulatory assets balances, net of regulatory liabilities: 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

 

While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped 

applying regulatory accounting to our regulated operations. 

NOTE 3. SEGMENT AND RELATED INFORMATION 

We have three reportable segments that are determined based on the way we organize our operations and evaluate performance: 

 

 

 

Results for the UniSource Energy and UES holding companies, Millennium and UED are included in Other below. 

In accordance with accounting rules related to the transfer of a business held under common control, we reflect UNS Electric’s 

purchase of BMGS as if it occurred on January 1, 2009. UNS Electric’s net income and reconciling adjustments in the table below 

increased by $3 million for the year ended December 31, 2011, and $5 million for each of the years ended December 31, 2010 and 

2009. The transaction had no impact on UniSource Energy’s consolidated financial statements. In addition, the segments disclosed 

in the 2010 and 2009 sections of the table below were revised to move Millennium into the “Other” segment as it is no longer a 

reportable segment. 

We disclose selected financial data for our reportable segments in the following tables: 

 

 

K-108 

 

• TEP would have recorded an extraordinary after-tax gain of $62 million and an after-tax loss in AOCI of $64 

million; 

 

• UNS Gas would have recorded an extraordinary after-tax gain of $18 million and an after-tax loss in AOCI of $2 

million; and 

 

• UNS Electric would have recorded an extraordinary after-tax loss of $6 million and an after-tax loss in AOCI of $3 

million. 

 (1) TEP, a regulated electric utility business, is our largest subsidiary; 

 (2) UNS Gas is a regulated gas distribution utility business; and 

 (3) UNS Electric is a regulated electric utility business. 

 Reportable Segments 

2011 TEP 

UNS 

Gas 

UNS 

Electric Other 

Reconciling 

Adjustments 

UniSource 

Energy 

 -Millions of DollarsIncome Statement 

Operating Revenues-External $ 1,141 $ 149 $ 219 $ — $ 1 $ 1,510 

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 (Loss) 85 10 18 — (3 ) 110 

 

Cash Flow Statement 

Capital Expenditures (352 ) (13 ) (96 ) (34 ) 121 (374 ) 

 

Balance Sheet 

Total Assets 3,275 319 370 1,172 (1,151 ) 3,985 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

 

 

K-109 

 Reportable Segments 

   

2010 TEP 

UNS 

Gas 

UNS 

Electric Other 

Reconciling 

Adjustments 

UniSource 

Energy 

 -Millions of DollarsIncome Statement 

Operating Revenue-External $ 1,096 $ 144 $ 213 $ — $ 1 $ 1,454 

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 (Benefit) 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 ) 

 

Balance Sheet 

Total Assets 3,076 310 356 1,152 (1,103 ) 3,791 

 

2009 

Income Statement 

Operating Revenues-External $ 1,065 $ 148 $ 183 $ — $ 1 $ 1,397 

Operating Revenues- Intersegment 34 5 4 28 (71 ) — 

Depreciation and Amortization 153 7 16 2 (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) 54 5 7 — (3 ) 63 

Net Income (Loss) 91 7 11 2 (5 ) 106 

 

Cash Flow Statement 

Capital Expenditures (240 ) (15 ) (29 ) (10 ) — (294 ) 

 
Table of Contents 

UNISOURCE 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 they are 

eliminated in consolidation: 

 

 

 

 

 

 

TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UniSource Energy, UNS 

Gas and, UNS Electric as well as to UniSource Energy’s non-utility businesses. Costs are directly assigned to the benefiting entity. 

Direct costs charged by TEP to affiliates were $10 million in 2011, 2010, and 2009. 

 

K-110 

 Reportable Segments 

 TEP 

UNS 

Gas 

UNS 

Electric Other 

 -Millions of DollarsIntersegment Revenue 

2011: 

Wholesale Sales—TEP to UNS Electric $ 2 $ — $ — $ — 

Wholesale Sales—UNS Electric to TEP — — 2 — 

Wholesale Sales—UED to UNS Electric — — — 5 

Wholesale Sales—UNS Gas to TEP — — — — 

Gas Revenue—UNS Gas to UNS Electric — 2 — — 

Other Revenue—TEP to Affiliates 10 — — — 

Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas — — — 18 

Other Revenue—TEP to UNS Electric 3 — — — 

 

Total Intersegment Revenue $ 15 $ 2 $ 2 $ 23 

 

2010: 

Wholesale Sales—TEP to UNS Electric $ 18 $ — $ — $ — 

Wholesale Sales—UNS Electric to TEP — — 2 — 

Wholesale Sales—UED to UNS Electric — — — 11 

Wholesale Sales—UNS Gas to TEP — 1 — — 

Gas Revenue—UNS Gas to UNS Electric — 5 — — 

Other Revenue—TEP to Affiliates 8 — — — 

Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas — — — 17 

Other Revenue—TEP to UNS Electric 3 — — — 

 

Total Intersegment Revenue $ 29 $ 6 $ 2 $ 28 

 

2009: 

Wholesale Sales—TEP to UNS Electric $ 23 $ — $ — $ — 

Wholesale Sales—UNS Electric to TEP — — 4 — 

Wholesale Sales—UED to UNS Electric — — — 12 

Gas Revenue—UNS Gas to UNS Electric — 5 — — 

Other Revenue—TEP to Affiliates 8 — — — 

Other Revenue—Millennium to TEP, UNS Electric, & UNS Gas — — — 16 

Other Revenue—TEP to UNS Electric 3 — — — 

 

Total Intersegment Revenue $ 34 $ 5 $ 4 $ 28 

 

(1) 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) Millennium provides a supplemental workforce and meter-reading services to TEP, UNS Gas and UNS Electric. Amounts are 

based on costs of services performed, and management believes that the charges for services are reasonable. Millennium 

charged TEP $17 million in 2011, $16 million in 2010, and $15 million in 2009 for these services. 

(3) TEP charged UNS Electric for control area services based on a FERC approved tariff. 

(4) TEP and UNS Electric sell power to each other at Dow Jones Four Corners Daily Index prices. 

(5) Starting in 2010, UNS Gas provides gas to TEP for generation of power at third-party market prices. 

(4) 

(4) 

(5) 

(1) 

(2) 

(3) 

(4) 

(4) 

(5) 

(1) 

(2) 

(3) 

(4) 

(4) 

(1) 

(2) 

(3) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

UniSource 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 2011, 

$3 million in 2010, and $2 million in 2009. 

Other 

Other significant reconciling adjustments include intercompany interest between UniSource Energy and UED, the elimination of 

investments in subsidiaries held by UniSource Energy and reclassifications of deferred tax assets and liabilities. 

NOTE 4. COMMITMENTS, CONTINGENCIES, AND PROPOSED ENVIRONMENTAL MATTERS 

TEP COMMITMENTS 

Firm Purchase Commitments 

At December 31, 2011, TEP had the following firm non-cancelable purchase commitments (minimum purchase obligations) and 

operating leases: 

 

Fuel, Purchased Power and Transmission Contracts 

TEP has long-term contracts for the purchase and delivery of coal 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. 

TEP has agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, 

replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In 

general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. 

These contracts expire in various years between 2012 and 2014. 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, 2011. 

Additionally, Purchased Power includes two 20-year Power Purchase Agreements (PPAs) with renewable energy generation 

facilities that achieved commercial operation in 2011. 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. 

Fuel, purchased power and transmission costs are recoverable from customers through the PPFAC. 

 

K-111 

 Purchase Commitments 

 2012 2013 2014 2015 2016 Thereafter Total 

 -Millions of DollarsFuel (including 

Transportation) $ 84 $ 59 $ 58 $ 44 $ 41 $ 75 $ 361 

Purchased Power 29 21 17 13 13 184 277 

Solar Equipment 12 12 — — — — 24 

Transmission 3 3 3 3 3 23 38 

Operating Leases 2 2 2 1 1 10 18 

 

Total Unrecognized 

Firm 

Commitments $ 130 $ 97 $ 80 $ 61 $ 58 $ 292 $ 718 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Solar Equipment 

TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. The ACC approved 6 MW, and we 

are seeking approval from the ACC for the remaining 3 MW in 2012. TEP spent $10 million in 2011 under this contract. TEP earns 

a return on company-owned solar projects. See Note 2. 

Operating Leases 

TEP’s aggregate operating lease expense is primarily for rail cars, office facilities and computer equipment, with varying terms, 

provisions, and expiration dates. This expense totaled $2 million in each of 2011, 2010, and 2009. 

UNS GAS and UNS ELECTRIC COMMITMENTS 

At December 31, 2011, UNS Gas had firm non-cancelable purchase commitments for fuel, including transportation, as described in 

the table below: 

 

UNS Gas purchases gas from various suppliers at market prices. However, UNS Gas’ risk of loss due to increased costs (as a 

result of changes in market prices of fuel) is mitigated through the use of the PGA, which provides for the pass-through of actual 

commodity costs to customers. UNS Gas’ forward gas purchase agreements expire through 2015. Certain of these contracts are at 

a fixed price per 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, 2011. UNS Gas has firm transportation agreements with capacity sufficient to meet its 

load requirements. These contracts expire in various years between 2012 and 2024. 

At December 31, 2011, UNS Electric had various firm non-cancelable purchase commitments as described in the table below: 

 

UNS Electric enters into agreements with various energy suppliers for purchased power at market prices to meet its energy 

requirements. In general, these contracts provide for capacity payments and energy payments based on actual power taken under 

the contracts. These contracts expire in various years through 2014. 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, 2011. Purchased power commitments also include one 20-year PPA with a renewable energy generation facility that 

achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility. 

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 2012 and 2016. 

However, the effects of both purchased power and transmission cost adjustments are mitigated through a purchased power rateadjustment mechanism. 

 

K-112 

 Purchase Commitments 

 2012 2013 2014 2015 2016 Thereafter Total 

 -Millions of DollarsTotal Unrecognized Firm Commitments – 

Fuel $ 23 $ 12 $ 10 $ 6 $ 6 $ 21 $ 78 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Purchase Commitments 

 2012 2013 2014 2015 2016 Thereafter Total 

 -Millions of DollarsPurchased Power $ 54 $ 40 $ 31 $ 3 $ 3 $ 43 $ 174 

Transmission 4 2 2 1 1 — 10 

 

Total Unrecognized Firm 

Commitments $ 58 $ 42 $ 33 $ 4 $ 4 $ 43 $ 184 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

UNS Gas and UNS Electric have operating lease expense, primarily for office facilities and computer equipment, with varying terms 

and expiration dates. The expense was $1 million in each of the years 2011, 2010, and 2009. UNS Gas’ and UNS Electric’s 

estimated future minimum payments under non-cancelable operating leases are less than $1 million per year for 2012 through 

2017. 

TEP CONTINGENCIES 

San Juan Mine Fire 

In September 2011, a fire at the underground mine that provides coal to San Juan caused mining operations to shut down. TEP 

owns approximately 20% of San Juan, which is operated by PNM. As we are unable to predict when operations will resume at the 

mine, we and the other owners of San Juan are considering alternatives for operating the facility. 

However, based on information we have received to date, we do not expect the mine fire to have a material effect on our financial 

condition, results of operations, or cash flows due to the current inventory of previously mined coal and the current low market price 

of wholesale power. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers 

through the PPFAC, subject to ACC approval. 

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 the 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. 

SJCC operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal 

government, the State of New Mexico and private parties. These gas producers allege that SJCC’s underground coal mine 

interferes with their operations, reducing the amount of natural gas they can recover. SJCC has compensated certain gas 

producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. 

These settlements, however, do not resolve all potential claims by gas producers in the area. TEP cannot estimate the impact 

of any future claims by these gas producers on the cost of coal at San Juan. 

TEP owns 50% of San Juan Units 1 and 2, which represents approximately 20% of the total generation capacity of the entire San 

Juan Generating Station, and is responsible for its share of any resulting liabilities. 

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 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. Among other things, 

the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the 

payment of civil penalties, including a beneficial mitigation project. 

 

K-113 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. 

TEP cannot predict the final outcome of the claims relating to San Juan and 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, estimates of the range 

of loss cannot be determined at this time. TEP accrued estimated losses of less than $1 million in 2011 in respect of these claims. 

Mine Closure Reclamation at Generating Stations Not Operated by TEP 

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest 

but does not operate. TEP is liable for a portion of final reclamation costs upon closure of these mines. TEP’s share of the 

reclamation costs for coal supply agreements expiring in 2016 through 2019 is approximately $26 million. TEP recognizes this cost 

over the remaining terms of these coal supply agreements and had recorded liabilities of $13 million at December 31, 2011, and 

$11 million at December 31, 2010. 

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates 

when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these 

assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply 

agreement terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year 

because recognition will occur over the remaining terms of its coal supply agreements. 

TEP’s PPFAC allows TEP to pass through most fuel costs (including final reclamation costs) to customers. Therefore, TEP 

classifies these costs as a regulatory asset. TEP will increase the regulatory asset and the reclamation liability over the remaining 

life of the coal supply agreements on an accrual basis and recover the regulatory asset through the PPFAC as final mine 

reclamation costs are paid to the coal suppliers. 

Tucson to Nogales Transmission Line 

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile 

transmission line from Tucson to Nogales, Arizona. 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 authorized construction 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. If a decision is made to pursue an alternative route, approvals will be needed 

from the ACC, the Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and 

Water Commission. As of December 31, 2011, and December 31, 2010, 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 consequence of the ACC’s 

requirement for a second transmission line serving the Nogales, Arizona area. 

RESOLUTION OF CONTINGENCIES 

Settlement of El Paso Electric Dispute 

In November 2011, a settlement agreement between TEP and El Paso became effective after receiving FERC approval in August 

2011. The settlement resolved a dispute over transmission service from Luna to TEP’s system, totaling $11 million, under the 1982 

Power Exchange and Transmission Agreement between the parties (Exchange Agreement). 

The settlement reduced TEP’s rights for transmission under the Exchange Agreement from 200 MW to 170 MW and required TEP 

to pay El Paso a lump-sum of $5 million, equivalent to the total amount that TEP would have paid El Paso for 30 MW of 

transmission from February 1, 2006, through the settlement date, including interest. 

 

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Under the PPFAC mechanism, TEP is allowed to recover $2 million of this additional transmission expense from its customers. In 

accordance with the settlement agreement, TEP has entered into two new firm transmission service agreements under El Paso’s 

Open Access Transmission Tariff for a total of 40 MW. The settlement agreement also required El Paso to withdraw its appeal 

before the United States Court of Appeals District of Columbia Circuit and required TEP to withdraw its related complaint before the 

Arizona District of the United States District Court. 

TEP recognized a pre-tax gain of approximately $7 million, including interest, in the third quarter of 2011. To reflect the gain, TEP 

recorded a $7.1 million net reduction to Transmission Expense, $0.9 million of Interest Income, and $0.6 million of Interest Expense 

on the income statements. TEP recorded the payment of $5 million in Purchased Power in the cash flow statements. 

Take-Or-Pay Accrual for Coal Transportation Agreement 

In December 2010, TEP recorded a $4 million liability and regulatory asset for take-or-pay obligations under a coal transportation 

agreement for Sundt Unit 4, effective through December 2015. In December 2011, TEP’s take-or-pay obligations were terminated. 

As a result, TEP reversed its $4 million liability and regulatory asset. 

Claims Related to Navajo Generating Station 

In June 1999, the Navajo Nation filed suit in the U.S. District Court for the District of Columbia (D.C. Lawsuit) against parties 

including SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to 

Navajo Generating Station (Navajo); Southern California Edison Company (SCE); and other defendants. 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 alleged, 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 initially 

sought $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 April 2010, the Navajo Nation filed a Second Amended 

Complaint which dropped the treble damages claim. In August 2011, the Navajo Nation, Peabody, SCE and SRP executed a 

written settlement agreement in return for the Navajo Nation’s dismissal of all claims in the D.C. Lawsuit. SRP asked that the 

Navajo participants, including TEP, contribute toward the settlement based on their respective ownership interests in the Navajo 

plant, which for TEP is 7.5%. TEP paid SRP the requested contribution which did not have a material impact on TEP’s financial 

statements. 

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 does not believe the lawsuit will be re-filed 

based upon the final outcome of the D.C. Lawsuit. 

PROPOSED ENVIRONMENTAL MATTERS 

ENVIRONMENTAL REGULATION 

TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO ), 

nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP capitalized $8 million in 2011, $18 million in 2010 and 

$24 million in 2009 in construction costs to comply with environmental requirements, including TEP’s share of new pollution control 

equipment installed at San Juan Generating Station (San Juan) described below. TEP expects to capitalize environmental 

compliance costs of $7 million in 2012 and $25 million in 2013. In addition, TEP recorded operating expenses of $12 million in 

2011, $14 million in 2010 and $13 million in 2009 related to environmental compliance. TEP expects environmental expenses to be 

$14 million in 2012. 

TEP may incur additional costs to comply with future changes in federal and state environmental laws, and regulations and permit 

requirements at its electric generating facilities. Compliance with these changes may reduce operating efficiency. 

 

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UNISOURCE 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. The EPA is required to develop rules establishing standards for the control of emissions of mercury 

and other hazardous air pollutants from electric generating units. The EPA issued the final rule in December 2011. 

Navajo 

Based on the EPA’s final standards, mercury and particulate emission control equipment may be required at Navajo by 2015. 

TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and approximately $43 million 

if the installation of baghouses to control particulates is necessary. 

Springerville 

Based on the EPA’s final standards, mercury emission control equipment may be required at Springerville by 2015. The estimated 

capital cost of this equipment for Springerville Units 1 and 2 is approximately $5 million. The annual operating cost associated with 

the mercury emission control equipment is expected to be approximately $3 million. 

San Juan 

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s final federal standards. 

Sundt 

TEP does not anticipate the final EPA rule will have a material capital impact on Sundt Unit 4. 

Four Corners 

Based on the EPA’s final standards, mercury emission control equipment may be required at Four Corners by 2015. The estimated 

capital cost of this equipment is less than $1 million. The annual operating cost associated with the mercury emission control 

equipment is expected to be less than $1 million. 

Regional Haze Rules 

The EPA's regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial 

facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies 

for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. 

Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory 

jurisdictions. The EPA oversees regional haze planning for these plants. 

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other 

environmental regulations and other business considerations could jeopardize the economic viability of the San Juan, Four Corners 

and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. TEP 

cannot predict the ultimate outcome of these matters. 

San Juan 

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO and 

sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) 

technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions. Based on two 

cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $180 

million and $200 million. 

 

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

In September 2011, PNM filed a petition to review the Federal Implementation Plan with the 10th Circuit Court of Appeals 

challenging various aspects of that plan. In addition, PNM filed a request with the EPA to stay the five-year installation timeframe 

for environmental upgrades ordered by the Federal Implementation Plan until the 10th Circuit considers and rules on the petition to 

review. 

In October 2011, PNM filed a Petition for Reconsideration of the Federal Implementation Plan. PNM also filed a Request to Stay 

the effective date of the final BART Federal Implementation Plan under the Clean Air Act with the EPA. In November 2011, PNM 

filed with the 10th Circuit a Motion to Stay the Federal Implementation Plan. WildEarth Guardians, Dine Citizens against Ruining 

our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club 

were granted leave to intervene in PNM’s petition to review in the 10th Circuit. Neither the Petition in the 10th Circuit, nor the 

Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a 

separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted 

leave to intervene in that appeal. 

In October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for 

Review of the EPA’s final Federal Implementation Plan determination in the 10th Circuit and a Petition for Reconsideration of the 

rule with the EPA. In November 2011, the New Mexico Governor and Environment Department filed a motion with the 10th Circuit 

to stay the rule. These appeals and motions are all currently pending. 

Four Corners 

In February 2011, the EPA supplemented the proposed FIP for the BART determination at Four Corners that would require the 

installation of SCR on Units 4 and 5 by 2018. TEP’s estimated share of the capital costs to install SCR is approximately $35 million. 

Navajo 

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report by the 

National Renewable Energy Laboratory (NREL) in partnership with the Department of the Interior and the Department of Energy. 

The report addresses potential energy, environmental and economic issues related to compliance with the regional haze rule. The 

report was submitted to the EPA in January 2012. If the EPA determines that SCR is required at Navajo, the capital cost impact to 

TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, 

necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital expenditure for the 

required baghouses would be approximately $43 million. The cost of required pollution controls 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. 

 

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UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES 

UTILITY PLANT 

The following table shows Utility Plant in Service by major class. 

 

 

TEP Utility Plant under Capital Leases 

All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term. See 

Note 6. In April 2010, TEP terminated the capital lease of Sundt Unit 4 and purchased the related leased assets. At December 31, 

2011, the utility plant under capital leases includes Springerville Common Facilities, Springerville Unit 1, and Springerville Coal 

Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases: 

 

 

K-118 

 UniSource Energy TEP 

 December 31, December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsPlant in Service: 

Electric Generation Plant $ 1,879 $ 1,787 $ 1,795 $ 1,709 

Electric Transmission Plant 810 741 766 705 

Electric Distribution Plant 1,453 1,368 1,234 1,168 

Gas Distribution Plant 233 224 — — 

Gas Transmission Plant 18 18 — — 

General Plant 331 215 302 187 

Intangible Plant—Software Costs 44 34 43 33 

Intangible Plant—Other 83 61 78 57 

Electric Plant Held for Future Use 5 5 4 4 

 

Total Plant in Service 4,856 4,453 4,222 3,863 

 

 

 

 

 

 

 

 

Utility Plant under Capital Leases $ 583 $ 583 $ 583 $ 583 

 

 At December 31, 2010, UniSource Energy’s total plant included $65 million of non-regulated plant in service related to BMGS, 

with $4 million of accumulated depreciation. See Note 2 for information regarding UNS Electric’s 2011 purchase of BMGS 

from UED. 

 Years Ended December 31, 

 2011 2010 2009 

 -Millions of DollarsLease Expense: 

Interest Expense – Included in: 

Capital Leases $ 40 $ 47 $ 49 

Operating Expenses – Fuel 4 4 4 

Other Expense 1 2 1 

Amortization of Capital Lease Assets – Included in: 

Operating Expenses – Fuel 3 3 2 

Operating Expenses – Depreciation and Amortization 14 14 26 

 

Total Lease Expense $ 62 $ 70 $ 82 

 

 

 

 

 

 

( 1 ) 

(1) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The depreciable lives as of December 31, 2011 were as follows: 

 

See Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 6. 

JOINTLY-OWNED FACILITIES 

At December 31, 2011, TEP’s interests in jointly-owned generating stations and transmission systems were as follows: 

 

TEP has financed or provided funds for the above facilities and TEP’s share of its operating expenses is reflected in the income 

statements based on the nature of the expense. 

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 UniSource Energy’s and 

TEP’s long-term debt in the statements of capitalization. 

UNISOURCE ENERGY DEBT- Convertible Senior Notes 

In 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due in 2035. 

UniSource Energy has the option to redeem the Convertible Senior Notes, in whole or in part, for cash at par plus accrued interest. 

Investors may require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash at par plus 

accrued interest on March 1 of 2015, 2020, 2025 and 2030, and upon the occurrence of certain fundamental changes, such as a 

change in control. Each $1,000 of Convertible Senior Notes can be converted into 28.814 shares of UniSource Energy Common 

Stock at any time, which is equivalent to a conversion price of approximately $34.71 per share of common stock. The conversion 

rate is subject to adjustments including an adjustment to reduce the conversion price upon the payment of quarterly dividends in 

excess of $0.19 per share. 

In December 2011, UniSource Energy announced that it would redeem $35 million of the $150 million outstanding Convertible 

Senior Notes on January 12, 2012, at a redemption price of 100% of the principal amount plus accrued interest. In January 2012, 

holders of approximately $33 million of the Convertible Senior Notes converted their interests into approximately 964,000 shares of 

UniSource Energy Common Stock. The remaining $2 million of 

 

K-119 

Major Class of Utility Plant in Service TEP 

UNS Gas and 

UNS Electric 

Electric Generation Plant 6-59 years 38-42 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 3-18 years 5-32 years 

 

Ownership 

Percentage 

Plant 

in 

Service 

Construction 

Work in 

Progress 

Accumulated 

Depreciation 

Net 

Book 

Value 

 -Millions of DollarsSan Juan Units 1 and 2 50.0% $ 430 $ 8 $ 219 $ 219 

Navajo Station Units 1, 2 and 3 7.5 146 1 99 48 

Four Corners Units 4 and 5 7.0 96 2 71 27 

Transmission Facilities 7.5 to 95.0 289 9 179 119 

Luna Energy Facility 33.3 52 — 1 51 

 

Total $ 1,013 $ 20 $ 569 $ 464 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Convertible Senior Notes were redeemed for cash. After the partial redemption, UniSource Energy had $115 million of Convertible 

Senior Notes outstanding. 

TEP DEBT 

Variable Rate Tax-Exempt Bonds (IDBs) 

At December 31, 2011, TEP had $215 million in tax-exempt variable rate debt outstanding. At December 31, 2010, TEP had $365 

million outstanding. Each series of bonds is supported by a letter of credit issued under the TEP Credit Agreement or separate TEP 

Letter of Credit and Reimbursement Agreements. The letters of credit are secured by mortgage bonds issued under TEP’s 1992 

Mortgage. 

In November 2011, TEP repurchased $150 million of variable rate IDBs. TEP did not cancel the repurchased bonds, which 

remained outstanding under their respective indentures but were not reflected as debt on the balance sheet. See 2011 TEP 

Unsecured Notes below. 

In December 2010, TEP issued $37 million of Coconino County, Arizona, tax-exempt pollution control bonds (2010 Coconino 

Bonds). The 2010 Coconino Bonds are supported by a letter of credit (LOC). The LOC is secured by $37 million of 1992 Mortgage 

Bonds and expires December 2014. The bonds accrue interest at a variable weekly rate and are due October 2032. These bonds 

are multi-modal bonds that allow TEP to change the interest feature of the bonds. They are callable at any time at par plus accrued 

interest and are subject to mandatory redemption under certain circumstances if the LOC is not extended. The average interest rate 

on TEP’s 2010 Coconino Bonds was 0.23% in 2011 and 0.38% in 2010. TEP used the proceeds to redeem a corresponding 

principal amount of fixed rate Coconino pollution control bonds. 

TEP capitalized less than $1 million in costs related to the issuance of these bonds and will amortize the costs to interest expense 

through October 2032, the term of the bonds. 

The following table shows interest rates on TEP’s variable rate IDBs which are reset weekly by its remarketing agents: 

 

In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate IDBs to a fixed 

rate of 2.4% from September 2009 to September 2014.

Unsecured Fixed Rate IDBs 

At December 31, 2011, TEP had $616 million in unsecured fixed rate IDBs. At December 31, 2010, TEP had $638 million 

outstanding. 

In November 2011, TEP redeemed $22 million in unsecured fixed rate IDBs. See 2011 TEP Unsecured Notes below. 

In October 2010, TEP issued $100 million of Pima County, Arizona tax-exempt IDBs. The IDBs are unsecured, bear interest at a 

rate of 5.25%, mature in October 2040, and are callable at par on or after October 1, 2020. Net of an underwriting discount, $99 

million of proceeds were deposited in a construction fund with the bond trustee. The proceeds were applied to the construction of 

certain of TEP’s transmission and distribution facilities used to provide electric service in Pima County. TEP drew down $88 million 

of the proceeds from the construction fund in 2010 and $11 million in 2011. 

 

K-120 

 Years Ended December 31, 

 2011 2010 2009 

Interest Rates on IDBs: 

Average Interest Rate 0.18 % 0.26 % 0.41 % 

Range of Average Weekly Rates 

 

 

 

0.05 

to 0.34 

% 

% 

 

 

0.17 

to 0.39 

% 

% 

 

 

0.25 

to 0.79 

% 

% 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

TEP capitalized approximately $1 million in costs related to the issuance of these bonds and will amortize the costs to interest 

expense through October 2040, the term of the bonds. 

2011 TEP Unsecured Notes 

In November 2011, TEP issued $250 million of 5.15% Notes due November 2021 at a discount of $0.8 million. The debt is callable 

anytime before August 15, 2021, with a make-whole premium plus accrued interest. Anytime after August 15, 2021, the debt is 

callable at par plus accrued interest. TEP used the net proceeds from the sale to 1) repurchase $150 million of variable rate IDBs, 

2) redeem $22 million of 6.1% fixed rate IDBs and 3) repay $78 million of outstanding revolving credit facility balances, with any 

remaining proceeds to be applied to general corporate purposes. The variable rate IDBs were supported by letters of credit (LOCs) 

issued under TEP’s Credit Facility. As a result of the repurchase of the variable rate IDBs, TEP cancelled $155 million of LOCs and 

reduced its mortgage bonds supporting the LOCs by the same amount. 

TEP capitalized $2 million in costs related to the issuance of the notes and will amortize the costs to interest expense through 

November 2021, the term of the notes. 

1992 Mortgage 

TEP's 1992 Mortgage creates liens on and security interests in most of TEP's utility plant assets, with the exception of Springerville 

Unit 2. San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2. Utility Plant under Capital 

Leases is not subject to such liens or available to TEP creditors, other than the lessors. The net book value of TEP's utility plant 

subject to the lien of the indenture was approximately $2 billion at December 31, 2011 and December 31, 2010. 

TEP CAPITAL LEASE OBLIGATIONS 

Springerville Leases 

The terms of TEP’s capital leases are as follows: 

 

 

 

TEP agreed with Tri-State, the owner of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville 

Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP 

will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these 

facilities; or 2) continue making payments to TEP for the use of these facilities. 

In 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 January 2012, through scheduled lease payments, TEP reduced its capital lease obligations by $74 million. 

 

K-121 

 

• The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for 

the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the 

leases TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of common facilities are: 

$38 million in 2017 and $68 million in 2021. 

 

• The Springerville Coal Handling Facilities Leases have an initial term to April 2015 but have 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 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. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Investments in Springerville Lease Debt and Equity 

TEP’s investments in Springerville Unit 1 lease debt totaled $29 million at December 31, 2011 and $67 million at December 31, 

2010. The investments in lease debt mature in 2013. TEP also held an undivided equity ownership interest in the Springerville Unit 

1 Leases totaling $37 million at December 31, 2011 and December 31, 2010. 

Interest Rate Swaps—Springerville Common Facilities Lease Debt 

TEP’s interest rate swaps hedge the floating interest rate risk associated with the Springerville Common Facilities Lease Debt. 

Interest on the lease debt is payable at six-month LIBOR plus a spread. The applicable spread was 1.625% at each of 

December 31, 2011 and December 31, 2010. The swaps have the effect of fixing the interest rates on the amortizing principal 

balances as follows: 

 

TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 16. 

UNS ELECTRIC SENIOR UNSECURED NOTES 

UNS Electric has $100 million of senior unsecured notes; $50 million at 6.5%, due 2015 and $50 million at 7.1%, due 2023. The 

UNS Electric long-term notes are guaranteed by UES. The notes may be prepaid with a make-whole call premium reflecting a 

discount rate equal to an equivalent maturity U.S. Treasury security yield plus 50 basis points. 

UNS Electric’s long-term notes contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, 

liens to secure indebtedness, restricted payments and incurrence of indebtedness. 

UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP 

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. UNS Electric used the 

$30 million in proceeds to repay borrowings under its revolving credit facility. The interest rate currently in effect is three-month 

LIBOR plus 1.25%. 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 10, 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by 

UES. 

The term loan credit agreement contains certain restrictive covenants for UNS Electric and UES. The covenants include restrictions 

on transactions with affiliates, restricted payments, additional indebtedness, liens and mergers. UNS Electric must meet an interest 

coverage ratio to issue additional debt. However, UNS Electric may, without meeting these tests, refinance indebtedness and incur 

short-term debt in an amount not to exceed $5 million. The credit agreement also requires UNS Electric to maintain a maximum 

leverage ratio, and allows UNS Electric to pay dividends so long as it maintains compliance with the credit agreement. 

UNS GAS SENIOR UNSECURED NOTES 

In August 2011, UNS Gas issued $50 million of senior guaranteed notes at 5.39%, due August 2026. UNS Gas used the proceeds 

to pay in full the $50 million of UNS Gas 6.23% notes that matured in August 2011. UNS Gas has another $50 million of notes at 

6.23%, due August 2015. The notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an 

equivalent maturity U.S. Treasury security yield plus 50 basis points. UES guarantees the notes. 

 

K-122 

Outstanding at December 31, 2011 

Fixed 

Ratio 

LIBOR 

Spread 

$ 34 million 5.77 % 1.625 % 

$ 22 million 3.18 % 1.625 % 

$ 7 million 3.32 % 1.625 % 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

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. 

UNISOURCE CREDIT AGREEMENT 

In November 2011, UniSource Energy amended its existing credit agreement to extend the expiration date from November 2014 to 

November 2016. 

In November 2010, UniSource Energy amended and restated its existing credit agreement. As amended, the agreement consists of 

a $125 million revolving credit facility and revolving letter of credit facility. UniSource Energy's obligations under the agreement are 

secured by a pledge of the capital stock of Millennium, UES and UED. 

UniSource Energy capitalized less than $0.5 million related to the 2011 credit agreement amendment and $1 million related to the 

2010 credit agreement amendment and restatement and will amortize these costs through November 2016. 

Unisource Energy had $57 million outstanding borrowings at December 31, 2011 and $27 million outstanding borrowings at 

December 31, 2010, under its revolving credit facility. The weighted average interest rate on the revolver was 2.04% at December 

31, 2011, and 3.26% at December 31, 2010. We have included the revolver borrowings in Long-Term Debt as UniSource Energy 

has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 21, 2012, outstanding 

borrowings under the UniSource Credit Agreement were $52 million. 

Interest rates and fees under the UniSource Credit Agreement are based on a pricing grid tied to UniSource Energy’s credit ratings. 

The interest rate currently in effect on borrowings is LIBOR plus 1.75% for Eurodollar loans or Alternate Base Rate plus 0.75% for 

Alternate Base Rate loans. 

The UniSource Credit Agreement contains a number of covenants which restrict UniSource Energy and its subsidiaries, including 

restrictions on additional indebtedness, liens, mergers and sales of assets. The UniSource Credit Agreement also requires 

UniSource Energy to meet a minimum cash flow to interest coverage ratio determined on a UniSource Energy standalone basis 

and not to exceed a maximum leverage ratio determined on a consolidated basis. Under the UniSource Credit Agreement, 

UniSource Energy may pay dividends so long as it maintains compliance with the agreement. 

TEP CREDIT AGREEMENT 

In December 2011, TEP reduced its letter of credit facility from $341 million to $186 million, following the repurchase of $150 million 

of variable rate IDBs and the cancellation of $155 million of LOCs supporting those bonds. 

In November 2011, TEP amended its existing credit agreement to extend the expiration date from November 2014 to November 

2016. 

In November 2010, TEP amended and restated its existing credit agreement, consisting of a $200 million revolving credit and 

revolving letter of credit facility and a $341 million letter of credit facility to support tax-exempt bonds. 

The TEP credit facility is secured by $386 million of mortgage bonds issued under the 1992 Mortgage, which creates a lien on and 

security interest in most of TEP’s utility plant assets. 

TEP capitalized $1 million related to the 2011 credit agreement amendment and $4 million related to the 2010 credit agreement 

amendment and restatement and will amortize these costs through November 2016. 

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate 

currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base 

Rate loans. The margin rate currently in effect on the $186 million letter of credit facility is 1.125%. 

 

K-123 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The TEP Credit Agreement contains a number of covenants which restrict TEP and its subsidiaries, including restrictions on liens, 

mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. Under the TEP 

Credit Agreement, TEP may pay dividends to UniSource Energy so long as it maintains compliance with the agreement. 

As of December 31, 2011, TEP had $10 million in borrowings and $1 million outstanding in letters of credit under its revolving credit 

facility. The weighted average interest rate on the revolver was 3.38%, at December 31, 2011. As of December 31, 2010, TEP only 

had $1 million outstanding in letters of credit under its revolving credit facility. The revolving loan balance was included in Current 

Liabilities in the UniSource Energy and TEP balance sheets. The outstanding letters of credit are off-balance sheet obligations of 

TEP. As of February 21, 2012, TEP had $85 million in borrowings and $1 million outstanding in letters of credit under its revolving 

credit facility. 

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 IDBs that were issued on behalf of TEP in December 2010 (See 

Variable Rate Tax-Exempt Bonds above). 

The 2010 TEP Reimbursement Agreement is secured by $37 million of mortgage bonds issued under TEP’s 1992 Mortgage. Fees 

are payable on the aggregate outstanding amount of the letter of credit at a rate of 1.50% per annum. 

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement 

described above. 

UNS GAS/UNS ELECTRIC CREDIT AGREEMENT 

In November 2011, UNS Gas and UNS Electric amended their existing unsecured credit agreement to extend the expiration date 

from November 2014 to November 2016. 

In November 2010, UNS Gas and UNS Electric amended and restated their existing unsecured credit agreement. As amended, the 

UNS Gas/UNS Electric Credit Agreement consists of a $100 million revolving credit and revolving letter of credit facility. The 

maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. 

UNS Gas and UNS Electric each are liable for only their own individual borrowings under the UNS Gas/UNS Electric Credit 

Agreement. UES guarantees the obligations of both UNS Gas and UNS Electric. The UNS Gas/UNS Electric Credit Agreement 

may be used to issue letters of credit, as well as for revolver borrowings. UNS Gas and UNS Electric issue letters of credit, which 

are off-balance sheet obligations, to support power and gas purchases and hedges. 

UNS Gas and UNS Electric capitalized less than $0.5 million of costs related to the 2011 credit agreement amendment and $1 

million related to the 2010 credit agreement amendment and restatement, and will amortize these costs through November 2016. 

Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to their credit ratings. 

The interest rate currently in effect on borrowings is LIBOR plus 1.5% for Eurodollar loans or Alternate Base Rate plus 0.5% for 

Alternate Base Rate loans. 

The UNS Electric/UNS Gas Credit Agreement contains a number of covenants which impose restrictions on UNS Gas, UNS 

Electric and UES, including restrictions on additional indebtedness, liens and mergers. The UNS Electric/UNS Gas Credit 

Agreement also stipulates a maximum leverage ratio. Under the terms of the UNS Electric/UNS Gas Credit Agreement, UNS Gas 

and UNS Electric may pay dividends so long as they maintain compliance with the agreement. 

 

K-124 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

UNS Electric had $6 million and $13 million in outstanding letters of credit under the UNS Gas/UNS Electric Credit Agreement as of 

December 31, 2011, and December 31, 2010, respectively, which are not shown on the balance sheet. 

UED SECURED TERM LOAN 

In July 2011, UED received $63 million from UNS Electric from the sale of BMGS. UED used a portion of those funds to fully repay 

the $27 million outstanding under its secured term loan. 

Other 

As of December 31, 2011, UniSource 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. 

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: 

 

 

 

 

NOTE 7. STOCKHOLDERS’ EQUITY 

DIVIDEND LIMITATIONS 

UniSource Energy 

Our ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, 

UES, Millennium and UED, as well as compliance with various debt covenant requirements. UniSource Energy and each of its 

subsidiaries were in compliance with debt covenants at December 31, 2011; therefore, TEP and the other subsidiaries were not 

restricted from paying dividends. 

 

K-125 

 

TEP 

Variable 

Rate IDBs 

Supported 

by Letters 

of Credit 

TEP 

Scheduled 

Debt 

Retirements 

TEP 

Capital 

Lease 

Obligations 

TEP 

Total 

UNS 

Gas 

UNS 

Electric 

UniSource 

Energy 

Parent 

Company Total 

 - Millions of Dollars - 

2012 $ — $ — $ 118 $ 118 $ — $ — $ — $ 118 

2013 — — 122 122 — — — 122 

2014 37 — 195 232 — — — 232 

2015 — — 23 23 50 80 — 153 

2016 178 — 18 196 — — 57 253 

 

Total 2012 – 2016 215 — 476 691 50 80 57 878 

Thereafter — 866 61 927 50 50 150 1,177 

Less: Imputed Interest — — (107 ) (107 ) — — — (107 ) 

 

Total $ 215 $ 866 $ 430 $ 1,511 $ 100 $ 130 $ 207 $ 1,948 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 TEP’s Variable Rate IDBs are backed by $186 million in LOCs issued pursuant to TEP’s Credit Agreement which expires in 

November 2016 and TEP’s $37 million Reimbursement Agreement which expires December 2014. Although the Variable Rate 

IDBs 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. 

 The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount. 

In January 2012, UniSource Energy redeemed $35 million of its convertible senior notes. Pursuant to the redemption, 

substantially all of the notes were converted into approximately 1 million shares of UniSource Energy Common Stock. 

(1) (2) (3) 

(1) 

(2) 

(3) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

In February 2012, UniSource Energy declared a first quarter dividend to shareholders of $0.43 per share of UniSource Energy 

Common Stock. The dividend, totaling approximately $16 million, will be paid on March 22, 2012, to common shareholders of 

record as of March 12, 2012. 

In January 2012, holders of approximately $33 million of the Convertible Senior Notes converted their interests into approximately 

964,000 shares of UniSource Energy Common Stock increasing common stock equity by $33 million. 

TEP 

UniSource Energy is the holder of TEP’s common stock. TEP pays dividends from current year earnings; therefore the dividend 

restriction in the Federal Power Act does not limit TEP’s payment of dividends from net income. TEP paid dividends to UniSource 

Energy of $60 million in both 2010 and 2009. TEP did not pay dividends to UniSource Energy in 2011. 

UniSource Energy contributed capital to TEP of $30 million in 2011, $15 million in 2010, and $30 million in 2009. 

NOTE 8. INCOME TAXES 

A reconciliation of the federal statutory income tax rate to each company’s effective income tax rate follows: 

 

In 2010, UniSource Energy recorded a $3 million out-of-period income tax expense. The out-of-period expense related to the writeoff 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. 

 

K-126 

 UniSource Energy TEP 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsFederal Income Tax Expense at Statutory Rate $ 62 $ 66 $ 59 $ 48 $ 58 $ 51 

State Income Tax Expense, Net of Federal Benefit 8 9 7 6 8 6 

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 ) (1 ) — (3 ) (1 ) 

Federal/State Tax Credits (3 ) (2 ) (1 ) (2 ) (2 ) (1 ) 

Other 1 (3 ) — 1 — — 

 

Total Federal and State Income Tax Expense $ 67 $ 77 $ 63 $ 52 $ 60 $ 54 

 

 

 

 

 

 

 

 

 

 

 

 

Effective Tax Rate 38 % 41 % 37 % 38 % 36 % 37 % 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Income tax expense included in the income statements consists of the following: 

 

The significant components of deferred income tax assets and liabilities consist of the following: 

 

 

K-127 

 UniSource Energy TEP 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsCurrent Tax Expense (Benefit) 

Federal $ (7 ) $ 34 $ 6 $ (5 ) $ 28 $ 7 

State (2 ) 7 — (2 ) 7 1 

 

Total (9 ) 41 6 (7 ) 35 8 

 

Deferred Tax Expense (Benefit) 

Federal 64 32 47 50 24 38 

Federal Investment Tax Credits (1 ) (1 ) — (1 ) (1 ) — 

State 13 5 10 10 2 8 

 

Total 76 36 57 59 25 46 

 

Total Federal and State Income Tax 

Expense $ 67 $ 77 $ 63 $ 52 $ 60 $ 54 

 

 

 

 

 

 

 

 

 

 

 

 

 

UniSource Energy 

December 31, 

TEP 

December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsGross Deferred Income Tax Assets 

Capital Lease Obligations $ 169 $ 192 $ 169 $ 192 

Net Operating Loss Carryforwards 81 — 76 — 

Customer Advances and Contributions in Aid of Construction 30 43 17 27 

Alternative Minimum Tax Credit 43 34 25 16 

Accrued Postretirement Benefits 23 24 23 24 

Renewable Energy Credit Up-Front Incentive Payments 22 14 18 11 

Emission Allowance Inventory 10 11 10 11 

Unregulated Investment Losses 9 9 — — 

Other 34 29 29 26 

 

Gross Deferred Income Tax Assets 421 356 367 307 

 

Deferred Tax Assets Valuation Allowance (7 ) (8 ) — — 

 

Gross Deferred Income Tax Liabilities 

Plant—Net (581 ) (465 ) (513 ) (413 ) 

Capital Lease Assets—Net (41 ) (48 ) (41 ) (48 ) 

Regulatory Asset—Income Taxes Recoverable Through Future 

Revenues (4 ) (7 ) (3 ) (7 ) 

Pensions (17 ) (12 ) (18 ) (13 ) 

PPFAC (19 ) (1 ) (16 ) — 

Other (29 ) (30 ) (17 ) (22 ) 

 

Gross Deferred Income Tax Liabilities (691 ) (563 ) (608 ) (503 ) 

 

Net Deferred Income Tax Liabilities $ (277 ) $ (215 ) $ (241 ) $ (196 ) 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The balance sheets display the net deferred income tax liability as follows: 

 

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. The $9 million unregulated investment loss deferred tax asset 

includes $7 million of capital loss at December 31, 2011 and $8 million at December 31, 2010. 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, UniSource Energy recorded a $7 million valuation allowance against the 

deferred tax asset as of December 31, 2011 and $8 million at December 31, 2010. Management believes that based on its 

historical pattern of taxable income, UniSource Energy will produce sufficient income in the future to realize all other deferred 

income tax assets. 

State Tax Rate Change 

We record deferred tax assets and liabilities using the income tax rates expected to be in effect when the deferred tax assets and 

liabilities are realized or settled. 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 UniSource 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 UniSource Energy’s and TEP’s effective tax rate for 2011. 

Uncertain Tax Positions 

In accordance with accounting rules related to uncertain tax positions, we are required to determine whether it is “more likely than 

not” that we will sustain an income tax position under examination. Each income tax position is measured to determine the amount 

of benefit to recognize in the financial statements. The following table shows the changes in unrecognized tax benefits of 

UniSource Energy and TEP: 

 

Unrecognized tax benefits of $1 million, if recognized, would reduce the effective tax rate at December 31, 2011, and December 31, 

2010, for both UniSource Energy and TEP. Included in reductions based on settlements with authorities is $13 million for 

UniSource Energy and $10 million for TEP related to a change in accounting method filed with the Internal Revenue Service (IRS) 

in 2011. The remaining balance in unrecognized tax benefits could change in the next twelve months as a result of ongoing IRS 

audits, but we are unable to determine the amount of the change. 

 

K-128 

 UniSource Energy TEP 

 December 31, December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsDeferred Income Taxes – Current Assets $ 23 $ 31 $ 22 $ 32 

Deferred Income Taxes – Noncurrent Liabilities (300 ) (246 ) (263 ) (228 ) 

 

Net Deferred Income Tax Liability $ (277 ) $ (215 ) $ (241 ) $ (196 ) 

 

 

 

 

 

 

 

 

 UniSource Energy TEP 

 December 31, December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsUnrecognized Tax Benefits, beginning of year $ 41 $ 19 $ 35 $ 19 

Additions based on tax positions taken in the current year 9 11 8 8 

Reductions based on settlements with tax authorities (22 ) — (19 ) — 

Additions based on tax positions taken in the prior year 1 16 — 13 

Reductions based on tax positions taken in the prior year — (4 ) — (4 ) 

Reductions based on expiration of the statute of limitations — (1 ) — (1 ) 

 

Unrecognized Tax Benefits, end of year $ 29 $ 41 $ 24 $ 35 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

UniSource Energy and TEP recognize interest accrued related to unrecognized tax benefits in Other Interest Expense in the 

income statements. UniSource Energy and TEP recorded a reduction to interest expense of $1 million in 2011 and 2009. We did 

not recognize a reduction to interest expense in 2010. The balance of interest payable for UniSource Energy and TEP was $1 

million at December 31, 2011 and $2 million at December 31, 2010. We have no penalties accrued in the years presented. 

UniSource Energy and TEP have been audited by the IRS through tax year 2006 and are currently under audit by the IRS for 2008 

through 2010. 2007 was not selected for audit. We are unable to determine when the audits will be completed. UniSource Energy 

and TEP are not currently under audit by any state tax agencies. 

NOTE 9. EMPLOYEE BENEFIT PLANS 

PENSION BENEFIT PLANS 

We 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. We 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 Retail Rates, 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 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). 

Pension Contributions 

The Pension Protection Act of 2006 (The Pension Act) established minimum funding targets for pension plans. A plan’s funding 

target is the present value of all benefits accrued or earned as of the beginning of the plan year. While the annual targets are not 

legally required, benefit payment options are limited for plans that do not meet the targets, and a funding deficiency notice must be 

sent to all plan participants. Our plans are in compliance with The Pension Act. 

In 2012, UniSource Energy expects to contribute $23 million to the pension plans, including $20 million in contributions by TEP. 

OTHER POSTRETIREMENT BENEFIT PLANS 

TEP provides limited health care and life insurance benefits for retirees. All regular employees may become eligible for these 

benefits if they reach retirement age while working for TEP or an affiliate. UNS Gas and UNS Electric provide postretirement 

medical benefits for current retirees. UNS Gas and UNS Electric active employees do not participate in the postretirement medical 

plan. 

In 2009, TEP established a Voluntary Employee Beneficiary Association (VEBA) to fund its other postretirement benefit plan. TEP 

contributed $2 million in each of 2011 and 2010 and $1 million in 2009 to the VEBA. We record changes in other postretirement 

obligation, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in 

Retail Rates. 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. 

 

K-129 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The pension and other postretirement benefit related amounts (excluding tax balances) included on the UniSource Energy balance 

sheet are: 

 

The table above includes accrued pension benefit liabilities for UNS Gas and UNS Electric of approximately $8 million at 

December 31, 2011, and $6 million at December 31, 2010. The table also includes a postretirement benefit liability of $1 million for 

UNS Gas and UNS Electric for each period presented.

OBLIGATIONS AND FUNDED STATUS 

We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 31, 

2011, and December 31, 2010. The tables below include TEP’s, UNS Gas’ and UNS Electric’s plans. The change in projected 

benefit obligation and plan assets and reconciliation of the funded status are as follows: 

 

 

 

K-130 

 Pension Benefits 

Other Postretirement 

Benefits 

 Years Ended December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsRegulatory Pension Asset included in Other Regulatory Assets $ 106 $ 86 $ 8 $ 8 

Accrued Benefit Liability included in Accrued Employee Expenses (1 ) — (2 ) (4 ) 

Accrued Benefit Liability included in Pension and Other Postretirement 

Benefits (72 ) (63 ) (66 ) (65 ) 

Accumulated Other Comprehensive Loss (SERP) 2 4 — — 

 

Net Amount Recognized $ 35 $ 27 $ (60 ) $ (61 ) 

 

 

 

 

 

 

 

 

 Pension Benefits 

Other Postretirement 

Benefits 

 Years Ended December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsChange in Projected Benefit Obligation 

Benefit Obligation at Beginning of Year $ 283 $ 242 $ 73 $ 71 

Actuarial (Gain) Loss 22 28 — (1 ) 

Interest Cost 16 15 4 4 

Service Cost 10 8 3 3 

Amendments — — (2 ) — 

Other — 1 — — 

Benefits Paid (12 ) (11 ) (5 ) (4 ) 

 

Projected Benefit Obligation at End of Year 319 283 73 73 

 

Change in Plan Assets 

Fair Value of Plan Assets at Beginning of Year 220 184 4 2 

Actual Return on Plan Assets 14 25 — — 

Benefits Paid (12 ) (11 ) (5 ) (4 ) 

Employer Contributions (1) 23 22 6 6 

 

Fair Value of Plan Assets at End of Year 245 220 5 4 

 

Funded Status at End of Year $ (74 ) $ (63 ) $ (68 ) $ (69 ) 

 

 

 

 

 

 

 

 

(1) TEP made $20 million in pension contributions and $6 million of other postretirement benefits contributions in 2011 and 2010. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

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 

starting in 2018. There are 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 $1 million at December 31, 2011 and $2 million at 

December 31, 2010. 

The table above includes the following for UNS Gas and UNS Electric: 

 

 

 

The following table provides the components of UniSource Energy’s regulatory assets and accumulated other comprehensive loss 

that have not been recognized as components of net periodic benefit cost as of the dates presented: 

 

Information for pension plans with Accumulated Benefit Obligations in excess of pension plan assets follows: 

 

At December 31, 2011, and December 31, 2010, all UniSource Energy defined benefit pension plans had accumulated benefit 

obligations in excess of pension plan assets. 

The components of net periodic benefit costs are as follows: 

 

Approximately 19% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in 

current year earnings. 

 

K-131 

 • Pension benefit obligations of $8 million at December 31, 2011, and $6 million at December 31, 2010; 

 • Plan assets of $10 million December 31, 2011, and $9 million at December 31, 2010; and 

 • A postretirement benefit liability of $1 million at December 31, 2011 and December 31, 2010. 

 Pension Benefits 

Other Postretirement 

Benefits 

 Years Ended December 31, 

 2011 2010 2011 2010 

 -Millions of DollarsNet Loss $ 108 $ 89 $ 11 $ 11 

Prior Service Cost (Benefit) 1 1 (3 ) (3 ) 

 December 31, 

 2011 2010 

 -Millions of DollarsProjected Benefit Obligation at End of Year $ 319 $ 283 

Accumulated Benefit Obligation at End of Year 281 243 

Fair Value of Plan Assets at End of Year 245 220 

 Pension Benefits 

Other Postretirement 

Benefits 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsService Cost $ 10 $ 8 $ 7 $ 3 $ 3 $ 2 

Interest Cost 15 15 14 4 4 4 

Expected Return on Plan Assets (16 ) (14 ) (11 ) — — — 

Prior Service Cost Amortization — — 1 (1 ) (2 ) (2 ) 

Recognized Actuarial Loss 6 5 7 — — 1 

 

Net Periodic Benefit Cost $ 15 $ 14 $ 18 $ 6 $ 5 $ 5 

 

 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: 

 

 

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of 

employees expected to receive benefits under the plan. We will amortize $7 million estimated net loss and less than $0.5 million 

prior service cost from other regulatory assets and less than $0.5 million prior service cost from AOCI into net periodic benefit cost 

in 2012. The estimated net loss for the defined benefit postretirement plans that will be amortized from other regulatory assets into 

net periodic benefit cost in 2012 is less than $1 million. The estimated prior service benefit that will be amortized is less than $1 

million. 

 

 

Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation 

increase, and the expected return on plan assets. 

We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment 

return model. The model used provides a “best-estimate” range over 20 years from the 25 percentile to the 75 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. 

 

K-132 

 Pension Benefits 

 2011 2010 2009 

 

Regulatory 

Asset AOCI 

Regulatory 

Asset AOCI 

Regulatory 

Asset 

 -Millions of DollarsCurrent Year Actuarial (Gain) Loss $ 25 $ (2 ) $ 16 $ 1 $ (21 ) 

Amortization of Actuarial (Gain) Loss (5 ) — (5 ) — (7 ) 

Plan Amendments — — — — (1 ) 

 

Total Recognized (Gain) Loss $ 20 $ (2 ) $ 11 $ 1 $ (29 ) 

 

 

 

 

 

 

 

 

 

 

 Other Postretirement Benefits 

 2011 2010 2009 

 

Regulatory 

Asset 

Regulatory 

Asset 

Regulatory 

Asset 

 -Millions of DollarsPrior Service Cost (Credit) $ (2 ) $ — $ — 

Current Year Actuarial (Gain) Loss — (1 ) 1 

Amortization of Actuarial Gain (Loss) — (1 ) (1 ) 

Prior Service (Cost) Amortization 1 2 2 

 

Total Recognized (Gain) Loss $ (1 ) $ — $ 2 

 

 

 

 

 

 

 Pension Benefits 

Other Postretirement 

Benefits 

 2011 2010 2011 2010 

Weighted-Average Assumptions Used to Determine Benefit 

Obligations as of the Measurement Date 

Discount Rate 4.9%-5.0% 5.5% - 5.6% 4.7% 5.2% 

Rate of Compensation Increase 3.0% 3.0% – 5.0% N/A N/A 

 Pension Benefits 

Other Postretirement 

Benefits 

 2011 2010 2009 2011 2010 2009 

Weighted-Average Assumptions Used to Determine 

Net Periodic Benefit Cost for Years Ended 

December 31 

Discount Rate 5.5%-5.6% 6.3% 6.3% 5.2% 6.0% 6.5% 

Rate of Compensation Increase 3.0%-5.0% 3.0%–5.0% 3.0% -5.0% N/A N/A N/A 

Expected Return on Plan Assets 7.0% 7.5% 8.0% 5.1% 5.6% N/A 

th th 
Table of Contents 

UNISOURCE 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. 

 

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, 2011 amounts: 

 

PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS 

Pension Assets 

We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset 

category, were as follows: 

 

 

K-133 

 December 31, 

 2011 2010 

Assumed Health Care Cost Trend Rates 

Health Care Cost Trend Rate Assumed for Next Year 6.9 % 7.9 % 

Ultimate Health Care Cost Trend Rate Assumed 4.5 % 4.5 % 

Year that the Rate Reaches the Ultimate Trend Rate 2049 2027 

 

OnePercentagePoint Increase 

OnePercentagePoint 

Decrease 

 -Millions of DollarsEffect on Total of Service and Interest Cost Components $ 1 $ (1 ) 

Effect on Postretirement Benefit Obligation 5 (5 ) 

 TEP Plan Assets UNS Gas and UNS Electric Plan Assets 

 

December 31, 

2011 

December 31, 

2010 

December 31, 

2011 

December 31, 

2010 

Asset Category 

Equity Securities 49 % 57 % 55 % 57 % 

Fixed Income Securities 42 34 34 32 

Real Estate 7 7 11 11 

Other 2 2 — — 

 

Total 100 % 100 % 100 % 100 % 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The following tables set forth the fair value measurements of pension plan assets, by level within the fair value hierarchy: 

 

 

Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money 

market funds, and certificates of deposit. 

Level 2 investments comprise amounts held in commingled equity funds, U.S. bond and real estate funds. Valuations are based on 

active market quoted prices for assets held by each respective fund. 

Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on 

appraisals comprising 85% of real estate assets tracked by the index in 2011, and comprising 94% in 2010. 

Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. 

 

K-134 

 

Fair Value Measurements of Pension Assets 

December 31, 2011 

 

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: 

U.S. Large Cap — 61 — 61 

U.S. Small Cap — 13 — 13 

Non-U.S. — 47 — 47 

Fixed Income — 101 — 101 

Real Estate — 7 11 18 

Private Equity — — 4 4 

 

Total $ 1 $ 229 $ 15 $ 245 

 

 

 

 

 

 

 

 

 

Fair Value Measurements of Pension Assets 

December 31, 2010 

 

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: 

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 

 

 

 

 

 

 

 

 
Table of Contents 

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 

$10 million at December 31, 2011, and $9 million at December 31, 2010. 

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. 

 

 

UES has no pension assets classified as Level 3 in the fair value hierarchy. 

Pension Plan Investments 

Investment Goals 

Strategic asset allocation is the principal method for achieving each pension plan’s investment objective, while maintaining an 

appropriate level of risk. We will consider the projected impact on benefit security of any proposed changes to the current asset 

allocation policy. The expected long-term returns and implications for pension plan sponsor funding will be reviewed in selecting 

policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We 

expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to 

real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest 

rate risk. 

Risk Management 

We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment 

markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In 

establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: 1) plan status; 2) 

plan sponsor financial status and profitability; 3) 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 also have been used for defensive purposes. 

 

K-135 

 

Year Ended 

December 31, 2011 

 Private Equity Real Estate Hedge Fund Total 

 - Millions of Dollars - 

Beginning Balance at January 1, 2011 $ 2 $ 10 $ — $ 12 

Actual Return on Plan Assets: 

Assets Held at Reporting Date — 1 — 1 

Assets Sold During the Period — — — — 

Purchases, Sales, and Settlements 2 — — 2 

 

Ending Balance at December 31, 2011 $ 4 $ 11 $ — $ 15 

 

 

 

 

 

 

 

 

 

Year Ended 

December 31, 2010 

 Private Equity Real Estate Hedge Fund Total 

 - Millions of Dollars - 

Beginning Balance at January 1, 2010 $ 1 $ 8 $ 1 $ 10 

Actual Return on Plan Assets: 

Assets Held at Reporting Date — 1 — 1 

Assets Sold During the Period — — (1 ) (1 ) 

Purchases, Sales, and Settlements 1 1 — 2 

 

Ending Balance at December 31, 2010 

 $ 2 $ 10 $ — 

$ 

 

 

12 

 

 

 

 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Relationship between Plan Assets and Benefit Obligations 

The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation 

and Projected Benefit Obligation) against the market value of assets and tracking the changes in each. The frequency of this 

monitoring will depend on the availability of plan data, but will be no less frequent than annually via annual actuarial valuation. 

The current target allocation percentages for the major categories of plan assets as of December 31, 2011 follow. Each plan allows 

a variance of +/- 2% from these targets before funds are automatically rebalanced. 

 

Pension Fund Descriptions 

The funds are manager of manager funds, which allow different fund managers to make investment decisions, with the exception of 

the private equity fund, which holds a portfolio of investment funds. 

Other Postretirement Benefit Assets 

As of December 31, 2011, the fair value of VEBA trust assets were $5 million, of which $3 million were fixed income investments 

and $2 million were equities. As of December 31, 2010, the fair value of VEBA trust assets was $4 million, including $2 million of 

fixed income investments and approximately $2 million of equity and money market funds. There are no level three assets in the 

VEBA trust. 

ESTIMATED FUTURE BENEFIT PAYMENTS 

TEP expects the following benefit payments to be made by the defined benefit pension plans and postretirement plan, which reflect 

future service, as appropriate. 

 

UNS Gas and UNS Electric expect annual pension and postretirement benefit payments of approximately $6 million in 2012 

through 2016 and $9 million in 2017 through 2021 to be made by the defined benefit pension and postretirement plans. 

 

K-136 

 TEP Plan UES Plan VEBA Trust 

Fixed Income 41 % 33 % 38 % 

U.S. Large Cap 24 % 28 % 33 % 

Non-U.S. Developed 15 % 17 % 9 % 

Real Estate 8 % 11 % — 

U.S. Small Cap 5 % 5 % 7 % 

Non-U.S. Emerging 5 % 6 % 11 % 

Private Equity 2 % — — 

Cash / Treasury Bills — — 2 % 

 

Total 100 % 100 % 100 % 

 

 

 

 

 

 

 

Pension 

Benefits 

Other 

Postretirement 

Benefits 

 -Millions of Dollars2012 $ 13 $ 4 

2013 15 5 

2014 16 5 

2015 17 5 

2016 18 5 

Years 2017-2021 109 31 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

DEFINED CONTRIBUTION PLANS 

We offer defined contribution savings plans to all eligible employees. The Internal Revenue Code identifies the plans as qualified 

401(k) plans. Participants direct the investment of contributions to certain funds in their account which may include a UNS stock 

fund. We match part of a participant’s contributions to the plans. TEP made matching contributions to these plans of $5 million in 

2011 and $4 million in each of 2010 and 2009. UNS Gas and UNS Electric made matching contributions of less than $1 million in 

each of 2011, 2010, and 2009. 

NOTE 10. SHARE-BASED COMPENSATION PLAN 

In 2011, UniSource Energy shareholders approved the UniSource Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), a 

new share-based compensation plan. Under the 2011 Plan, the Compensation Committee of the UniSource Energy Board of 

Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted 

shares/units, and performance shares. The total number of shares which may be awarded under the 2011 Plan cannot exceed 

1.2 million shares. The 2011 Plan supersedes and replaces the UniSource Energy 2006 Omnibus Stock and Incentive Plan (2006 

Plan) and all other prior equity compensation plans (Prior Plans). The Prior Plans, however, remain in effect until all stock options 

and other awards granted thereunder have been exercised, forfeited, canceled, expired or terminated. 

STOCK OPTIONS 

No stock options were granted by the Compensation Committee during 2011 or 2010. In 2009, the Compensation Committee 

granted 248,760 stock options to officers with an exercise price of $26.11. 

Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three 

years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of 

the grant. Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant 

date fair value of the options less estimated forfeitures. For awards granted to retirement eligible officers, compensation expense is 

recorded immediately. 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. 

The fair value of the 2009 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 term of the stock options granted in 2009 was 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 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. 

 

 

K-137 

 2009 

Expected Term (years) 7 

Risk-free Rate 3.4 % 

Expected Volatility 25.0 % 

Expected Dividend Yield 3.2 % 

Weighted-Average Grant-Date Fair Value of 

Options Granted During the Period $ 5.53 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

See summary of the stock option activity in the table below: 

 

 

See summary of stock options in the table below: 

 

RESTRICTED STOCK UNITS/AWARDS AND PERFORMANCE SHARES 

Restricted Stock Units 

Restricted stock and stock units are generally granted to non-employee directors. Restricted stock is an award of Common Stock 

that is subject to forfeiture if the restrictions specified in the award are not satisfied. Stock units are a non-voting unit of measure 

that is equivalent to one share of Common Stock. The directors may elect to receive stock units in lieu of restricted stock. 

Restricted stock generally vests over periods ranging from one to three years and is payable in Common Stock. Stock units vest 

either immediately or over periods ranging from one to three years. The restricted stock units vest immediately upon death, 

disability, or retirement. In the January following the year the person is no longer a director, Common Stock shares will be issued 

for the vested stock units. Compensation expense equal to the fair market value on the grant date is recognized over the vesting 

period. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of 

common shares on the date the dividend is paid. 

Common Stock shares totaling 56,705 in 2011, 14,866 in 2010, and 101,765 in 2009 were issued with no additional increase in 

equity as the expense was previously recognized over the vesting period. 

 

K-138 

(Shares in Thousands) 2011 2010 2009 

Stock Options Shares 

Weighted 

Average 

Exercise 

Price Shares 

Weighted 

Average 

Exercise 

Price Shares 

Weighted 

Average 

Exercise 

Price 

Outstanding, Beginning of Year 921 $ 27.96 1,598 $ 24.50 1,635 $ 22.50 

Granted — — — — 249 26.11 

Exercised (319 ) 25.60 (660 ) 19.33 (282 ) 14.46 

Forfeited/Expired (21 ) 31.92 (17 ) 37.88 (4 ) 12.28 

 

Outstanding, End of Year 581 29.11 921 27.96 1,598 24.50 

 

 

 

 

 

 

 

Exercisable, End of Year 508 $ 29.53 654 $ 28.70 1,085 $ 23.06 

Aggregate Intrinsic Value of Options 

Exercised ($000s) $ 3,690 $ 9,124 $ 4,177 

 At December 31, 2011 

Aggregate Intrinsic Value for Options Outstanding ($000s) $ 4,670 

Aggregate Intrinsic Value for Options Exercisable ($000s) $ 3,892 

Weighted Average Remaining Contractual Life of Outstanding Options 5.6 years 

Weighted Average Remaining Contractual Life of Exercisable Options 5.4 years 

 Options Outstanding Options Exercisable 

Range of Exercise Prices 

Number of 

Shares 

(000s) 

WeightedAverage 

Remaining 

Contractual 

Life 

WeightedAverage 

Exercise 

Price 

Number of 

Shares 

(000s) 

WeightedAverage 

Exercise 

Price 

$17.44 - $17.84 20 1.3 years $ 17.75 20 $ 17.75 

$26.11 - $37.88 561 5.7 years $ 29.51 489 $ 30.01 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The Compensation Committee granted the following stock units to non-employee directors: 

 

 

 

Performance Share Awards 

In 2011, the Compensation Committee granted performance share awards to officers. Half of the performance share awards had a 

grant date fair value, based on a Monte Carlo simulation, of $33.73 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 the 

Edison Electric Institute Index during the performance period of January 1, 2011 through December 31, 2013. The remaining half 

had a grant date fair value of $36.58 per share and will be paid out in shares of UniSource Energy Common Stock based on 

cumulative net income for the three-year period ending December 31, 2013. The performance shares vest based on the 

achievement of goals by the end of the performance period; any unearned awards are forfeited. Performance shares are eligible for 

dividend equivalents during the performance period.

In 2010, the Compensation Committee granted performance share awards to officers. 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 Stock based on a comparison of UniSource Energy’s cumulative Total Shareholder Return to the 

Edison Electric Institute Index during the performance period of January 1, 2010 through December 31, 2012. The remaining half 

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 three-year period ending December 31, 2012. The performance shares vest based on the 

achievement of goals by the end of the performance period; any unearned awards are forfeited. Performance shares are eligible for 

dividend equivalents during the performance period.

In 2009, the Compensation Committee granted performance share awards to officers at a grant date fair value, based on a Monte 

Carlo simulation, of $21.62 per share. At December 31, 2011, upon completion of the three-year performance period, 45,642 

shares vested based on goal attainment at 75% 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; 23,414 shares were unearned 

and forfeited. Compensation expense equal to the fair value on the grant date was recognized over the vesting period for the 

requisite service period. 

 

 

K-139 

 • May 2011—14,655 stock units at a weighted average fair value of $37.53 per share, 

 • May 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. 

 Performance Shares Restricted Stock Units 

 

Shares 

(000s) 

WeightedAverage 

Grant-Date 

Fair Value 

Shares 

(000s) 

WeightedAverage 

Grant-Date 

Fair Value 

Non-vested at January 1, 2011 156 $ 27.19 16 $ 31.69 

Granted 93 35.26 15 37.53 

Vested (46 ) 23.41 (16 ) 31.69 

Forfeited (50 ) 28.29 — — 

 

Non-vested at December 31, 2011 153 $ 32.85 15 $ 37.53 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units) 

Annually during 2009 through 2011, UniSource Energy recorded share-based compensation expense of $3 million, $2 million of 

which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. UniSource Energy did not 

realize a tax deduction from the exercise of share-based payment arrangements in 2011. In each of 2010 and 2009, UniSource 

Energy realized an actual tax deduction from the exercise of share-based payment arrangements of $3 million. 

At December 31, 2011, the total unrecognized compensation cost related to non-vested share-based compensation was $2 million, 

which will be recorded as compensation expense over the remaining vesting periods through December 2013. The total number of 

shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at 

December 31, 2011, was 0.7 million. 

NOTE 11. FAIR VALUE MEASUREMENTS 

The following tables set forth, by level within the fair value hierarchy, UniSource Energy’s and TEP’s assets and liabilities 

accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level 

of input significant to the fair value measurement. There were no transfers between Levels 1, 2 or 3 for either reporting period. 

 

 

K-140 

 UniSource Energy 

 

Quoted Prices 

in Active 

Markets for 

Identical Assets 

(Level 1) 

Significant 

Other 

Observable 

Inputs 

(Level 2) 

Significant 

Unobservable 

Inputs 

(Level 3) Total 

 December 31, 2011 

 - Millions of Dollars - 

Assets 

Cash Equivalents $ 23 $ — $ — $ 23 

Rabbi Trust Investments to support the Deferred Compensation and 

SERP Plans — 16 — 16 

Energy Contracts — — 14 14 

 

Total Assets 23 16 14 53 

 

Liabilities 

Energy Contracts — (21 ) (24 ) (45 ) 

Interest Rate Swaps — (12 ) — (12 ) 

 

Total Liabilities — (33 ) (24 ) (57 ) 

 

Net Total Assets and (Liabilities) $ 23 $ (17 ) $ (10 ) $ (4 ) 

 

 

 

 

 

 

 

 

(1) 

(2) 

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Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

 

K-141 

 UniSource Energy 

 

Quoted Prices 

in Active 

Markets for 

Identical Assets 

(Level 1) 

Significant 

Other 

Observable 

Inputs 

(Level 2) 

Significant 

Unobservable 

Inputs 

(Level 3) Total 

 December 31, 2010 

 - Millions of Dollars - 

Assets 

Cash Equivalents $ 38 $ — $ — $ 38 

Rabbi Trust Investments to support the Deferred Compensation and 

SERP Plans — 16 — 16 

Collateral Posted — 3 — 3 

Energy Contracts — — 15 15 

 

Total Assets 38 19 15 72 

 

Liabilities 

Energy Contracts — (19 ) (25 ) (44 ) 

Interest Rate Swaps — (10 ) — (10 ) 

 

Total Liabilities — (29 ) (25 ) (54 ) 

 

Net Total Assets and (Liabilities) $ 38 $ (10 ) $ (10 ) $ 18 

 

 

 

 

 

 

 

 

 TEP 

 

Quoted Prices 

in Active 

Markets for 

Identical Assets 

(Level 1) 

Significant 

Other 

Observable 

Inputs 

(Level 2) 

Significant 

Unobservable 

Inputs 

(Level 3) Total 

 December 31, 2011 

 - Millions of Dollars - 

Assets 

Cash Equivalents $ 8 $ — $ — $ 8 

Rabbi Trust Investments to support the Deferred Compensation and 

SERP Plans — 16 — 16 

Energy Contracts — — 3 3 

 

Total Assets 8 16 3 27 

 

Liabilities 

Energy Contracts — (9 ) (3 ) (12 ) 

Interest Rate Swaps — (11 ) — (11 ) 

 

Total Liabilities — (20 ) (3 ) (23 ) 

 

Net Total Assets and (Liabilities) $ 8 $ (4 ) $ — $ 4 

 

 

 

 

 

 

 

 

(1) 

(2) 

(3) 

(4) 

(4) 

(5) 

(1) 

(2) 

(4) 

(4) 

(5) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

 

 

 

 

Energy Contracts 

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially 

the full term of the asset or liability—such as gas swap derivatives valued using New York Mercantile Exchange (NYMEX) pricing, 

adjusted for basis differences—we categorize the instrument in Level 2. We categorize derivatives in Level 3 using an aggregate 

pricing service or published prices that represent a consensus reporting of multiple brokers. 

For both power and gas prices, TEP and UNS Electric obtain quotes from brokers, major market participants, exchanges or 

industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of 

quotations each for power and for gas and then validate those prices using other sources. We believe that the market information 

provided is reflective of market conditions as of the time and date indicated. 

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms including: delivery 

periods during non-standard time blocks, delivery during only a few months of a given year when prices are quoted only for the 

annual average, or delivery at illiquid delivery points. In these cases, we use percentage multipliers to value non-standard time 

blocks, we apply historical price curve relationships to calendar year quotes, and we include adjustments for transmission and line 

losses to value contracts at illiquid delivery points. 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. We review these 

assumptions quarterly. 

 

K-142 

 TEP 

 

Quoted Prices 

in Active 

Markets for 

Identical Assets 

(Level 1) 

Significant 

Other 

Observable 

Inputs 

(Level 2) 

Significant 

Unobservable 

Inputs 

(Level 3) Total 

 December 31, 2010 

 - Millions of Dollars - 

Assets 

Cash Equivalents $ 21 $ — $ — $ 21 

Rabbi Trust Investments to support the Deferred Compensation and 

SERP Plans — 16 — 16 

Energy Contracts — — 3 3 

 

Total Assets 21 16 3 40 

 

Liabilities 

Energy Contracts — (7 ) (2 ) (9 ) 

Interest Rate Swaps — (10 ) — (10 ) 

 

Total Liabilities — (17 ) (2 ) (19 ) 

 

Net Total Assets and (Liabilities) $ 21 $ (1 ) $ 1 $ 21 

 

 

 

 

 

 

 

 

(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 Investments and Other Property—Other on the balance sheets. 

(2) Rabbi Trust Investments include amounts held in mutual and money market funds related to deferred compensation and SERP benefits. The valuation is based on 

quoted prices traded in active markets. These investments are included in Investments and Other Property—Other on the balance sheets. 

(3) Collateral provided for energy contracts with counterparties to reduce credit risk exposure. Collateral Posted is included in Current Assets—Other on the UniSource 

Energy balance sheet. 

(4) Energy Contracts include gas swap agreements (Level 2), gas collars (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 Derivative Instruments on the balance sheets. 

The valuation techniques are described below. See Note 16. 

(5) 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 Swap 

index. These interest rate swaps are included in Derivative Instruments on the balance sheets. 

(1) 

(2) 

(4) 

(4) 

(5) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

TEP estimates the fair value of its purchase power call option 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. 

UNS Gas estimates the fair value of its gas collar using the Black-Scholes-Merton option pricing model which includes assumptions 

about future prices of energy, interest rates, volatility, credit worthiness and credit spread. 

UniSource Energy’s and TEP’s 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. 

The following tables set forth a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair 

value hierarchy: 

 

 

K-143 

 

Year Ended 

December 31, 2011 

 

UniSource 

Energy TEP 

 Energy Contracts 

 -Millions of DollarsBalance as of December 31, 2010 $ (10 ) $ 1 

Gains and (Losses) (Realized/Unrealized) Recorded to: 

Net Regulatory Assets – 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 or losses relating to assets/liabilities 

still held at the end of the period $ (9 ) $ — 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

Financial Instruments Not Carried at Fair Value 

The market price received when selling an asset or paid to transfer a liability at the measurement date is the fair value of a financial 

instrument. We use the following methods and assumptions for estimating the fair value of our financial instruments: 

 

 

 

 

K-144 

 

Year Ended 

December 31, 2010 

 UniSource Energy TEP 

 

Energy 

Contracts 

Equity 

Investments Total 

Energy 

Contracts 

 - Millions of Dollars - 

Balance as of December 31, 2009 $ (13 ) $ 6 $ (7 ) $ (4 ) 

Gains and (Losses) (Realized/Unrealized) Recorded to: 

Net Regulatory Assets – Derivative Instruments (9 ) — (9 ) 9 

Other Comprehensive Income (1 ) — (1 ) (1 ) 

Other Expense — (6 ) (6 ) — 

Settlements 13 — 13 (3 ) 

 

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 

 

 

 

 

 

 

 

 

(1) In December 2010, Millennium reduced to zero the book value of its equity investments classified as Level 3 in the fair value 

hierarchy. 

• The carrying amounts of our current assets and liabilities, including Current Maturities of Long-Term Debt, and amounts 

outstanding under our credit agreements approximate their fair value due to the short-term nature of these instruments; with 

the exception of $50 million of UNS Gas Senior Unsecured Notes, outstanding at December 31, 2010, with a make-whole 

provision on a call premium that have a fair value of $51 million. These items have been excluded from the table below. 

• Investments in Lease Debt and Equity: TEP calculates 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 incorporate the impact of counterparty credit risk using market credit default swap data. The fair value of TEP’s 

Investment in Lease Equity decreased significantly during the fourth quarter of 2011 based on the recent Springerville Unit 1 

appraisal. No impairment was recorded as TEP expects to recover the full carrying value in Retail Rates. 

• Long-Term Debt: UniSource Energy and TEP 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 bonds with similar characteristics with respect to 

credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable 

estimates of their 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. 

(1) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The amount 

recorded on the balance sheet (carrying value) and the estimated fair values of our financial instruments included the following: 

 

TEP intends to hold the $29 million investment in Springerville Lease Debt Securities to maturity. This investment is stated at 

amortized cost, which means the purchase cost has been adjusted for the amortization of the premium and discount to maturity. 

NOTE 12. UNISOURCE ENERGY EARNINGS PER SHARE (EPS) 

We compute basic EPS by dividing Net Income by the weighted average number of common shares outstanding during the period. 

Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon 

exercise of outstanding stock options; contingently issuable shares under equity-based awards or common shares that would result 

from the conversion of convertible notes. The numerator in calculating diluted EPS is Net Income adjusted for the interest on 

Convertible Senior Notes (net of tax) that would not be paid if the notes were converted to common shares. 

The following table shows the effects of potentially dilutive common stock on the weighted average number of shares: 

 

 

K-145 

 December 31, 

 2011 2010 

 

Carrying 

Value 

Fair 

Value 

Carrying 

Value 

Fair 

Value 

 -Millions of DollarsAssets: 

TEP Investment in Lease Debt and Equity $ 66 $ 50 $ 105 $ 111 

Liabilities: 

Long-Term Debt 

TEP 1,080 1,061 1,004 862 

UniSource Energy 1,517 1,543 1,353 1,238 

 Years Ended December 31, 

 2011 2010 2009 

 -Thousands of DollarsNumerator: 

Net Income $ 109,975 $ 112,984 $ 105,901 

Income from Assumed Conversion of Convertible Senior Notes 4,390 4,390 4,390 

 

Adjusted Numerator $ 114,365 $ 117,374 $ 110,291 

 

 

 

 

 

 

 -Thousands of SharesDenominator: 

Weighted Average Shares of Common Stock Outstanding: 

Common Shares Issued 36,780 36,200 35,653 

Fully Vested Deferred Stock Units 129 123 105 

Participating Securities 53 92 100 

 

Total Weighted Average Shares of Common Stock Outstanding and 

Participating Securities—Basic 36,962 36,415 35,858 

Effect of Diluted Securities: 

Convertible Senior Notes 4,281 4,178 4,093 

Options and Stock Issuable under Share Based Compensation 

Plans 366 448 499 

 

Total Shares—Diluted 41,609 41,041 40,450 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The following table shows the number of stock options excluded from the diluted EPS computation because the stock option’s 

exercise price was greater than the average market price of the Common Stock: 

 

In January 2012, holders of approximately $33 million of Convertible Senior Notes converted their interests into approximately 

964,000 shares of UniSource Energy Common Stock. This conversion of convertible notes to common stock will have a minimal 

impact on diluted EPS as the dilutive effect of the convertible notes has been reflected in the diluted EPS computation. 

NOTE 13. MILLENNIUM INVESTMENTS 

In 2010, Millennium recorded impairment losses of $10 million reducing the book value of its unconsolidated equity and cost 

method investments to zero. Millennium received notification of valuation changes and ownership percentage reductions as 

projects lost viability and funding failed. In addition, Millennium sold a wholly-owned subsidiary, and recorded a gain of less than $1 

million. Gains and losses were included in Other Income or Other Expense on UniSource Energy's income statements. Millennium 

also wrote off $3 million of Deferred Tax Assets related to its investments. 

In 2009, Millennium sold an equity investment and recorded a $6 million gain on the sale which is included in Other Income on 

UniSource Energy's income statements. Millennium received an upfront payment of $5 million in 2009 and a $15 million, three-year, 

6%, secured note receivable due in June 2012. Principal on the note is due at maturity; interest on the note is due annually on 

December 31. The $15 million note is included in Current Asset – Other on UniSource Energy’s balance sheet. 

NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS 

The following recently issued accounting standards are not yet reflected in the financial statements: 

 

 

 

 

K-146 

 Years Ended December 31, 

 2011 2010 2009 

 -Thousands of SharesStock Options Excluded from the Diluted EPS Computation 153 212 395 

 

 

 

 

 

 

 

• The Financial Accounting Standards Board (FASB) issued authoritative guidance that will eliminate the current option to 

report other comprehensive income in the statement of changes in equity. An entity can elect to present items of net 

income and other comprehensive income in one continuous statement, or in two separate but consecutive statements. 

We will be required to comply in the first quarter of 2012 and plan to present a separate statement of other 

comprehensive income. 

 

• The FASB issued authoritative guidance that changed some fair value measurement principles and disclosure 

requirements. The most significant disclosure change is expansion of required information for unobservable inputs. We 

will be required to comply in the first quarter of 2012, and we do not expect this pronouncement to have a material impact 

on the valuation techniques used to estimate the fair value of assets and liabilities. 

 

• The FASB issued authoritative guidance that will require entities to disclose both gross and net information about 

instruments and transactions eligible for offset in the statement of financial position as well as instruments and 

transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires 

disclosure of collateral received and posted in connection with master netting arrangements. We will be required to 

comply in the first quarter of 2013. 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION 

A reconciliation of net income to net cash flows from operating activities follows: 

 

 

K-147 

 UniSource Energy 

 Years Ended December 31, 

 2011 2010 2009 

 -Thousands of DollarsNet Income $ 109,975 $ 112,984 $ 105,901 

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities 

Depreciation Expense 133,832 128,215 144,960 

Amortization Expense 30,983 28,094 31,058 

Depreciation and Amortization Recorded to Fuel and Other O&M Expense 6,140 5,432 4,929 

Amortization of Deferred Debt-Related Costs included in Interest Expense 3,985 3,753 4,171 

Provision for Retail Customer Bad Debts 2,072 3,724 3,583 

Use of Renewable Energy Credits for Compliance 5,695 4,745 — 

California Power Exchange Provision for Wholesale Revenue Refunds Refunds — — 4,172 

Deferred Income Taxes 75,588 28,142 57,452 

Deferred Tax Valuation Allowance (73 ) 7,510 — 

Pension and Postretirement Expense 21,202 19,688 23,594 

Pension and Postretirement Funding (28,775 ) (27,742 ) (30,078 ) 

Share Based Compensation Expense 2,599 2,751 2,779 

Excess Tax Benefit from Stock Options Exercised — (3,338 ) (3,256 ) 

Allowance for Equity Funds Used During Construction (4,496 ) (4,232 ) (4,113 ) 

CTC Revenue Refunded (35,958 ) (10,095 ) (12,726 ) 

Decrease to Reflect PPFAC/PGA Recovery (4,932 ) (29,622 ) (14,553 ) 

Gain on Settlement of El Paso Electric Dispute (7,391 ) — — 

Loss/(Gain) on Millennium’s Investments — 9,936 (4,730 ) 

Changes in Assets and Liabilities which Provided (Used) 

Cash Exclusive of Changes Shown Separately 

Accounts Receivable 2,743 (8,851 ) 6,458 

Materials and Fuel Inventory (20,864 ) 21,744 (24,621 ) 

Accounts Payable 7,397 2,661 (8,243 ) 

Income Taxes (2,739 ) 24,470 11,443 

Interest Accrued 14,344 14,354 15,956 

Current Regulatory Liabilities 2,644 2,788 10,009 

Taxes Other Than Income Taxes 2,857 2,442 (48 ) 

Other 20,492 7,367 23,213 

 

Net Cash Flows – Operating Activities $ 337,320 $ 346,920 $ 347,310 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

Proceeds from the issuance of the 2010 Coconino Bonds were deposited with a trustee and were used in 2010 to redeem $37 

million of pollution control bonds. TEP had no cash receipts or payments as a result of this transaction. 

Proceeds from the issuance of $100 million of Pima County tax-exempt IDBs were deposited in a construction fund with a trustee. 

TEP drew down funds as qualified expenditures were incurred. The $11 million remaining in the construction fund at December 31, 

2010 affected recognized assets and liabilities but did not result in cash receipts or payments. TEP drew down the remaining funds 

in the construction fund by March 2011. 

Proceeds from the issuance of $95 million of unsecured fixed rate IDBs in 2009 were deposited with a trustee and were used in 

2009, to redeem approximately $95 million of unsecured fixed rate IDBs. TEP had no cash receipts or payments as a result of this 

transaction. 

Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or 

payments were as follows: 

 

 

K-148 

 TEP 

 Years Ended December 31, 

 2011 2010 2009 

 -Thousands of DollarsNet Income $ 85,334 $ 108,260 $ 90,688 

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities 

Depreciation Expense 104,894 99,510 116,970 

Amortization Expense 34,650 32,196 35,931 

Depreciation and Amortization Recorded to Fuel and Other O&M Expense 4,509 3,855 3,439 

Amortization of Deferred Debt-Related Costs included in Interest Expense 2,378 2,146 2,364 

Provision for Retail Customer Bad Debts 1,447 2,506 2,342 

Use of Renewable Energy Credits for Compliance 5,190 4,245 — 

California Power Exchange Provision for Wholesale Revenue Refunds Refunds — — 4,172 

Deferred Income Taxes 59,309 24,897 45,678 

Pension and Postretirement Expense 18,816 17,454 21,294 

Pension and Postretirement Funding (25,878 ) (25,672 ) (28,330 ) 

Share Based Compensation Expense 2,027 2,131 2,121 

Allowance for Equity Funds used During Construction (3,842 ) (3,567 ) (3,516 ) 

CTC Revenue Refunded (35,958 ) (10,095 ) (12,726 ) 

Decrease to Reflect PPFAC Recovery (6,165 ) (21,541 ) (18,186 ) 

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 4,809 (5,156 ) (951 ) 

Materials and Fuel Inventory (19,789 ) 20,920 (23,794 ) 

Accounts Payable 13,166 (447 ) (10,456 ) 

Income Taxes (5,582 ) 20,203 (2,714 ) 

Interest Accrued 14,268 14,431 16,142 

Current Regulatory Liabilities 303 2,500 10,555 

Taxes Other Than Income Taxes 2,282 1,469 725 

Other 19,517 12,238 16,316 

 

Net Cash Flows – Operating Activities $ 268,294 $ 302,483 $ 268,064 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

 

 

 

 

 

 

NOTE 16. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES 

FINANCIAL IMPACT OF DERIVATIVES 

Cash Flow Hedges 

At December 31, 2011, UniSource Energy and TEP had liabilities related to their cash flow hedges of $14 million and $12 million at 

December 31, 2010. 

The net after-tax unrealized gains and losses on derivative activities reported in AOCI were as follows: 

 

Regulatory Treatment of Commodity Derivatives 

The following table discloses unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on 

the balance sheet as a regulatory asset or a regulatory liability rather than as a component of AOCI or in the income statements. 

 

 

K-149 

 Years Ended December 31, 

 2011 2010 2009 

 -Thousands of Dollars- 

(Decrease)/Increase to Utility Plant Accruals $ (2,154 ) $ 8,514 $ 1,082 

Net Cost of Removal of Interim Retirements 31,626 4,592 43,381 

Capital Lease Obligations 15,162 16,630 17,984 

Asset Retirement Obligations 7,638 (1,872 ) — 

UED Secured Term Loan Prepayments — 3,188 3,625 

(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. 

 UniSource Energy TEP 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsNet After-Tax Unrealized Losses $ 4 $ 6 $ — $ 4 $ 6 $ — 

 UniSource Energy TEP 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsIncrease (Decrease) to Regulatory Assets $ 2 $ — $ (29 ) $ 2 $ (4 ) $ (11 ) 

(1) 

(2) 

(3) 

(4) 

(5) 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

The fair value of derivative assets and liabilities were as follows: 

 

The realized losses on settled gas swaps that are fully recoverable through the PPFAC or PGA were as follows: 

 

At December 31, 2011, UniSource Energy and TEP had contracts that will settle through the third quarter of 2015. 

Other Commodity Derivatives 

The settlement of forward purchased power and sales contracts that do not result in physical delivery were reflected in the financial 

statements of UniSource Energy and TEP as follows: 

 

DERIVATIVE VOLUMES 

At December 31, 2011, UniSource Energy had gas swaps totaling 14,856 Billion British thermal units (GBtu) and power contracts 

totaling 3,147 Gigawatt-hours (GWh) while TEP had gas swaps totaling 6,855 GBtu and power contracts totaling 815 GWh. At 

December 31, 2010, UniSource Energy had gas swaps totaling 14,973 GBtu and power contracts totaling 4,807 GWh while TEP 

had gas swaps totaling 6,424 GBtu and power contracts totaling 1,144 GWh. We account for gas swaps and power contracts as 

derivatives. 

CREDIT RISK ADJUSTMENT 

When the fair value of our derivative contracts is reflected as an asset, the counterparty owes us and this creates credit risk. We 

also consider the impact of our own credit risk on instruments that are in a net liability position. The impact of counterparty credit 

risk and our own credit risk on the fair value of derivative asset contracts was less than $0.5 million at December 31, 2011, and 

December 31, 2010. 

CONCENTRATION OF CREDIT RISK 

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk 

exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. 

We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the 

supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and 

mark-to-market valuations. 

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each 

company to post collateral under certain circumstances. These circumstances include: exposures 

 

K-150 

 UniSource Energy TEP 

 

December 31, 

2011 

December 31, 

2010 

December 31, 

2011 

December 31, 

2010 

 -Millions of DollarsAssets $ 14 $ 15 $ 3 $ 3 

Liabilities (43 ) (42 ) (9 ) (7 ) 

 

Net Assets (Liabilities) $ (29 ) $ (27 ) $ (6 ) $ (4 ) 

 

 

 

 

 

 

 

 

 UniSource Energy TEP 

 Years Ended December 31, 

 2011 2010 2009 2011 2010 2009 

 -Millions of DollarsRealized Losses on Gas Swaps $ 19 $ 23 $ 51 $ 7 $ 9 $ 29 

 2011 2010 2009 

 -Millions of DollarsRecorded in Wholesale Sales: 

Forward Power Sales $ 10 $ 27 $ 20 

Forward Power Purchases (15 ) (34 ) (18 ) 

 

Total Sales and Purchases Not Resulting in Physical Delivery $ (5 ) $ (7 ) $ 2 

 

 

 

 

 

 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

 

in excess of unsecured credit limits provided to TEP, UNS Gas or UNS Electric; credit rating downgrades; or a failure to meet 

certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in 

the form of cash or letters of credit to fully collateralize our exposure to these counterparties. 

The following table shows the sum of the fair value of all derivative instruments under contracts with credit-risk related contingent 

features that are in a net liability position at December 31, 2011. It also shows cash collateral and letters of credit posted, and 

additional collateral to be posted if credit-risk related contingent features were triggered. 

 

As of December 31, 2011, TEP had $17 million of credit exposure to other counterparties’ creditworthiness related to its wholesale 

marketing and gas hedging activities; and UNS Electric had $1 million of such exposure related to its supply and hedging contracts. 

TEP had four counterparties which individually comprise greater than 10% of the total credit exposure and UNS Electric had one. At 

December 31, 2011, UNS Gas had no exposure to other counterparties’ creditworthiness. 

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED) 

Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair 

presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the 

summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not 

represent overall trends and changes in operations.

 

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not 

equal the total for the year. 

 

K-151 

 TEP 

UniSource 

Energy 

 December 31, 2011 

 -Millions of DollarsNet Liability Position $ 16 $ 64 

Cash Collateral Posted — — 

Letters of Credit 1 6 

Additional Collateral to Post if Contingent Features Triggered 16 61 

 

 UniSource Energy 

 First Second Third Fourth 

 

-Thousands of Dollars- 

(Except Per Share Amounts) 

2011 

Operating Revenue $ 344,766 $ 369,673 $ 450,948 $ 344,128 

Operating Income 44,820 71,289 123,760 41,803 

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 

2010 

Operating Revenue $ 318,849 $ 339,114 $ 438,830 $ 357,173 

Operating Income 52,955 72,301 123,524 48,334 

Net Income 20,178 25,889 55,665 11,252 

Basic EPS 0.56 0.71 1.52 0.31 

Diluted EPS 0.52 0.66 1.38 0.30 
Table of Contents 

UNISOURCE ENERGY, TEP AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded) 

 

The following tables reflect the quarterly impact of revisions recorded in the second and third quarters of 2011 (See Note 1): 

 

 

 

K-152 

 

 TEP 

 First Second Third Fourth 

 -Thousands of Dollars2011 

Operating Revenue $ 239,588 $ 295,233 $ 369,846 $ 251,719 

Operating Income 27,792 62,497 111,479 27,613 

Net Income 4,704 25,157 53,912 1,561 

2010 

Operating Revenue $ 231,083 $ 274,694 $ 354,638 $ 264,852 

Operating Income 38,248 63,901 116,055 35,827 

Net Income 10,490 27,941 59,704 10,125 

 

2010 

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- (Except Per Share Amounts) 

 UniSource Energy 

Income Statement 

Net Income $ 19,972 $ 20,178 $ 25,886 $ 25,889 $ 54,883 $ 55,665 $ 11,082 $ 11,252 

Basic EPS 0.55 0.56 0.71 0.71 1.50 1.52 0.30 0.31 

Diluted EPS 0.52 0.52 0.66 0.66 1.36 1.38 0.29 0.30 

 TEP 

Income Statement 

Net Income $ 10,349 $ 10,490 $ 27,938 $ 27,941 $ 58,993 $ 59,704 $ 9,999 $ 10,125 
Table of Contents 

 

Schedule II—Valuation and Qualifying Accounts – UniSource Energy 

 

 

 

 

Schedule II—Valuation and Qualifying Accounts—TEP 

 

 

 

 

K-153 

Description 

Beginning 

Balance 

AdditionsCharged 

to Income Deductions 

Ending 

Balance 

Year Ended December 31, -Millions of DollarsReserve for Uncollectible Accounts 

2011 $ 13 $ 5 $ 2 $ 16 

2010 $ 13 $ 4 $ 4 $ 13 

2009 $ 27 $ 4 $ 18 $ 13 

Deferred Tax Assets Valuation Allowance 

2011 $ 8 $ — $ 1 $ 7 

2010 $ — $ 8 $ — $ 8 

2009 $ — $ — $ — $ — 

Other 

2011 $ 4 $ 6 

2010 $ 2 $ 4 

2009 $ 4 $ 2 

 TEP, UNS Gas and UNS Electric record additions to the Reserve for Uncollectible Accounts based on historical experience 

and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less 

amounts recovered. Amounts include reserves for trade receivables, wholesale sales and in-kind transmission imbalances. 

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. 

Principally reserves for sales tax audits, litigation and damages billable to third parties. 

Description 

Beginning 

Balance 

AdditionsCharged 

to Income Deductions 

Ending 

Balance 

Year Ended December 31, -Millions of DollarsReserve for Uncollectible Accounts 

2011 $ 11 $ 4 $ 1 $ 14 

2010 $ 11 $ 3 $ 3 $ 11 

2009 $ 24 $ 2 $ 15 $ 11 

Other 

2011 $ 3 $ 4 

2010 $ — $ 3 

2009 $ 4 $ — 

 TEP records additions to the Reserve for Uncollectible Accounts based on historical experience and any specific customer 

collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. 

Amounts include reserves for trade receivables, wholesales sales and in-kind transmission imbalances. 

Principally reserves for sales tax audits, litigation and damages billable to third parties. 

(1) 

(2) 

(3) 

(1) 

(2) 

(3) 

(1) 

(2) 

(1) 

(2) 
Table of Contents 

None. 

 

UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy 

and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 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, 2011. Disclosure controls 

and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSource Energy and 

TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time 

periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are 

also designed to ensure that information required to be disclosed by UniSource Energy and TEP in the reports that they file or 

submit under the Act is accumulated and communicated to management, including the principal executive and principal financial 

officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon 

the evaluation performed, UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that 

UniSource Energy and TEP’s disclosure controls and procedures are effective. 

While UniSource Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of 

their financial reporting, there has been no change in UniSource Energy or TEP’s internal control over financial reporting during the 

fourth quarter of 2011, that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal 

control over financial reporting. 

UniSource 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 UniSource Energy’s and TEP’s 2011 Annual Report on Form 10-K, the Report of 

Independent Registered Public Accounting Firm for UniSource 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. 

 

None. 

 

K-154 

ITEM 9. – CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 

ITEM 9A. – CONTROLS AND PROCEDURES 

ITEM 9B. – OTHER INFORMATION 
Table of Contents 

PART III 

 

 

Directors – UniSource Energy 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

K-155 

ITEM 10. – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS 

Name Age 

Board 

Committee* 

Director 

Since 

Paul J. Bonavia 60 None 2009 

Lawrence J. Aldrich 59 2,3,5 2000 

Barbara M. Baumann 56 1,2,4 2005 

Larry W. Bickle 66 3,4,5 1998 

Harold W. Burlingame 71 2,3,5 1998 

Robert A. Elliott 56 1,2,3,4,5 2003 

Daniel W.L. Fessler 70 1,3,5 2005 

Louise L. Francesconi 59 1,2,4 2008 

Warren Y. Jobe 71 1,2,4 2001 

Ramiro G. Peru 56 1,2,4 2008 

Gregory A. Pivirotto 59 1,3,4 2008 

Joaquin Ruiz 59 2,3,5 2005 

* Board Committees 

(1) Audit 

(2) Compensation 

(3) Corporate Governance and Nominating 

(4) Finance 

(5) Environmental, Safety and Security 

Paul J. Bonavia Mr. Bonavia has served as Chairman and Chief Executive Officer of UniSource Energy and 

TEP since January 2009; he also served as President from January 2009 to December 2011. 

Prior to joining UniSource 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. 

Lawrence J. Aldrich President and Chief Executive Officer of University Physicians Healthcare from 2009-2010. 

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 

2002 to December 2005; Managing Director and Founder of Tucson Ventures, LLC, from 

February 2000 to September 2002. 

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; member of the Board of 

Trustees of the Putnam Mutual Funds since 2010. 

Larry W. Bickle Director of SM Energy Company since 1994; Retired private equity investor; Managing Director 

of Haddington Ventures, LLC from 1997 to 2007. Non-executive Chairman of Quantum Natural 

Gas Strategies, 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; Director and Corporate 

Secretary of Southern Arizona Community Bank from 1998-2010; Television Analyst/Pre- game 

Show Co-host for Fox Sports Arizona from 1998-2009; Chairman of the Board of 
Table of Contents 

 

 

 

 

 

 

Directors – TEP 

 

 

 

 

K-156 

 

Tucson Metropolitan Chamber of Commerce from 2002 to 2003; Chairman of the Board of 

Tucson Urban League from 2003 to 2004; Chairman of the Board of the Tucson Airport 

Authority from January 2006 to January 2007; Director of AAA since 2007; Director of the NBA 

Retired Players Association since 2010; and Director of the University of Arizona Foundation. 

Daniel W.L. Fessler President of the California Public Utility Commission from 1991-1996; Professor Emeritus of the 

University of California since 1994; Of counsel for the law firm of Holland & Knight from 2003-

2007; Partner in the law firm of LeBoeuf, Lamb, Greene & MacRae LLP from 1997 to 2003; 

previously served on the UniSource 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; Director of Stryker Corporation since July 2006; 

Chairman of the Board of Trustees for TMC Healthcare; Director of Global Solar Energy, Inc. 

since 2008. 

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, a trucking company, 

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 President and Chief Executive Officer and Director of University Medical Center Corporation 

from 1994-2010; Certified Public Accountant since 1978; Director of Arizona Hospital & 

Healthcare Association from 1997 to 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. 

Name Age 

Director 

Since 

Paul J. Bonavia 60 2009 

Michael J. DeConcini 47 2009 

David G. Hutchens 45 2011 

Kevin P. Larson 55 2009 

Paul J. Bonavia Mr. Bonavia has served as Chairman and Chief Executive Officer of UniSource Energy and 

TEP since January 2009; he also served as President from January 2009 to December 2011. 

Prior to joining UniSource Energy, Mr. Bonavia served as President of the Utilities Group of Xcel 

Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises 

business unit and President of the company’s Energy Markets unit. 

Michael J. DeConcini Mr. DeConcini has served as Senior Vice President, Operations of UniSource Energy since May 

2010 and Senior Vice President and Chief Operating Officer of TEP from May 
Table of Contents 

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. 

 

 

Executive Officers of UniSource Energy and TEP 

See Item 1. Business, Executive Officers of the Registrants. 

Information required by Items 401, 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UniSource 

Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 

days after December 31, 2011, which information is incorporated herein by reference. 

 

Information concerning Executive Compensation will be contained in UniSource Energy’s Proxy Statement relating to the 2012 

Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, which 

information is incorporated herein by reference. 

 

General 

At February 21, 2012, UniSource Energy had outstanding 38.0 million shares of Common Stock. At February 21, 2012, the number 

of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to 

approximately 3% of the outstanding Common Stock. 

At February 21, 2012, UniSource Energy owned 100% of the outstanding shares of common stock of TEP. 

Security Ownership of Certain Beneficial Owners 

Information concerning the security ownership of certain beneficial owners of UniSource Energy will be contained in UniSource 

Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 

days after December 31, 2011, which information is incorporated herein by reference. 

Security Ownership of Management 

Information concerning the security ownership of the Directors and Executive Officers of UniSource Energy will be contained in 

UniSource Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later 

than 120 days after December 31, 2011, which information is incorporated herein by reference. 

 

K-157 

David G. Hutchens Mr. Hutchens has served as President of UniSource Energy and TEP since December 2011. In 

March 2011, Mr. Hutchens was named Executive Vice President of UniSource 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 

UniSource Energy and TEP. Mr. Hutchens joined TEP in 1995. 

Kevin P. Larson Mr. Larson has served as Senior Vice President and Chief Financial Officer of UniSource 

Energy and TEP since September 2005. Mr. Larson is also Treasurer of UniSource 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. 

ITEM 11. – EXECUTIVE COMPENSATION 

ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED 

STOCKHOLDER MATTERS 
Table of Contents 

Securities Authorized for Issuance Under Equity Compensation Plans 

Information concerning securities authorized for issuance under equity compensation plans will be contained in UniSource Energy’s 

Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after 

December 31, 2011, which information is incorporated herein by reference. 

 

Information concerning certain relationships and related transactions, and director independence of UniSource Energy and TEP will 

be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks 

and Insider Participation in UniSource Energy’s Proxy Statement relating to the 2012 Annual Meeting of Shareholders, which will be 

filed with the SEC not later than 120 days after December 31, 2011, which information is incorporated herein by reference. 

 

Information concerning principal accountant fees and services will be contained in UniSource Energy’s Proxy Statement relating to 

the 2012 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2011, which 

information is incorporated herein by reference. 

PART IV 

 

 

 

K-158 

ITEM 13. – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 

ITEM 14. – PRINCIPAL ACCOUNTANT FEES AND SERVICES 

ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 

 Page 

(a) (1). Consolidated Financial Statements as of December 31, 2011 and 2010 and for Each of the Three Years in the 

Period Ended December 31, 2011 

UniSource Energy Corporation 

Report of Independent Registered Public Accounting Firm 78 

Consolidated Statements of Income 80 

Consolidated Statements of Cash Flows 81 

Consolidated Balance Sheets 82 

Consolidated Statements of Capitalization 84 

Consolidated Statements of Changes in Stockholders’ Equity 85 

Notes to Consolidated Financial Statements 92 

Tucson Electric Power Company 

Report of Independent Registered Public Accounting Firm 79 

Consolidated Statements of Income 86 

Consolidated Statements of Cash Flows 87 

Consolidated Balance Sheets 88 

Consolidated Statements of Capitalization 90 

Consolidated Statements of Changes in Stockholder’s Equity 91 

Notes to Consolidated Financial Statements 92 

 (2). Financial Statement Schedules 

Schedule II 

Valuation and Qualifying Accounts 153 

 (3). Exhibits 

Reference is made to the Exhibit Index commencing on page 162. 
Table of Contents 

SIGNATURES 

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this 

report to be signed on its behalf by the undersigned, thereunto duly authorized. 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons 

on behalf of the registrant and in the capacities and on the dates indicated. 

 

 

K-159 

 UNISOURCE ENERGY CORPORATION 

Date: February 27, 2012 By: /s/ Kevin P. Larson 

 Kevin P. Larson 

 Senior Vice President and Principal 

 Financial Officer 

Date: February 27, 2012 /s/ Paul J. Bonavia* 

 Paul J. Bonavia 

 Chairman of the Board and 

 Principal Executive Officer 

Date: February 27, 2012 /s/ Kevin P. Larson 

 Kevin P. Larson 

 Principal Financial Officer 

Date: February 27, 2012 /s/ Karen G. Kissinger* 

 Karen G. Kissinger 

 Principal Accounting Officer 

Date: February 27, 2012 /s/ Lawrence J. Aldrich* 

 Lawrence J. Aldrich 

 Director 

Date: February 27, 2012 /s/ Barbara M. Baumann* 

 Barbara M. Baumann 

 Director 

Date: February 27, 2012 /s/ Larry W. Bickle* 

 Larry W. Bickle 

 Director 

Date: February 27, 2012 /s/ Harold W. Burlingame* 

 Harold W. Burlingame 

 Director 

Date: February 27, 2012 /s/ Robert A. Elliott* 

 Robert A. Elliott 

 Director 
Table of Contents 

 

K-160 

Date: February 27, 2012 /s/ Daniel W.L. Fessler* 

 Daniel W.L. Fessler 

 Director 

Date: February 27, 2012 /s/ Louise L. Francesconi* 

 Louise L. Francesconi 

 Director 

Date: February 27, 2012 /s/ Warren Y. Jobe* 

 Warren Y. Jobe 

 Director 

Date: February 27, 2012 /s/ Ramiro Peru* 

 Ramiro Peru 

 Director 

Date: February 27, 2012 /s/ Gregory A. Pivirotto* 

 Gregory A. Pivirotto 

 Director 

Date: February 27, 2012 /s/ Joaquin Ruiz* 

 Joaquin Ruiz 

 Director 

Date: February 27, 2012 By: /s/ Kevin P. Larson 

 Kevin P. Larson 

 As attorney-in-fact for each 

 of the persons indicated 
Table of Contents 

SIGNATURES 

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this 

report to be signed on its behalf by the undersigned, thereunto duly authorized. 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons 

on behalf of the registrant and in the capacities and on the dates indicated. 

 

 

K-161 

 TUCSON ELECTRIC POWER COMPANY 

Date: February 27, 2012 By: /s/ Kevin P. Larson 

 Kevin P. Larson 

 Senior Vice President and Principal 

 Financial Officer 

Date: February 27, 2012 /s/ Paul J. Bonavia* 

 Paul J. Bonavia 

 Chairman of the Board and 

 Principal Executive Officer 

Date: February 27, 2012 /s/ Kevin P. Larson 

 Kevin P. Larson 

 Principal Financial Officer and Director 

Date: February 27, 2012 /s/ Karen G. Kissinger* 

 Karen G. Kissinger 

 Principal Accounting Officer 

Date: February 27, 2012 /s/ Michael J. DeConcini* 

 Michael J. DeConcini 

 Director 

Date: February 27, 2012 /s/ David G. Hutchens* 

 David G. Hutchens 

 Director 

Date: February 27, 2012 By: /s/ Kevin P. Larson 

 Kevin P. Larson 

 As attorney-in-fact for each of the persons indicated 
Table of Contents 

EXHIBIT INDEX 

 

 

K-162 

*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, File No. 1-5924-Exhibit No 3(a)). 

*3(a)(1) 

 

—

 

TEP Articles of Amendment filed with the ACC on September 3, 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. (Form 8-A/A, dated January 30, 1998, File 

No. 1-13739 – Exhibit 2(a)). 

*3(d) 

 

—

 

Revised and restated bylaws of UniSource Energy, as revised and restated December 14, 2011 (Form 8-K, 

dated December 15, 2011, File No. 13739 – Exhibit 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)). 
Table of Contents 

 

K-163 

*4(c)(4) 

 

—

 

First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and 

Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power

Company Projects). (Form S-4, Registration No. 33-52860 — Exhibit 4(i)(4)). 

*4(d)(1) 

 

—

 

Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to 

Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power 

Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4

(I)(1)). 

*4(d)(2) 

 

—

 

Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty 

authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson 

Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File no. 1-

5924 — Exhibit 4(I)(2)). 

*4(d)(3) 

 

—

 

First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and 

TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson 

Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-

5924 — Exhibit 4(k)(3)). 

*4(d)(4) 

 

—

 

First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan 

Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A 

(Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File 

No. 1-5924 — Exhibit 4(k)(4)). 

*4(d)(5) 

 

—

 

Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and 

TEP relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company 

Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(k)(5)). 

*4(d)(6) 

 

—

 

Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and 

Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power

Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(k)(6)). 

*4(e)(1) 

 

—

 

Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to 

Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company 

Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — Exhibit 4(m)(1)). 

*4(e)(2) 

 

—

 

Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty 

authorizing Variable Rate Demand Industrial Development Revenue Bonds. 1983 Series B (Tucson Electric 

Power Company Springerville Project). (Form 10-K for the year ended December 31, 1983, File No. 1-5924 — 

Exhibit 4(m)(2)). 

*4(e)(3) 

 

—

 

First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and 

TEP relating to Floating Rate Monthly Demand Industrial Developmental Revenue Bonds, 1983 Series B (Tucson 

Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-

5924 — Exhibit 4(I)(3)). 

*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)). 
Table of Contents 

 

K-164 

*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)). 
Table of Contents 

 

K-165 

*4(h)(3) 

 

—

 

First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and

TEP relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company 

Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(o)(3)). 

*4(h)(4) 

 

—

 

First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and 

Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power

Company Springerville Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(o)(4)). 

*4(i)(1) 

 

—

 

Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, 

Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 4(r)(1)). 

*4(i)(2) 

 

—

 

Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series 

A, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732 — Exhibit 4(r)(2)). 

*4(i)(3) 

 

—

 

Supplemental Indenture No. 2 creating a series of bonds designated Second Mortgage Bonds, Collateral Series 

B, dated as of December 1, 1997. (Form 10-K for year ended December 31, 1997, File No. 1-5924 — Exhibit 4

(m)(3)). 

*4(i)(4) 

 

—

 

Supplemental Indenture No. 3 creating a series of bonds designated Second Mortgage Bonds, Collateral Series, 

dated as of August 1, 1998. (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 — Exhibit 4(c)). 

*4(i)(5) 

 

—

 

Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series 

C, dated as of November 1, 2002. (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 — 

Exhibit 99.2). 

*4(i)(6) 

 

—

 

Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series 

D, dated as of March 1, 2004. (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 — Exhibit 10 

(b)). 

*4(i)(7) 

 

—

 

Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series 

E, dated as of May 1, 2005. (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 – 

Exhibit 4(b)). 

*4(i)(8) 

 

—

 

Supplemental Indenture No. 7 creating a series of bonds designated First Mortgage Bonds, Collateral Series F, 

dated as of December 1, 2006. (Form 8-K dated December 22, 2006, File Nos. 1-5924 and 1-13739 – Exhibit 

4.1). 

*4(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. (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)). 
Table of Contents 

 

K-166 

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) 

 

—

 

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(l)(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(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 B (Tucson Electric Power Company 

Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 — Exhibit 4(c)). 

*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 B (Tucson Electric Power Company Project). (Form 10-Q for the quarter ended March 31, 1998, File No. 

1-5924 — Exhibit 4(d)). 

*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 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(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 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(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. (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. 
Table of Contents 

 

K-167 

*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). 

*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(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(r)(1) 

 

—

 

Indenture dated as of March 1, 2005, to The Bank of New York, as Trustee. (Form 8-K dated March 3, 2005, File 

Nos. 1-5924 and 1-13739 — Exhibit 4.1). 

*4(s)(1) 

 

—

 

Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UniSource 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 4.1). 

4(s)(2) 

 

—

 

Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among 

UniSource Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. 

*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. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.4). 

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(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(v)(1) 

 

—

 

Second Amended and Restated Pledge Agreement, dated as of November 9, 2010, among UniSource 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(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(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(x)(1) 

 

—

 

Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of 

Pima and U.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)). 
Table of Contents 

 

K-168 

*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(x)(3) 

 

—

 

Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control 

Corporation and U.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(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(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(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 (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 CoTrustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(5)). 
Table of Contents 

 

K-169 

*10(a)(6) 

 

—

 

Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia 

and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee.

(Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(6)). 

*10(a)(7) 

 

—

 

Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between 

Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as CoTrustee. (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 CoTrustee 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)). 
Table of Contents 

 

K-170 

*10(a)(16) 

 

—

 

Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984,

between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United 

States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of 

America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year 

ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(12)). 

*10(a)(17) 

 

—

 

Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984,

between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States 

Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as

Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended 

December 31, 1986, File No. 1-5924 — Exhibit 10(e)(13)). 

*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)). 
Table of Contents 

 

K-171 

*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 CoTrustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coalhandling 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)). 
Table of Contents 

 

K-172 

*10(b)(8) 

 

—

 

Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, 

between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. 

Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital 

Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — 

Exhibit 10(b)(8)). 

*10(b)(9) 

 

—

 

Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, 

between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. 

Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing

Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — 

Exhibit 10(b)(9)). 

*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)). 
Table of Contents 

 

K-173 

*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)). 

*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(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(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(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(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(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). 
Table of Contents 

 

K-174 

*10(d) 

 

—

 

Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, 

Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle 

National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 

33-55732 — Exhibit 10(u)). 

*10(e) 

 

—

 

Lease Agreement, dated as of December 15, 1992, between TEP, as Lessee, and Wilmington Trust Company 

and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 

33-55732 — Exhibit 10(v)). 

*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). 

+*10(i) 

 

—

 

Management and Directors Deferred Compensation Plan of UniSource Energy. (Form S-8 dated January 6, 

1998, File No. 333-43769). 

+*10(j) 

 

—

 

TEP Supplemental Retirement Account for Classified Employees. (Form S-8 dated May 21, 1998, File No. 333-

53309). 

+*10(k) — TEP Triple Investment Plan for Salaried Employees. (Form S-8 dated May 21, 1998, File No. 333-53333). 

+*10(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)). 

+*10(n) 

 

—

 

Amended and Restated UniSource Energy 1994 Outside Director Stock Option Plan of UniSource Energy. (Form 

S-8 dated September 9, 2002, File No. 333-99317). 

*10(o) 

 

—

 

Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens 

Communications Company relating to the Purchase of Citizens’ Electric Utility Business in the State of Arizona. 

(Form 8-K dated October 31, 2002, File No. 1-13739 — Exhibit 99-1). 

+*10(p) 

 

—

 

UniSource Energy 2006 Omnibus Stock and Incentive Plan. (Form S-8 dated January 31, 2007, File No. 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)). 

+*10(r) 

 

—

 

Management and Directors Deferred Compensation Plan II of UniSource Energy. (Form S-8 dated December 30, 

2008, File No. 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). 

 

+*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) 

 

—

 

Employment Agreement, dated May 4, 2009, between UniSource Energy and Paul J. Bonavia. (Form 10-Q for 

the quarter ended March 31, 2009, File No. 13739 – Exhibit 4). 

+*10(v) 

 

—

 

UniSource Energy Corporation 2011 Omnibus Stock and Incentive Plan. (Form 8-K dated May 10, 2011, File 1-

13739 – Exhibit 10.1). 
Table of Contents 

 

 

 

 

 

 

 

K-175 

12(a) — Computation of Ratio of Earnings to Fixed Charges – UniSource Energy. 

12(b) — Computation of Ratio of Earnings to Fixed Charges – TEP. 

21 — Subsidiaries of the Registrants. 

23(a) — Consent of Independent Registered Public Accounting Firm – UniSource Energy. 

23(b) — Consent of Independent Registered Public Accounting Firm – TEP. 

24(a) — Power of Attorney – UniSource Energy. 

24(b) — Power of Attorney – TEP. 

31(a) — Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UniSource Energy, by Paul J. Bonavia. 

31(b) — Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UniSource Energy, by Kevin P. Larson. 

31(c) — Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by 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 UniSource Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended 

December 31, 2011, formatted in XBRL (Extensible Business Reporting Language): 

(a) UniSource Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Cash Flows, 

(iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Capitalization, (v) Consolidated Statements of Changes in 

Stockholders’ Equity and Comprehensive Income; and 

(b) Notes to Consolidated Financial Statements. 

# These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T. 

(*) 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. 
Exhibit 4(e)(7) 

THIRD SUPPLEMENTAL INDENTURE OF TRUST 

THIS THIRD SUPPLEMENTAL INDENTURE OF TRUST, dated December 7, 2011 (this “Third Supplemental Indenture”), 

between THE INDUSTRIAL DEVELOPMENT AUTHORITY OF THE COUNTY OF APACHE, a political subdivision of the State of Arizona 

created and existing under and by virtue of the Constitution and laws of the State of Arizona (hereinafter called the “Authority”), and U.S. Bank 

Trust National Association, a national banking association, as successor trustee (hereinafter called the “Trustee”), being an amendment and 

supplement to the Indenture of Trust, dated as of December 1, 1983, as heretofore supplemented (the “Indenture”), between the Authority and 

the Trustee pursuant to which the Authority issued The Industrial Development Authority of the County of Apache Industrial Development 

Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project) (the “Bonds”). 

W I T N E S S E T H: 

WHEREAS, the Authority is authorized and empowered under Title 35, Chapter 5, Arizona Revised Statutes, as amended (the 

“Act”), to issue its bonds in accordance with the Act and to make secured or unsecured loans for the purpose of financing or refinancing the 

acquisition, construction, improvement or equipping of projects consisting of land, any building or other improvement, and all real and personal 

properties, including but not limited to machinery and equipment, whether or not now in existence or under construction, whether located within 

or without Apache County, which shall be suitable for, among other things, facilities for the furnishing of electric energy, gas or water, air and 

water pollution control facilities and sewage and solid waste disposal facilities, and to charge and collect interest on such loans and pledge the 

proceeds of loan agreements as security for the payment of the principal of and interest on bonds, or designated issues of bonds, issued by the 

Authority; and 

WHEREAS, the Authority has entered into a Loan Agreement, dated as of December 1, 1983, as heretofore supplemented (the “Loan 

Agreement”), with Tucson Electric Power Company, an Arizona corporation (the “Company”); and 

WHEREAS, pursuant to the Indenture, the Authority has heretofore issued and sold the Bonds for the purpose of financing the 

Company’s share of the costs of the acquisition, construction, improvement and equipping of certain facilities, including facilities relating to the 

Company’s Springerville Generating Station located in Apache County, Arizona as more fully described in Exhibit A to the Loan Agreement; 

and 

WHEREAS, the Authority has been requested by the Company to amend and supplement the Indenture as hereinafter set forth in 

order to provide for cancellation of the Letter of Credit at any time all of the Outstanding Bonds are Company Bonds registered in the name of 

the Company; and 

WHEREAS, pursuant to Section 12.03 of the Indenture, the Authority has requested that the Trustee enter into this Third 

Supplemental Indenture; and 

WHEREAS, pursuant to Section 12.05 of the Indenture, the Company and the Bank have consented to this Third Supplemental 

Indenture; and 
WHEREAS, there has been delivered to the Authority and the Trustee a Approving Opinion of Bond Counsel stating that the 

amendments set forth in this Third Supplemental Indenture are authorized or permitted by the Act and comply with terms of the Act, are 

authorized or permitted by the Indenture and comply with the terms of the Indenture, will, upon the execution and delivery hereof, be valid and 

binding upon the Authority in accordance with the terms hereof and will not adversely affect the exemption from federal income taxation of 

interest on the Bonds. 

NOW, THEREFORE, for and in consideration of these premises and the mutual covenants herein contained and the sum of one 

dollar lawful money of the United States of America, to the Authority duly paid by the Trustee at or before the execution and delivery of these 

presents, and for other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, the parties hereto 

covenant and agree as follows: 

Section 1. Definitions . Unless otherwise specifically provided herein to the contrary, the capitalized terms in this Third 

Supplemental Indenture, including, without limitation, the capitalized terms set forth in the Recitals hereto, shall have the meanings provided for 

such terms in the Indenture. 

Section 2. Amendment of Subsection 4.05(b) . Subsection 4.05(b) of the Indenture is hereby amended by addition of the following 

sentence at the end thereof; 

If at any time all of the Bonds Outstanding shall be Company Bonds registered in the name of the Company and an Authorized 

Company Representative shall have so directed the Trustee, the entity acting as Trustee and Agent shall promptly surrender any 

Letter of Credit then in effect to the Bank for cancellation. 

Section 3. Counterparts . This Third Supplemental Indenture may be executed in any number of counterparts, each of which, when

executed and delivered, shall be an original; but such counterparts shall together constitute but one and the same instrument. 

Section 4. Effective Date . The amendments set forth in this Third Supplemental Indenture shall be deemed to be effective as of the 

date that: (i) all Outstanding Bonds are registered in the name of the Company, as evidenced by a certificate of the Registrar delivered to the 

Authority and (ii) the Company, as Owner of all Outstanding Bonds and as authorized by Section 13.05 of the Indenture, delivers its written 

consent to this Third Supplemental Indenture pursuant to Section 12.03 of the Indenture, such written consent to be delivered to the Authority 

and the Trustee. 

Section 5. Provisions of Indenture Not Otherwise Modified . Except as specifically amended by this Third Supplemental 

Indenture, the Indenture is hereby ratified, approved and confirmed and remains in full force and effect. 

 

2 
IN WITNESS WHEREOF, The Industrial Development Authority of the County of Apache has caused this Third Supplemental 

Indenture to be executed by its President, and U.S. Bank Trust National Association has caused this Third Supplemental Indenture to be 

executed on its behalf by one of its Vice Presidents, all as of the day and year first above written. 

 

 

Signature Page to Third Supplemental Indenture of Trust 

 

THE INDUSTRIAL DEVELOPMENT 

AUTHORITY OF THE COUNTY OF APACHE 

 By: /s/ John Lang, President 

 Title: Authorized Officer 

 

U.S. BANK TRUST NATIONAL 

ASSOCIATION, as TRUSTEE 

 By: /s/ Patrick Crowley 

 Title: Vice President 
Exhibit 4(f)(7) 

THIRD SUPPLEMENTAL INDENTURE OF TRUST 

THIS THIRD SUPPLEMENTAL INDENTURE OF TRUST, dated December 7, 2011 (this “Third Supplemental Indenture”), 

between THE INDUSTRIAL DEVELOPMENT AUTHORITY OF THE COUNTY OF APACHE, a political subdivision of the State of Arizona 

created and existing under and by virtue of the Constitution and laws of the State of Arizona (hereinafter called the “Authority”), and U.S. Bank 

Trust National Association, a national banking association, as successor trustee (hereinafter called the “Trustee”), being an amendment and 

supplement to the Indenture of Trust, dated as of December 1, 1983, as heretofore supplemented (the “Indenture”), between the Authority and 

the Trustee pursuant to which the Authority issued The Industrial Development Authority of the County of Apache Industrial Development 

Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project) (the “Bonds”). 

W I T N E S S E T H: 

WHEREAS, the Authority is authorized and empowered under Title 35, Chapter 5, Arizona Revised Statutes, as amended (the 

“Act”), to issue its bonds in accordance with the Act and to make secured or unsecured loans for the purpose of financing or refinancing the 

acquisition, construction, improvement or equipping of projects consisting of land, any building or other improvement, and all real and personal 

properties, including but not limited to machinery and equipment, whether or not now in existence or under construction, whether located within 

or without Apache County, which shall be suitable for, among other things, facilities for the furnishing of electric energy, gas or water, air and 

water pollution control facilities and sewage and solid waste disposal facilities, and to charge and collect interest on such loans and pledge the 

proceeds of loan agreements as security for the payment of the principal of and interest on bonds, or designated issues of bonds, issued by the 

Authority; and 

WHEREAS, the Authority has entered into a Loan Agreement, dated as of December 1, 1983, as heretofore supplemented (the “Loan 

Agreement”), with Tucson Electric Power Company, an Arizona corporation (the “Company”); and 

WHEREAS, pursuant to the Indenture, the Authority has heretofore issued and sold the Bonds for the purpose of financing the 

Company’s share of the costs of the acquisition, construction, improvement and equipping of certain facilities, including facilities relating to the 

Company’s Springerville Generating Station located in Apache County, Arizona as more fully described in Exhibit A to the Loan Agreement; 

and 

WHEREAS, the Authority has been requested by the Company to amend and supplement the Indenture as hereinafter set forth in 

order to provide for cancellation of the Letter of Credit at any time all of the Outstanding Bonds are Company Bonds registered in the name of 

the Company; and 

WHEREAS, pursuant to Section 12.03 of the Indenture, the Authority has requested that the Trustee enter into this Third 

Supplemental Indenture; and 

WHEREAS, pursuant to Section 12.05 of the Indenture, the Company and the Bank have consented to this Third Supplemental 

Indenture; and 
WHEREAS, there has been delivered to the Authority and the Trustee a Approving Opinion of Bond Counsel stating that the 

amendments set forth in this Third Supplemental Indenture are authorized or permitted by the Act and comply with terms of the Act, are 

authorized or permitted by the Indenture and comply with the terms of the Indenture, will, upon the execution and delivery hereof, be valid and 

binding upon the Authority in accordance with the terms hereof and will not adversely affect the exemption from federal income taxation of 

interest on the Bonds. 

NOW, THEREFORE, for and in consideration of these premises and the mutual covenants herein contained and the sum of one 

dollar lawful money of the United States of America, to the Authority duly paid by the Trustee at or before the execution and delivery of these 

presents, and for other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, the parties hereto 

covenant and agree as follows: 

Section 1. Definitions . Unless otherwise specifically provided herein to the contrary, the capitalized terms in this Third 

Supplemental Indenture, including, without limitation, the capitalized terms set forth in the Recitals hereto, shall have the meanings provided for 

such terms in the Indenture. 

Section 2. Amendment of Subsection 4.05(b) . Subsection 4.05(b) of the Indenture is hereby amended by addition of the following 

sentence at the end thereof; 

If at any time all of the Bonds Outstanding shall be Company Bonds registered in the name of the Company and an Authorized 

Company Representative shall have so directed the Trustee, the entity acting as Trustee and Agent shall promptly surrender any Letter of Credit 

then in effect to the Bank for cancellation. 

Section 3. Counterparts . This Third Supplemental Indenture may be executed in any number of counterparts, each of which, when

executed and delivered, shall be an original; but such counterparts shall together constitute but one and the same instrument. 

Section 4. Effective Date . The amendments set forth in this Third Supplemental Indenture shall be deemed to be effective as of the 

date that: (i) all Outstanding Bonds are registered in the name of the Company, as evidenced by a certificate of the Registrar delivered to the 

Authority and (ii) the Company, as Owner of all Outstanding Bonds and as authorized by Section 13.05 of the Indenture, delivers its written 

consent to this Third Supplemental Indenture pursuant to Section 12.03 of the Indenture, such written consent to be delivered to the Authority 

and the Trustee. 

Section 5. Provisions of Indenture Not Otherwise Modified . Except as specifically amended by this Third Supplemental 

Indenture, the Indenture is hereby ratified, approved and confirmed and remains in full force and effect. 
IN WITNESS WHEREOF, The Industrial Development Authority of the County of Apache has caused this Third Supplemental Indenture 

to be executed by its President, and U.S. Bank Trust National Association has caused this Third Supplemental Indenture to be executed on its 

behalf by one of its Vice Presidents, all as of the day and year first above written. 

 

 

Signature Page to Third Supplemental Indenture of Trust 

 

THE INDUSTRIAL DEVELOPMENT 

AUTHORITY OF THE COUNTY OF APACHE 

 By: /s/ John Lang, President 

 Title: Authorized Officer 

 

U.S. BANK TRUST NATIONAL 

ASSOCIATION, as TRUSTEE 

 By: /s/ Patrick Crowley 

 Title: Vice President 
Exhibit 4(i)(14) 

Supplemental Indenture No. 13 

 

TUCSON ELECTRIC POWER COMPANY 

to 

THE BANK OF NEW YORK MELLON, 

Trustee 

 

Dated as of November 1, 2011 

Supplemental to Indenture of Mortgage and Deed of Trust, 

dated as of December 1, 1992 

 

Amending Terms of Bonds Designated 

First Mortgage Bonds, Collateral Series I 

This instrument constitutes a mortgage, a deed of trust and a security agreement. 
SUPPLEMENTAL INDENTURE NO. 13 , dated as of November 1, 2011, between T UCSON E LECTRIC P OWER C OMPANY 

(hereinafter sometimes called the “Company”), a corporation organized and existing under the laws of the State of Arizona, having its principal 

office at One South Church Avenue, in the City of Tucson, Arizona, as trustor, and T HE B ANK OF N EW Y ORK M ELLON , formerly known as The 

Bank of New York (successor in trust to Bank of Montreal Trust Company), a banking corporation organized and existing under the laws of the 

State of New York and having its principal office at 101 Barclay Street, in the Borough of Manhattan, The City of New York, New York, as 

trustee (hereinafter sometimes called the “Trustee”), under the Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, between 

the Company and the Trustee (hereinafter called the “Original Indenture”), as heretofore amended and supplemented, this Supplemental 

Indenture No. 13 being supplemental thereto (the Original Indenture as heretofore amended and supplemented, and as supplemented hereby, and 

as it may from time to time be further supplemented, modified, altered or amended by any supplemental indenture entered into in accordance 

with and pursuant to the provisions thereof, is hereinafter called the “Indenture”). 

R ECITALS OF THE C OMPANY 

WHEREAS, on November 9, 2010, the Company issued a series of Bonds designated “First Mortgage Bonds, Collateral Series I”

limited in aggregate principal amount (except as contemplated in clause (b) of Section 2 of Article II of the Original Indenture) to $540,588,000, 

such series of Bonds and such Bonds to be hereinafter sometimes called, respectively, “Series 10” and “Series 10 Bonds”; and 

WHEREAS, all terms of Series 10 Bonds have been established in a Supplemental Indenture No. 11, dated as of November 1, 2010 

(the “Supplemental Indenture No. 11”); and 

WHEREAS, the Holder of all Series 10 Bonds is Union Bank, N.A., in its capacity as Administrative Agent under the Second 

Amended and Restated Credit Agreement, dated as of November 9, 2010, among the Company, the Lenders party thereto, the Issuing Banks 

party thereto, the Co-Syndication Agents party thereto, the Co-Documentation Agents party thereto and the Administrative Agent, as amended, 

amended and restated, supplemented or otherwise modified from time to time (the “Credit Agreement”); and 

WHEREAS, the Company is amending the Credit Agreement to, among other things, extend the term thereof, and desires to amend 

the Series 10 Bonds to extend their stated maturity; and 

WHEREAS, Section 2 of Article XIII of the Indenture provides that with the consent of the Holder of each Outstanding Bond 

directly affected, the Company and the Trustee may enter into an indenture supplemental to the Indenture for the purpose of adding any 

provisions to, or changing in any manner or eliminating any of the provisions of the Indenture, including, but not limited to, changing the stated 

maturity of the principal of any such Bond; and 

WHEREAS, the Administrative Agent, as Holder of all Series 10 Bonds, has consented to all changes described in this Supplemental 

Indenture No. 13; and 

 

2 
WHEREAS, as provided in Article II, Section 6 of the Indenture, upon surrender for exchange of the existing Series 10 Bonds by the 

Administrative Agent, the Company shall execute, the Trustee shall authenticate, and the Company shall deliver to the Administrative Agent 

replacement Series 10 Bonds in substitution and exchange for (but not payment of) the surrendered Series 10 Bonds, and the Trustee shall cancel 

the surrendered Series 10 Bonds and deliver proof of cancellation to the Company; and 

WHEREAS, effective June 3, 1999, The Bank of New York succeeded to all of the corporate trust business of Bank of Montreal 

Trust Company, and, as a consequence, The Bank of New York, being otherwise qualified and eligible under Article XII of the Original 

Indenture, became the successor trustee under the Indenture without further act on the part of the parties thereto, as contemplated by Section 11 

of Article XII of the Original Indenture; and 

WHEREAS, effective July 1, 2008, The Bank of New York changed its name to The Bank of New York Mellon. 

ARTICLE I 

A DDITIONAL D EFINITIONS 

 

For all purposes of this Supplemental Indenture No. 13, except as otherwise expressly provided or unless the context otherwise 

requires, the terms defined herein shall have the meanings herein specified and include the plural as well as the singular. All terms that are not 

defined herein but are defined in the Supplemental Indenture No. 11 or in the Indenture shall have the meanings set forth in the Supplemental 

Indenture No. 11 or in the Indenture, respectively. 

ARTICLE II 

A MENDMENT OF T ERMS OF S ERIES 10 B ONDS 

This Supplemental Indenture No. 13 is being delivered to effect the following changes to the Supplemental Indenture No. 11 and the 

Series 10 Bonds: 

 

 

 

 

2 

 Section 1. Applicability of Article . 

 1. clause (d) of Article II of the Supplemental Indenture No. 11 is hereby amended to read as follows: 

 “(d) the Series 10 Bonds shall mature on December 9, 2016;”; and 

 2. the form of Series 10 Bonds is hereby amended to read as set forth in Exhibit A attached hereto. 
ARTICLE III 

M ISCELLANEOUS P ROVISIONS 

This Supplemental Indenture No. 13 is a supplement to the Original Indenture. As heretofore supplemented and further supplemented 

by this Supplemental Indenture No. 13, the Original Indenture is in all respects ratified, approved and confirmed, and the Original Indenture as 

heretofore supplemented and this Supplemental Indenture No. 13 shall together constitute one and the same instrument. 

Upon the effectiveness of this Supplemental Indenture No. 13, each reference in the Supplemental Indenture No. 11 to “this 

Supplemental Indenture No. 11”, “hereunder”, “hereof”, “herein” or words of like import referring to the Supplemental Indenture No. 11 shall 

mean and be a reference to the Supplemental Indenture No. 11, as amended by this Supplemental Indenture No. 13. Except as specifically 

amended above, the Supplemental Indenture No. 11 shall continue to be in full force and effect and is hereby in all respects ratified, approved 

and confirmed. 

The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture No. 13. The statements and 

recitals herein are deemed to be those of the Company and not of the Trustee. 

 

4 
IN WITNESS WHEREOF, Tucson Electric Power Company has caused its corporate name to be hereunto affixed, and this 

instrument to be signed by one of its Vice Presidents, and its corporate seal to be hereunto affixed and attested by its Secretary or one of its 

Assistant Secretaries for and on its behalf; and The Bank of New York Mellon, as trustee, in evidence of its acceptance of the trust hereby 

created, has caused its corporate name to be hereunto affixed, and this instrument to be signed by one of its authorized signatories and its 

corporate seal to be hereunto affixed and attested by one of its authorized signatories, for and on its behalf, all as of the day and year first above 

written. 

 

 

[SEAL] 

 

5 

 T UCSON E LECTRIC P OWER C OMPANY 

 By /s/ Kentton C. Grant 

 Kentton C. Grant 

 Vice President and Treasurer 

Attest: 

/s/ Linda H. Kennedy 

Linda H. Kennedy 

Secretary 
 

 

[SEAL] 

 

6 

 

T HE B ANK OF N EW Y ORK M ELLON , 

Trustee 

 By /s/ Francine Kincaid 

 Authorized Signatory 

Attest: 

/s/ Scott Klein 

Authorized Signatory 
S TATE OF A RIZONA ) 

) ss.: 

C OUNTY OF P IMA ) 

This instrument was acknowledged before me this 17th day of November, 2011 by Kentton C. Grant, as Vice President and 

Treasurer, and Linda H. Kennedy, as Secretary, of T UCSON E LECTRIC P OWER C OMPANY , an Arizona corporation, known to me to be the 

individuals who executed this instrument, and known to me to be a Vice President and Treasurer and the Secretary, respectively, of said 

corporation, and who personally acknowledged before me and stated that they executed said instrument on behalf of said corporation for the 

purposes and consideration therein expressed. 

 

 

 

7 

/s/ Aniza Ortiz 

N OTARY P UBLIC 

 Aniza Ortiz 

Notary Public – Arizona 

 Pima County 

My Commission Expires 

 May 26, 2014 
S TATE OF N EW Y ORK ) 

) ss.: 

C OUNTY OF N EW Y ORK ) 

This instrument was acknowledged before me this 16th day of November, 2011 by Francine Kincaid, as Authorized Signatory, and 

Scott Klein, as Authorized Signatory, of T HE B ANK OF N EW Y ORK M ELLON , a New York banking corporation, known to me to be the 

individuals who executed this instrument, and known to me to be Authorized Signatories of said corporation, and who personally acknowledged 

before me and stated that they executed said instrument on behalf of said corporation for the purposes and consideration therein expressed. 

 

 

 

8 

/s/ Joann Labarbera 

N OTARY P UBLIC 

 Joann Labarbera 

Notary Public, State of New York 

 No. 01LA5023752 

 Qualified in New York County 

Commission Expires June 8, 2014 
Exhibit A 

[Form of Bond] 

This bond is non-transferable, 

except to a successor Administrative Agent under the 

Credit Agreement referred to herein. 

 

TUCSON ELECTRIC POWER COMPANY 

FIRST MORTGAGE BOND, COLLATERAL SERIES I 

DUE DECEMBER 9, 2016 

TUCSON ELECTRIC POWER COMPANY, a corporation of the State of Arizona (hereinafter sometimes called the “Company”), 

for value received, promises to pay to as Administrative Agent under the Credit Agreement hereinafter referred to or registered assigns, the 

principal sum of 

DOLLARS 

on December 9, 2016 in coin or currency of the United States of America which at the time of payment shall be legal tender for the payment of 

public and private debts, at the office or agency of the Company in The City of New York, or in the City of Tucson, Arizona, upon presentation 

hereof, and quarterly, on the last Business Day (as defined in Supplemental Indenture No. 11 hereinafter referred to) of March, June, September 

and December in each year, commencing December 31, 2010 (each an “Interest Payment Date”), and at Maturity (as defined in Supplemental 

Indenture No. 11 hereinafter referred to), to pay interest thereon in like coin or currency at the rate specified below, from the Interest Payment 

Date next preceding the date of this bond (unless this bond be dated on an Interest Payment Date, in which case from the date hereof; or unless 

this bond be dated prior to the first Interest Payment Date, in which case from and including the date of the first authentication and delivery of 

the bonds of this series), until the Company’s obligation with respect to such principal sum shall be discharged. 

During the period from and including the date of the first authentication and delivery of the bonds of this series (which date was 

November 9, 2010) to and including the day next preceding the first Interest Payment Date, the bonds of this series shall bear interest at the rate 

of eight per centum (8%) per annum; thereafter, the bonds of this series shall bear interest at a rate equal to the Alternate Base Rate (as defined in 

Supplemental Indenture No. 11 hereinafter referred to) from time to time in effect plus 500 basis points. Interest on the bonds of this series 

during any period for which payment is made shall be computed in accordance with the Credit Agreement. 

 

A-1 

No. $ 
This bond is one of an issue of bonds of the Company, issued and to be issued in one or more series under and equally and ratably secured 

(except as any sinking, amortization, improvement, renewal or other fund, established in accordance with the provisions of the indenture 

hereinafter mentioned, may afford additional security for the bonds of any particular series) by the Indenture of Mortgage and Deed of Trust, 

dated as of December 1, 1992 (the “Original Indenture”), from the Company to The Bank of New York Mellon, formerly known as The Bank of 

New York (successor in trust to Bank of Montreal Trust Company), as trustee (the “Trustee”), as supplemented by thirteen supplemental 

indentures including Supplemental Indenture No. 11, dated as of November 1, 2010, establishing the bonds of this series, as amended by 

Supplemental Indenture No. 13, dated as of November 1, 2011 (the Original Indenture, as so supplemented, and such Supplemental Indenture 

No. 11, as so amended, being hereinafter called the “Indenture” and “Supplemental Indenture No. 11”, respectively), to which Indenture 

reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security provided by the 

Indenture, the rights and limitations of rights of the Company, the Trustee and the holders of said bonds with respect to the security provided by 

the Indenture, the powers, duties and immunities of the Trustee, the terms and conditions upon which such bonds are and are to be secured, and 

the circumstances under which additional bonds may be issued. The acceptance of this bond shall be deemed to constitute the consent and 

agreement by the holder hereof to all of the terms and provisions of the Indenture. This bond is one of a series of bonds designated as the First 

Mortgage Bonds, Collateral Series I, of the Company. 

The Indenture permits, with certain exceptions as therein provided, the Trustee to enter into one or more supplemental indentures for the 

purpose of adding any provisions to, or changing in any manner or eliminating any of the provisions of, the Indenture with the consent of the 

holders of not less than sixty per centum (60%) in aggregate principal amount of the bonds of all series then outstanding under the Indenture, 

considered as one class; provided, however, that if there shall be bonds of more than one series outstanding under the Indenture and if a proposed 

supplemental indenture shall directly affect the rights of the holders of bonds of one or more, but less than all, of such series, then the consent 

only of the holders of bonds in aggregate principal amount of the outstanding bonds of all series so directly affected, considered as one class, 

shall be required; and provided, further, that if the bonds of any series shall have been issued in more than one tranche and if the proposed 

supplemental indenture shall directly affect the rights of the holder of bonds of one or more, but less than all, of such tranches, then the consent 

only of the holders of bonds in aggregate principal amount of the outstanding bonds of all tranches so directly affected, considered as one class, 

shall be required; and provided, further, that the Indenture permits the Trustee to enter into one or more supplemental indentures for limited 

purposes without the consent of any holders of bonds. Any such consent by the holder of this bond shall be conclusive and binding upon such 

holder and upon all future holders of this bond and of any bond issued upon the registration of transfer hereof or in exchange therefor or in lieu 

hereof, whether or not notation of such consent is made upon this bond. 

The Company has issued and delivered the bonds of this series to Union Bank, N.A., as Administrative Agent (the “Administrative 

Agent”) under the Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among the Company, the Lenders party 

thereto, the Issuing Banks party thereto, the Co-Syndication Agents party thereto, the Co-Documentation Agents party thereto and Union Bank, 

N.A. (formerly known as Union Bank of 

 

A-2 
California, N.A.), as Administrative Agent, as amended, amended and restated, supplemented or otherwise modified from time to time (the 

“Credit Agreement”), in order to provide collateral security for the obligation of the Company thereunder to pay the Obligations (as defined in 

Supplemental Indenture No. 11). 

Upon the occurrence of an Event of Default under the Credit Agreement, and further upon such additional conditions as are set forth in 

subdivision (h) of Article II of Supplemental Indenture No. 11, then all bonds of this series shall be redeemed immediately at the principal 

amount thereof plus accrued interest to the date of redemption. 

The obligation of the Company to pay interest on the bonds of this series on any Interest Payment Date prior to Maturity (a) shall be 

deemed to have been satisfied and discharged in full in the event that all amounts then due in respect of the Obligations shall have been paid or 

(b) shall be deemed to remain unsatisfied in an amount equal to the aggregate amount then due in respect of the Obligations and remaining 

unpaid (not in excess, however, of the amount otherwise then due in respect of interest on the bonds of this series). 

The obligation of the Company to pay the principal of and accrued interest on the bonds of this series at or after Maturity (x) shall be 

deemed to have been satisfied and discharged in full in the event that all amounts then due in respect of the Obligations shall have been paid and 

no Letter of Credit (as defined in Supplemental Indenture No. 11) shall remain outstanding or (y) shall be deemed to remain unsatisfied in an 

amount equal to the aggregate amount then due in respect of the Obligations and remaining unpaid plus the aggregate stated amount of the 

outstanding Letters of Credit (not in excess, however, of the amount otherwise then due in respect of principal of and accrued interest on the 

bonds of this series). 

The principal of this bond and the interest accrued hereon may become or be declared due and payable before the stated maturity hereof, on 

the conditions, in the manner and at the times set forth in the Indenture, upon the happening of a default as therein provided. 

This bond is non-transferable except as required to effect transfer to any successor administrative agent under the Credit Agreement, any 

such transfer to be made at the office or agency of the Company in The City of New York, upon surrender and cancellation of this bond, and 

upon any such transfer a new bond of this series, for the same aggregate principal amount and having the same stated maturity date, will be 

issued to the transferee in exchange herefor. Prior to due presentment for registration of transfer, the Company and the Trustee may deem and 

treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payment and for all other 

purposes. This bond, alone or with other bonds of this series, may in like manner be exchanged at such office or agency for one or more bonds of 

this series of the same aggregate principal amount and having the same stated maturity date and interest rate, all as provided in the Indenture. 

No recourse shall be had for the payment of the principal of or interest on this bond, or for any claim based hereon or otherwise in respect 

hereof or of the Indenture, against any incorporator, shareholder, director or officer, as such, past, present or future, of the Company or of any 

predecessor or successor corporation, either directly or through the Company or any predecessor or successor corporation, whether by virtue of 

any constitution, statute or rule of 

 

A-3 
law, or by the enforcement of any assessment or penalty or by any legal or equitable proceeding or otherwise howsoever (including, without 

limiting the generality of the foregoing, any proceeding to enforce any claimed liability of shareholders of the Company, based upon any theory 

of disregarding the corporate entity of the Company or upon any theory that the Company was acting as the agent or instrumentality of the 

shareholders); all such liability being, by the acceptance hereof and as a part of the consideration for the issuance hereof, expressly waived and 

released by every holder hereof, and being likewise waived and released by the terms of the Indenture under which this bond is issued, as more 

fully provided in said Indenture. 

This bond shall not be valid or become obligatory for any purpose until the certificate of authentication hereon shall have been signed by 

The Bank of New York Mellon, or its successor, as Trustee under the Indenture. 

 

A-4 
I N W ITNESS W HEREOF , the Company has caused this bond to be signed in its name by the manual or facsimile signature of its President or 

one of its Vice Presidents, and its corporate seal, or a facsimile thereof, to be impressed or imprinted hereon and attested by the manual or 

facsimile signature of its Secretary or one of its Assistant Secretaries. 

Dated: , 20 

 

Attest: 

 

 

A-5 

 TUCSON ELECTRIC POWER COMPANY 

 By: 

 

 
[FORM OF TRUSTEE’S CERTIFICATE OF AUTHENTICATION] 

This is one of the bonds, of the series designated therein, described in the within-mentioned Indenture. 

Dated: , 20 

 

 

A-6 

 

The Bank of New York Mellon, 

 Trustee 

 By: 

 

 

 
Exhibit 4(o)(2) 

[Execution Version] 

AMENDMENT NO. 1 

TO 

CREDIT AGREEMENT 

This AMENDMENT NO. 1, dated as of November 18, 2011 (this “ Amendment ”), is made by and among TUCSON ELECTRIC POWER 

COMPANY, an Arizona corporation (the “ Borrower ”), the lenders listed on the signature pages of this Amendment as “Lenders” (such lenders, 

together with their respective permitted assignees from time to time, being referred to herein, collectively, as the “ Lenders ”), THE BANK OF 

NEW YORK MELLON, JPMORGAN CHASE BANK, N.A., WELLS FARGO BANK, NATIONAL ASSOCIATION, UNION BANK, N.A. 

and U.S. BANK NATIONAL ASSOCIATION, as issuing banks (collectively, in such capacities, the “ Issuing Banks ”), and UNION BANK, 

N.A. (formerly known as Union Bank of California, N.A.), as administrative agent (in such capacity, the “ Administrative Agent ”). 

PRELIMINARY STATEMENT: 

The Borrower, the Lenders, the Issuing Banks, JPMorgan Chase Bank, N.A., SunTrust Bank and Wells Fargo Bank, National Association, 

as Co-Syndication Agents, Bank of America, N.A. and U.S. Bank National Association, as Co-Documentation Agents, and the Administrative 

Agent previously entered into that certain Second Amended and Restated Credit Agreement, dated as of November 9, 2010 (the “ Existing 

Agreement ”, as amended by this Amendment, the “ Amended Agreement ”, and as the Amended Agreement may hereafter be amended, 

restated, supplemented or otherwise modified from time to time, the “ Credit Agreement ”). The Borrower desires to amend the Existing 

Agreement to (a) extend the Final Maturity Date to November 9, 2016, (b) reduce the Applicable Margin and the Commitment Fee Rate, and 

(c) make certain other modifications thereto, and the Lenders, the Issuing Banks and the Administrative Agent have agreed to such amendments 

on the terms and conditions set forth herein. The parties therefore agree as follows (capitalized terms used but not defined herein having the 

meanings assigned to such terms in the Existing Agreement): 

SECTION 1. Amendments to Existing Agreement. The Existing Agreement is, effective as of the date hereof and subject to the 

satisfaction of the conditions precedent set forth in Section 2 hereof, hereby amended as follows: 

(a) Bond Delivery Agreement . The definition of “ Bond Delivery Agreement ” contained in Section 1.01 of the Existing Agreement is 

hereby amended and restated in its entirety to read as follows: 

“ Bond Delivery Agreement ” means the Amended and Restated Bond Delivery Agreement, dated as of the Amendment No. 1 

Effective Date, between the Borrower and the Administrative Agent, substantially in the form of Exhibit F, executed and delivered 

pursuant to the terms of Amendment No. 1 in connection with the issuance of the Collateral Mortgage Bonds. 
(b) Collateral Mortgage Bonds . The definition of “ Collateral Mortgage Bonds ” contained in Section 1.01 of the Existing Agreement is 

hereby amended and restated in its entirety to read as follows: 

“ Collateral Mortgage Bonds ” means the First Mortgage Bonds, Collateral Series I, substantially in the form attached to the 

Thirteenth Supplemental Indenture. 

(c) Disclosure Documents . The definition of “ Disclosure Documents ” contained in Section 1.01 of the Existing Agreement is hereby 

amended and restated in its entirety to read as follows: 

“ Disclosure Documents ” means (i) the Annual Report on Form 10-K of the Borrower for the fiscal year ended December 31, 2010, 

as filed with the SEC, (ii) the Quarterly Reports on Form 10-Q of the Borrower for the fiscal quarters ended March 31, 2011, June 30, 2011 

and September 30, 2011, as filed with the SEC, and (iii) the Current Reports on Form 8-K of the Borrower as filed with the SEC on 

February 25, 2011 and May 11, 2011. 

(d) Final Maturity Date . The definition of “ Final Maturity Date ” contained in Section 1.01 of the Existing Agreement is hereby amended 

and restated in its entirety to read as follows: 

“ Final Maturity Date ” means November 9, 2016. 

(e) Security Documents . The definition of “ Security Documents ” contained in Section 1.01 of the Existing Agreement is hereby 

amended by deleting the phrase “the Eleventh Supplemental Indenture, the Collateral Mortgage Bonds and the Bond Delivery Agreement” in its 

entirety and substituting therefor the new phrase “the Eleventh Supplemental Indenture, the Thirteenth Supplemental Indenture, the Collateral 

Mortgage Bonds and the Bond Delivery Agreement”. 

(f) Transactions . The definition of “ Transactions ” contained in Section 1.01 of the Existing Agreement is hereby amended by deleting 

the phrase “under the Eleventh Supplemental Indenture” in its entirety and substituting therefor the new phrase “under the Thirteenth 

Supplemental Indenture”. 

(g) Additional Definitions . The following new definitions are hereby added to Section 1.01 of the Existing Agreement in appropriate 

alphabetical order: 

“ Amendment No. 1 ” means Amendment No. 1, dated as of November 18, 2011, among the Borrower, the Issuing Banks, the 

Lenders and the Administrative Agent, which Amendment No. 1 amended this Agreement pursuant to the terms thereof. 

“ Amendment No. 1 Effective Date ” means November 18, 2011. 

“ Thirteenth Supplemental Indenture ” means Supplemental Indenture No. 13 under the Mortgage Indenture, substantially in the form 

of Exhibit G. 

 

2 
(h) Letters of Credit . Section 2.04(a)(ii) of the Existing Agreement is hereby amended by deleting the last sentence thereof in its entirety 

and substituting therefor the following new sentence: “On the Amendment No. 1 Effective Date, upon the satisfaction (or waiver in accordance 

with Section 9.02) of the conditions precedent specified in Section 2 of Amendment No. 1, each of the Existing Revenue Bond Letters of Credit 

shall be amended by the applicable Issuing Bank to extend the stated expiration date thereof to November 2, 2016 (which date is five 

(5) Business Days prior to the Final Maturity Date).” 

(i) Financial Condition . Section 3.04(a) of the Existing Agreement is hereby amended by (i) deleting each reference to the date 

“December 31, 2009” in its entirety and substituting therefor in each case the new date “December 31, 2010” and (ii) deleting the phrase “to and 

including the Effective Date” in its entirety and substituting therefor the new phrase “to and including the Amendment No. 1 Effective Date”. 

(j) No Material Adverse Change . Section 3.04(b) of the Existing Agreement is hereby amended by deleting the phrase “since 

December 31, 2009” in its entirety and substituting therefor the new phrase “since December 31, 2010”. 

(k) Secured Indebtedness . Section 3.04(c) of the Existing Agreement is hereby amended by (i) deleting the phrase “As of the Effective 

Date” in its entirety and substituting therefor the new phrase “As of the Amendment No. 1 Effective Date” and (ii) deleting the amount 

“$540,588,000” in its entirety and substituting therefor the new amount “$577,741,000”. 

(l) Security Documents . Section 3.12(a) of the Existing Agreement is hereby amended by deleting the phrase “As of the Effective Date” 

in its entirety and substituting therefor the new phrase “As of the Amendment No. 1 Effective Date”. 

(m) Solvency . Section 3.14 of the Existing Agreement is hereby amended by deleting the phrase “On the Effective Date” in its entirety and 

substituting therefor the new phrase “On the Amendment No. 1 Effective Date”. 

(n) Pricing Schedule . Schedule 1.01 of the Existing Agreement is hereby replaced in its entirety with Schedule A attached hereto. 

(o) Commitment Schedule . Schedule 2.01 of the Existing Agreement is hereby replaced in its entirety with Schedule B attached hereto. 

(p) Additional Exhibits . Exhibit A hereto is hereby added as Exhibit F to the Existing Agreement. Exhibit B hereto is hereby added as 

Exhibit G to the Existing Agreement. 

SECTION 2. Conditions of Effectiveness . This Amendment shall become effective as of the date first written above (the “ Effective Date 

”) when, and only when, (a) the Administrative Agent shall have received all fees (including, without limitation, all upfront fees) payable by the 

Borrower pursuant to that certain proposal letter agreement, dated October 5, 2011, among Union Bank, the Borrower, UniSource Energy, UNS 

Gas and UNS Electric (the “ Proposal Letter ”), together with, to the extent invoiced, reimbursement or payment of all reasonable fees and outof-pocket disbursements of counsel to the Administrative Agent and other out-of-pocket 

 

3 
expenses of the Administrative Agent required to be reimbursed or paid by the Borrower pursuant to the Proposal Letter, (b) all requisite 

Governmental Authorities (including, without limitation, the ACC and all other regulatory authorities) and third parties shall have approved or 

consented to the execution, delivery and performance by the Borrower of this Amendment, the Amended Agreement, the other Loan Documents 

executed and delivered in connection herewith and the transactions contemplated hereby and thereby (collectively, the “ Transactions ”) to the 

extent required (and the Administrative Agent shall have received copies of all such approvals and consents, which shall be in form and 

substance satisfactory to the Administrative Agent and the Lenders, certified by an authorized officer of the Borrower as being true, correct and 

complete copies thereof and as being in full force and effect), no stay of any applicable regulatory approval shall have been issued and there shall 

be no litigation or governmental, administrative or judicial action, actual or threatened, that could reasonably be expected to restrain, prevent or 

impose burdensome conditions on this Amendment, the Amended Agreement, any of the other Loan Documents or the Transactions, and (c) the 

Administrative Agent shall have received: (i) counterparts of this Amendment executed by all of the parties hereto (in sufficient quantity for each 

party to have a fully executed original), and (ii) all of the following documents, each document being dated the Effective Date unless otherwise 

specified below, in form and substance satisfactory to the Administrative Agent and in the number of originals or photostatic copies reasonably 

requested by the Administrative Agent: 

(A) a favorable written opinion (addressed to the Administrative Agent, the Issuing Banks and the Lenders) of each of (1) Morgan, 

Lewis & Bockius LLP, New York counsel for the Borrower, (2) Todd C. Hixon, Esq., General Counsel for the Borrower, and (3) Rodey, 

Dickason, Sloan, Akin & Robb, PA, special New Mexico counsel for the Borrower, in each case covering such customary matters relating 

to this Amendment, the Amended Agreement, the other Loan Documents executed and delivered in connection herewith, the Mortgage 

Indenture, the Lien of the Mortgage Indenture and the Transactions as the Administrative Agent shall reasonably request, and the Borrower 

hereby requests such counsel to deliver such opinions; 

(B) counterparts of the Bond Delivery Agreement (as defined in the Amended Agreement) signed on behalf of the Borrower and any 

other parties thereto, together with (1) the Collateral Mortgage Bonds (as defined in the Amended Agreement) in an aggregate principal 

amount not less than $540,588,000 and reflecting a maturity date of December 9, 2016, duly issued and authenticated under the Mortgage 

Indenture (and (I) the Administrative Agent, the Issuing Banks and the Lenders hereby consent to the amendment and restatement of the 

existing Collateral Mortgage Bonds to reflect such maturity date and (II) in connection therewith, the Issuing Banks and the Lenders 

hereby authorize and direct the Administrative Agent to execute and deliver a Bondholder Consent substantially in the form of Exhibit C 

hereto) (such Collateral Mortgage Bonds being delivered in exchange for the Mortgage Bonds of the same series and amount held by the 

Administrative Agent which reflect a May 1, 2015 maturity date); (2) a duly executed copy of the Thirteenth Supplemental Indenture (as 

defined in the Amended Agreement) and all other documents, instruments and 

 

4 
filings relating to the issuance and authentication of the Collateral Mortgage Bonds (as defined in the Amended Agreement) under the 

Mortgage Indenture; (3) copies of any amendments or supplements, entered into at any time after November 9, 2010, to the Mortgage 

Indenture, the Revenue Bond Indentures, the Revenue Bond Loan Agreements and all related agreements with respect to the Revenue 

Bonds, certified by an authorized officer of the Borrower as being a true, correct and complete copy thereof and as being in full force and 

effect; (4) all documents, instruments and filings creating or perfecting the Lien of the Mortgage Indenture; and (5) all other documents 

and instruments required by law or reasonably requested by the Administrative Agent to be filed, registered or recorded to create or perfect 

the Liens intended to be created under the Security Documents; 

(C) such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, 

existence and good standing of the Borrower, the authorization of the Transactions and any other legal matters relating to the Borrower, 

this Amendment, the Amended Agreement, the other Loan Documents executed and delivered in connection herewith, the Mortgage 

Indenture, the Lien of the Mortgage Indenture or the Transactions, all in form and substance satisfactory to the Administrative Agent and 

its counsel; 

(D) a certificate (the statements in which shall be true), signed by an Authorized Officer, certifying that: 

(1) the representations and warranties of the Borrower set forth in this Amendment, the Amended Agreement and the other 

Loan Documents are true and correct on and as of the Effective Date with the same effect as though made on and as of such date, 

except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and 

warranties were true and correct as of such earlier date); 

(2) both before and after giving effect to this Amendment, no Default has occurred and is continuing; 

(3) the Borrower and its Subsidiaries do not have any indebtedness or preferred stock outstanding other than (x) the 

Obligations, (y) the Indebtedness described in the most recent financial statements of the Borrower and its Consolidated Subsidiaries 

referenced in Section 3.04(a) of the Amended Agreement and (z) $250 million of 5.15% Notes due November 15, 2021, issued by 

the Borrower on November 8, 2011; and 

(4) the Capital Stock of the Borrower (to the extent owned by UniSource Energy, which owns all Capital Stock of the 

Borrower) is free and clear of any Liens. 

 

5 
SECTION 3. Representations and Warranties of the Borrower . The Borrower represents and warrants to the Administrative Agent, the 

Lenders and the Issuing Banks that: 

(a) Authorization; Enforceability . The Transactions are within the Borrower’s organizational powers and have been duly authorized by all 

necessary corporate and, if required, stockholder action. This Amendment has been duly executed and delivered by the Borrower, and each of 

this Amendment and the Amended Agreement constitutes, and each other Loan Document to which the Borrower is a party required to be 

executed and delivered pursuant to the terms of this Amendment, when executed and delivered by the Borrower (and, in the case of the 

Collateral Mortgage Bonds (as defined in the Amended Agreement), authenticated by the trustee therefor), will constitute, a legal, valid and 

binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, subject to applicable bankruptcy, insolvency, 

reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether 

considered in a proceeding in equity or at law. 

(b) Governmental Approvals; No Conflicts . The Transactions (i) do not require any consent or approval of, registration or filing with, or 

any other action by, any Governmental Authority, except for (A) such approvals of the ACC that have been obtained and are in full force and 

effect and (B) filings necessary to perfect Liens created under the Loan Documents (all of which filings have been made), (ii) will not violate any 

Requirement of Law, (iii) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or 

any of its Consolidated Subsidiaries or its assets, or give rise to a right thereunder to require any payment to be made by the Borrower or any of 

its Consolidated Subsidiaries, and (iv) will not result in the creation or imposition of any Lien on any asset of the Borrower or any of its 

Consolidated Subsidiaries, except Liens created under the Loan Documents or under the Mortgage Indenture. 

(c) Litigation . There are no actions, suits or proceedings by or before any arbitrator or Governmental Authority pending against or, to the 

knowledge of the Borrower, threatened against or affecting the Borrower or any of its Consolidated Subsidiaries that in any manner draws into 

question the validity or enforceability of this Amendment or the Amended Agreement or that otherwise involve this Amendment, the Amended 

Agreement, any of the other Loan Documents, the Mortgage Indenture or the Transactions. 

(d) No Default . No Default has occurred and is continuing or would occur as a result of the execution, delivery or performance of this 

Amendment. 

SECTION 4. Reference to and Effect on the Existing Agreement. (a) Upon the effectiveness of this Amendment: (i) each reference in 

the Existing Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Existing Agreement shall mean and 

be a reference to the Amended Agreement; and (ii) each reference in any other Loan Document to “the Credit Agreement”, “thereunder”, 

“thereof” or words of like import referring to the Existing Agreement shall mean and be a reference to the Amended Agreement. This 

Amendment shall constitute a “Loan Document” for all purposes under the Credit Agreement. 

 

6 
(b) Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects 

ratified and confirmed. Without limiting the generality of the foregoing, the Security Documents and all of the Collateral described therein do 

and shall continue to secure the payment of all Obligations. 

(c) The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any 

right, power or remedy of the Lenders, the Administrative Agent or the Issuing Banks under the Existing Agreement or any other Loan 

Document, nor constitute a waiver of any provision of the Existing Agreement or any other Loan Document. 

SECTION 5. Costs and Expenses . The Borrower agrees to pay, promptly after delivery to the Borrower of a reasonably detailed 

statement therefor, all reasonable out-of-pocket expenses incurred by the Administrative Agent in connection with the preparation, negotiation, 

syndication, execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder, including, without 

limitation, the reasonable fees, charges and disbursements of counsel to the Administrative Agent with respect thereto and with respect to 

advising the Administrative Agent as to its rights and responsibilities hereunder and thereunder, and all out-of-pocket expenses incurred by the 

Administrative Agent, any Issuing Bank or any Lender (including, without limitation, the fees, charges and disbursements of any counsel for the 

Administrative Agent, any Issuing Bank or any Lender) in connection with the enforcement (whether through negotiations, legal proceedings or 

otherwise) of this Amendment. 

SECTION 6. Execution in Counterparts . This Amendment may be executed in counterparts (and by different parties hereto on different 

counterparts), each of which shall constitute an original but all of which when taken together shall constitute a single contract. Delivery of an 

executed signature page to this Amendment by facsimile or other electronic transmission (including, without limitation, by Adobe portable 

document format file (also known as a “PDF” file)) shall be as effective as delivery of a manually signed counterpart of this Amendment. 

SECTION 7. Governing Law . This Amendment shall be governed by, and construed in accordance with, the laws of the State of the New 

York. 

SECTION 8. Miscellaneous. This Amendment shall be subject to the provisions of Sections 9.05, 9.07, 9.10, 9.11 and 9.12 of the Existing 

Agreement, each of which is incorporated by reference herein, mutatis mutandis . 

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] 

 

7 
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly 

authorized, as of the date first above written. 

 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-1 

TUCSON ELECTRIC POWER COMPANY 

By: /s/ Kentton C. Grant 

 

Name: Kentton C. Grant 

Title: Vice President and Treasurer 

UNION BANK, N.A ., as Administrative 

Agent, as an Issuing Bank and as a Lender 

By: /s/ Jeffrey P. Fesenmaier 

 

Name: Jeffrey P. Fesenmaier 

Title: Vice President 
 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-2 

THE BANK OF NEW YORK MELLON, as 

an Issuing Bank and as a Lender 

By: /s/ Mark W. Rogers 

 

Name: Mark W. Rogers 

Title: Vice President 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-3 

JPMORGAN CHASE BANK, N.A. , as an 

Issuing Bank and as a Lender 

By: /s/ Nancy R. Barwig 

 

Name: Nancy R. Barwig 

Title: Credit Executive 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-4 

WELLS FARGO BANK, NATIONAL 

ASSOCIATION , as an Issuing Bank and as a Lender 

By: /s/ Yann Blindert 

 

Name: Yann Blindert 

Title: Director 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-5 

U.S. BANK NATIONAL ASSOCIATION , as 

an Issuing Bank and as a Lender 

By: /s/ Raymond J. Palmer 

 

Name: Raymond J. Palmer 

Title: Senior Vice President 
 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-6 

SUNTRUST BANK , as a Lender 

By: /s/ Andrew Johnson 

 

Name: Andrew Johnson 

Title: Director 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-7 

BANK OF AMERICA, N.A. , as a Lender 

By: /s/ Kevin P. Bertelsen 

 

Name: Kevin P. Bertelsen 

Title: Managing Director 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-8 

COBANK, ACB, as a Lender 

By: /s/ John H. Kemper 

 

Name: John H. Kemper 

Title: Vice President 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-9 

COMERICA BANK , as a Lender 

By: /s/ Fatima Arshad 

 

Name: Fatima Arshad 

Title: Vice President 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-10 

COMPASS BANK , an Alabama Banking 

 

Corporation, as a Lender 

By: /s/ Izaro Urreiztieta 

 

Name: Izaro Urreiztieta 

Title: Senior Vice President 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-11 

SCOTIABANC INC. , as a Lender 

By: /s/ J.F. Todd 

 

Name: J.F. Todd 

Title: Managing Director 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-12 

THE BANK OF NOVA SCOTIA , as a 

Lender 

By: /s/ Thane Rettew 

 

Name: Thane Rattew 

Title: Managing Director 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-13 

Bank Hapoalim B.M., as a Lender 

By: /s/ Helen H. Gateson 

 

Name: Helen H. Gateson 

Title: Vice President 

By: /s/ Frederic S. Becker 

 

Name: Frederic S. Becker 

Title: Senior Vice President 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-14 

CREDIT SUISSE AG, CAYMAN ISLANDS 

BRANCH, as a Lender 

By: /s/ Shaheen Malik 

 

Name: Shaheen Malik 

Title: Vice President 

By: /s/ Rahul Parmar 

 

Name: Rahul Parmar 

Title: Associate 
 

 

Amendment No. 1 to TEP Second Amended and Restated Credit Agreement 

S-15 

NATIONAL BANK OF ARIZONA , as a 

Lender 

By: /s/ Reid Clark 

 

Name: Reid Clark 

Title: Vice President 
SCHEDULE A 

to Amendment No. 1 to Credit Agreement 

SCHEDULE 1.01 

PRICING SCHEDULE 

The “Applicable Margin” and the “Commitment Fee Rate” for any day (a) from and after the Effective Date through (but not including) the 

Amendment No. 1 Effective Date, are the respective annual percentage rates set forth in Table A below in the applicable row under the column 

corresponding to the Status that exists on such day, and (b) from and after the Amendment No. 1 Effective Date, are the respective annual 

percentages rates set forth in Table B below in the applicable row under the column corresponding to the Status that exists on such day: 

TABLE A 

 

TABLE B 

 

 

Schedule A 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.625% 1.875 % 2.125 % 2.50 % 3.00 % 3.50 % 

Applicable Margin — ABR Loans 0.625% 0.875 % 1.125 % 1.50 % 2.00 % 2.50 % 

Commitment Fee Rate 0.175% 0.225 % 0.350 % 0.450 % 0.600 % 0.750 % 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.00% 1.125 % 1.25 % 1.50 % 1.75 % 2.00 % 

Applicable Margin — ABR Loans 0.00% 0.125 % 0.25 % 0.50 % 0.75 % 1.00 % 

Commitment Fee Rate 0.125% 0.175 % 0.20 % 0.25 % 0.30 % 0.35 % 
For purposes of this Pricing Schedule, the following terms have the following meanings: 

“ Level 1 Status ” exists at any date if, at such date, the Index Debt is rated either A- or higher by S&P or A3 or higher by Moody’s. 

“ Level 2 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB+ or higher by S&P or Baa1 or higher by 

Moody’s and (ii) Level 1 Status does not exist. 

“ Level 3 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB or higher by S&P or Baa2 or higher by 

Moody’s and (ii) neither Level 1 Status nor Level 2 Status exists. 

“ Level 4 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB- or higher by S&P or Baa3 or higher by 

Moody’s and (ii) none of Level 1 Status, Level 2 Status or Level 3 Status exists. 

“ Level 5 Status ” exists at any date if, at such date (i) the Index Debt is rated either BB+ or higher by S&P or Ba1 or higher by 

Moody’s and (ii) none of Level 1 Status, Level 2 Status, Level 3 Status or Level 4 Status exists. 

“ Level 6 Status ” exists at any date if, at such date, no other Status exists. 

“ Status ” refers to the determination of which of Level 1 Status, Level 2 Status, Level 3 Status, Level 4 Status, Level 5 Status or 

Level 6 Status exists at any date. 

Notwithstanding the foregoing, if the Index Debt is split-rated and the ratings differential is two or more ratings levels, the Status 

shall be determined assuming that (a) the higher rating is equal to the midpoint of the two ratings (e.g., for a split rating of BBB+/Baa3, BBB is 

the midpoint and will be deemed to be the higher rating, and for a split rating of BB/Baa1, Baa3 is the midpoint and will be deemed to be the 

higher rating) or (b) if there is no exact midpoint, the higher rating is equal to the higher of the two middle intermediate ratings (e.g., for a split 

rating of BBB+/Ba1, BBB is the higher of the two middle intermediate ratings and will be deemed to be the higher rating, and for a split rating of 

BB/Baa2, Baa3 is the higher of the two middle intermediate ratings and will be deemed to be the higher rating). 

If at any time the Index Debt is unrated by both Moody’s and S&P, Level 6 Status shall exist; provided that if the reason that there is 

no such Moody’s rating or S&P rating results from Moody’s or S&P, as the case may be, ceasing to issue debt ratings generally, then the 

Borrower and the Administrative Agent may select another nationally-recognized rating agency to substitute for Moody’s or S&P, as applicable, 

for purposes of this Pricing Schedule (and all references herein to Moody’s or S&P, as applicable, shall refer to such substitute rating agency), 

and until a substitute nationally-recognized rating agency is so selected the Status shall be determined by reference to the rating most recently in 

effect prior to such cessation; and provided , further , that if the Index Debt is rated by only one of Moody’s or S&P, the Status shall be 

determined by reference to the rating of such Rating Agency. 

 

Schedule A 
The Applicable Margin and Commitment Fee Rate shall be increased or decreased in accordance with the foregoing Pricing Schedule 

upon any change in the applicable ratings of the Index Debt. The ratings of the Index Debt in effect at any date is that in effect at the close of 

business on such date. 

 

Schedule A 
[SCHEDULE B 

to Amendment No. 1 to Credit Agreement] 

SCHEDULE 2.01 

Commitments 

 

 

Schedule B 

Lender Revolving Commitment Revenue Bond Commitment Aggregate Commitment 

Union Bank, N.A. $ 20,750,422.15 $ 35,336,625.04 $ 56,087,047.19 

JPMorgan Chase Bank, N.A. $ 18,498,408.45 $ 31,501,591.55 $ 50,000,000.00 

SunTrust Bank $ 18,498,408.45 $ 31,501,591.55 $ 50,000,000.00 

Wells Fargo Bank, National Association $ 18,498,408.45 $ 31,501,591.55 $ 50,000,000.00 

Bank of America, N.A. $ 16,648,567.60 $ 28,351,432.40 $ 45,000,000.00 

U.S. Bank National Association $ 16,648,567.60 $ 28,351,432.40 $ 45,000,000.00 

CoBank, ACB $ 14,798,726.76 $ 25,201,273.24 $ 40,000,000.00 

Compass Bank, an Alabama Banking Corporation $ 14,798,726.76 $ 25,201,273.24 $ 40,000,000.00 

National Bank of Arizona $ 11,099,045.07 $ 18,900,954.93 $ 30,000,000.00 

Bank Hapoalim B.M. $ 9,249,204.22 $ 15,750,795.78 $ 25,000,000.00 

Comerica Bank $ 9,249,204.22 $ 15,750,795.78 $ 25,000,000.00 

Scotiabanc Inc. $ 9,249,204.22 $ 15,750,795.78 $ 25,000,000.00 

The Bank of Nova Scotia $ 9,249,204.22 $ 15,750,795.78 $ 25,000,000.00 

The Bank of New York Mellon $ 9,249,204.22 $ 15,750,795.78 $ 25,000,000.00 

Credit Suisse AG, Cayman Islands Branch $ 3,514,697.60 $ 5,985,302.40 $ 9,500,000.00 

Total Commitments $ 200,000,000.00 $ 340,587,047.19 $ 540,587,047.19 
EXHIBIT A 

to Amendment No. 1 to Credit Agreement 

FORM OF BOND DELIVERY AGREEMENT 

[See Attached] 
Amended and Restated Bond Delivery Agreement 

TUCSON ELECTRIC POWER COMPANY 

to 

UNION BANK, N.A., 

as Administrative Agent 

Dated as of November , 2011 

Relating to 

First Mortgage Bonds, Collateral Series I 

 

A-1 
THIS AMENDED AND RESTATED BOND DELIVERY AGREEMENT, dated as of November , 2011, is between T UCSON E 

LECTRIC P OWER C OMPANY , an Arizona corporation (the “Company”), and U NION B ANK , N.A. (formerly known as Union Bank of California,

N.A.), as administrative agent (in such capacity, together with its successors and assigns in such capacity, the “Administrative Agent”) under the 

Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among the Company, the Lenders party thereto, the Issuing 

Banks party thereto, JPMorgan Chase Bank, N.A., SunTrust Bank and Wells Fargo Bank, National Association, as Co-Syndication Agents, Bank 

of America, N.A. and U.S. Bank National Association, as Co-Documentation Agents, and Union Bank, N.A. (formerly known as Union Bank of 

California, N.A.), as Administrative Agent, as amended, amended and restated, supplemented or otherwise modified from time to time (the 

“Credit Agreement”). 

W HEREAS , the Company has entered into the Credit Agreement and has requested the issuance of the Revenue Bond Letters of Credit and 

may from time to time borrow Loans and request the issuance of additional Letters of Credit (such terms and all other capitalized terms used 

herein without definition having the meanings assigned to them in the Credit Agreement) in accordance with the provisions of the Credit 

Agreement; and 

W HEREAS , the Company has established its First Mortgage Bonds, Collateral Series I, in the aggregate principal amount of up to 

$540,588,000.00 (the “Series 10 Bonds”), issued under and in accordance with, and secured by, the Indenture of Mortgage and Deed of Trust, 

dated as of December 1, 1992, between the Company and The Bank of New York Mellon, formerly known as The Bank of New York (successor 

in trust to Bank of Montreal Trust Company), as trustee (the “Trustee”), as amended and supplemented and as further supplemented by 

Supplemental Indenture No. 11, dated as of November 1, 2010, as amended by Supplemental Indenture No. 13, dated as of November 1, 2011 

(such Indenture, as so amended and supplemented, and such Supplemental Indenture, as so amended, being hereinafter sometimes called the 

“General First Mortgage” and “Supplemental Indenture No. 11”, respectively); and 

W HEREAS , the Company has issued and delivered to the Administrative Agent, for its benefit and the benefit of the Lenders and the 

Issuing Banks, the Series 10 Bonds in order to provide collateral security for the obligation of the Company under the Credit Agreement to pay 

the Obligations; and 

W HEREAS , on the date hereof, the Company is amending the Credit Agreement to, among other things, extend the term thereof; and 

W HEREAS , with the consent of the Administrative Agent, the Issuing Banks and the Lenders, the Company and the Trustee are entering 

into the Supplemental Indenture No. 13, dated as of November 1, 2011, to amend the Series 10 Bonds to extend their stated maturity; and 

W HEREAS , the Company and the Administrative Agent previously entered into that certain Bond Delivery Agreement, dated as of 

November 9, 2010 (the “Existing Bond Delivery Agreement”), and the parties hereto desire to amend and restate the Existing Bond Delivery 

Agreement on the terms and conditions set forth herein. 

 

A-2 
N OW , T HEREFORE , in consideration of the premises, of the agreements of the Lenders and Issuing Banks in the Credit Agreement, and of 

other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Company and the Administrative 

Agent hereby agree that the Existing Bond Delivery Agreement is amended and restated in its entirety, without novation, as follows: 

ARTICLE I 

S ERIES 10 B ONDS 

SECTION 1.1. Delivery of Series 10 Bonds. 

In order to provide collateral security for the obligation of the Company to pay the Obligations, as aforesaid, the Company hereby delivers 

to the Administrative Agent Series 10 Bonds in the aggregate principal amount of $540,588,000.00, maturing on December 9, 2016 and bearing 

interest as provided in Supplemental Indenture No. 11, in substitution and exchange for (but not payment of) the Series 10 Bonds previously 

issued and held by the Administrative Agent. The obligation of the Company to pay the principal of and interest on the Series 10 Bonds shall be 

deemed to have been satisfied and discharged in full or in part, as the case may be, to the extent of the payment by the Company of the 

Obligations, all as set forth in subdivision (u) of Article II of Supplemental Indenture No. 11 and in the Series 10 Bonds. 

The Series 10 Bonds are registered in the name of the Administrative Agent and shall be owned and held by the Administrative Agent, 

subject to the provisions of this Agreement, for its benefit and the benefit of the Lenders and the Issuing Banks, and the Company shall have no 

interest therein. The Administrative Agent shall be entitled to exercise all rights of bondholders under the General First Mortgage with respect to 

the Series 10 Bonds. 

The Administrative Agent hereby acknowledges receipt of the Series 10 Bonds. 

SECTION 1.2. Payments on Series 10 Bonds. 

Any payments received by the Administrative Agent on account of the principal of or interest on the Series 10 Bonds shall be distributed 

by the Administrative Agent in accordance with the applicable provisions of the Credit Agreement, and the Company hereby consents to such 

distribution. 

ARTICLE II 

N O T RANSFER OF B ONDS ; S URRENDER OF B ONDS 

SECTION 2.1. No Transfer of Bonds. 

The Administrative Agent shall not sell, assign or otherwise transfer any Series 10 Bonds delivered to it under this Agreement except to a 

successor administrative agent under the Credit Agreement. The Company may take such actions as it shall deem necessary, desirable or 

appropriate to effect compliance with such restrictions on transfer, including the issuance of stop-transfer instructions to the trustee under the 

General First Mortgage or any other transfer agent thereunder. 

 

A-3 
SECTION 2.2. Surrender of Bonds. 

(a) The Administrative Agent shall forthwith surrender to or upon the order of the Company all Series 10 Bonds held by it at the first time 

at which the Aggregate Commitments shall have been terminated, no Letter of Credit shall be outstanding and all Obligations shall have been 

paid in full. 

(b) Upon any permanent reduction in the Revolving Commitments or the Revenue Bond Commitments pursuant to Section 2.07(b) of the 

Credit Agreement, the Administrative Agent shall forthwith surrender to or upon the order of the Company Series 10 Bonds in an aggregate 

principal amount equal to the excess of the aggregate principal amount of the Series 10 Bonds held by the Administrative Agent over the sum of 

(i) the greater at such time of the total Revolving Commitments and the total Revolving Credit Exposure plus (ii) the greater at such time of the 

total Revenue Bond Commitments and the total Revenue Bond Credit Exposure, provided that the Administrative Agent shall have received, in 

accordance with Section 6 of Article II of the General First Mortgage, replacement Series 10 Bonds in an aggregate principal amount equal to 

the sum of clauses (i) and (ii) above. 

This Agreement shall be governed by and construed in accordance with the law of the State of New York. 

[R EMAINDER OF P AGE I NTENTIONALLY L EFT B LANK ] 

 

A-4 
I N W ITNESS W HEREOF , the Company and the Administrative Agent have caused this Agreement to be executed and delivered as of the 

date first above written. 

 

 

Signature Page to Amended and Restated Bond Delivery Agreement 

T UCSON E LECTRIC P OWER C OMPANY 

By 

 

 

Name: Kentton C. Grant 

Title: Vice President 

U NION B ANK , N.A., 

as Administrative Agent 

By 

 

 Vice President 
EXHIBIT B 

to Amendment No. 1 to Credit Agreement 

FORM OF THIRTEENTH SUPPLEMENTAL INDENTURE 

[See Attached] 

 
Supplemental Indenture No. 13 

TUCSON ELECTRIC POWER COMPANY 

to 

THE BANK OF NEW YORK MELLON, 

Trustee 

Dated as of November 1, 2011 

Supplemental to Indenture of Mortgage and Deed of Trust, 

dated as of December 1, 1992 

Amending Terms of Bonds Designated 

First Mortgage Bonds, Collateral Series I 

This instrument constitutes a mortgage, a deed of trust and a security agreement. 

 

B-1 
SUPPLEMENTAL INDENTURE NO. 13 , dated as of November 1, 2011, between T UCSON E LECTRIC P OWER C OMPANY (hereinafter 

sometimes called the “Company”), a corporation organized and existing under the laws of the State of Arizona, having its principal office at One 

South Church Avenue, in the City of Tucson, Arizona, as trustor, and T HE B ANK OF N EW Y ORK M ELLON , formerly known as The Bank of 

New York (successor in trust to Bank of Montreal Trust Company), a banking corporation organized and existing under the laws of the State of 

New York and having its principal office at 101 Barclay Street, in the Borough of Manhattan, The City of New York, New York, as trustee 

(hereinafter sometimes called the “Trustee”), under the Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, between the 

Company and the Trustee (hereinafter called the “Original Indenture”), as heretofore amended and supplemented, this Supplemental Indenture 

No. 13 being supplemental thereto (the Original Indenture as heretofore amended and supplemented, and as supplemented hereby, and as it may 

from time to time be further supplemented, modified, altered or amended by any supplemental indenture entered into in accordance with and 

pursuant to the provisions thereof, is hereinafter called the “Indenture”). 

R ECITALS OF THE C OMPANY 

W HEREAS , on November 9, 2010, the Company issued a series of Bonds designated “First Mortgage Bonds, Collateral Series I” limited in 

aggregate principal amount (except as contemplated in clause (b) of Section 2 of Article II of the Original Indenture) to $540,588,000, such 

series of Bonds and such Bonds to be hereinafter sometimes called, respectively, “Series 10” and “Series 10 Bonds”; and 

W HEREAS , all terms of Series 10 Bonds have been established in a Supplemental Indenture No. 11, dated as of November 1, 2010 (the 

“Supplemental Indenture No. 11”); and 

W HEREAS , the Holder of all Series 10 Bonds is Union Bank, N.A., in its capacity as Administrative Agent under the Second Amended and 

Restated Credit Agreement, dated as of November 9, 2010, among the Company, the Lenders party thereto, the Issuing Banks party thereto, the 

Co-Syndication Agents party thereto, the Co-Documentation Agents party thereto and the Administrative Agent, as amended, amended and 

restated, supplemented or otherwise modified from time to time (the “Credit Agreement”); and 

W HEREAS , the Company is amending the Credit Agreement to, among other things, extend the term thereof, and desires to amend the 

Series 10 Bonds to extend their stated maturity; and 

W HEREAS , Section 2 of Article XIII of the Indenture provides that with the consent of the Holder of each Outstanding Bond directly 

affected, the Company and the Trustee may enter into an indenture supplemental to the Indenture for the purpose of adding any provisions to, or 

changing in any manner or eliminating any of the provisions of the Indenture, including, but not limited to, changing the stated maturity of the 

principal of any such Bond; and 

W HEREAS , the Administrative Agent, as Holder of all Series 10 Bonds, has consented to all changes described in this Supplemental 

Indenture No. 13; and 

 

B-2 
W HEREAS , as provided in Article II, Section 6 of the Indenture, upon surrender for exchange of the existing Series 10 Bonds by the 

Administrative Agent, the Company shall execute, the Trustee shall authenticate, and the Company shall deliver to the Administrative Agent 

replacement Series 10 Bonds in substitution and exchange for (but not payment of) the surrendered Series 10 Bonds, and the Trustee shall cancel 

the surrendered Series 10 Bonds and deliver proof of cancellation to the Company; and 

W HEREAS , effective June 3, 1999, The Bank of New York succeeded to all of the corporate trust business of Bank of Montreal Trust 

Company, and, as a consequence, The Bank of New York, being otherwise qualified and eligible under Article XII of the Original Indenture, 

became the successor trustee under the Indenture without further act on the part of the parties thereto, as contemplated by Section 11 of Article 

XII of the Original Indenture; and 

W HEREAS , effective July 1, 2008, The Bank of New York changed its name to The Bank of New York Mellon. 

ARTICLE I 

A DDITIONAL D EFINITIONS 

S ECTION 1. A PPLICABILITY OF A RTICLE . 

For all purposes of this Supplemental Indenture No. 13, except as otherwise expressly provided or unless the context otherwise requires, 

the terms defined herein shall have the meanings herein specified and include the plural as well as the singular. All terms that are not defined 

herein but are defined in the Supplemental Indenture No. 11 or in the Indenture shall have the meanings set forth in the Supplemental Indenture 

No. 11 or in the Indenture, respectively. 

ARTICLE II 

A MENDMENT OF T ERMS OF S ERIES 10 B ONDS 

This Supplemental Indenture No. 13 is being delivered to effect the following changes to the Supplemental Indenture No. 11 and the Series 

10 Bonds: 

1. clause (d) of Article II of the Supplemental Indenture No. 11 is hereby amended to read as follows: 

“(d) the Series 10 Bonds shall mature on December 9, 2016;”; and 

2. the form of Series 10 Bonds is hereby amended to read as set forth in Exhibit A attached hereto. 

 

B-3 
ARTICLE III 

M ISCELLANEOUS P ROVISIONS 

This Supplemental Indenture No. 13 is a supplement to the Original Indenture. As heretofore supplemented and further supplemented by 

this Supplemental Indenture No. 13, the Original Indenture is in all respects ratified, approved and confirmed, and the Original Indenture as 

heretofore supplemented and this Supplemental Indenture No. 13 shall together constitute one and the same instrument. 

Upon the effectiveness of this Supplemental Indenture No. 13, each reference in the Supplemental Indenture No. 11 to “this Supplemental 

Indenture No. 11”, “hereunder”, “hereof”, “herein” or words of like import referring to the Supplemental Indenture No. 11 shall mean and be a 

reference to the Supplemental Indenture No. 11, as amended by this Supplemental Indenture No. 13. Except as specifically amended above, the 

Supplemental Indenture No. 11 shall continue to be in full force and effect and is hereby in all respects ratified, approved and confirmed. 

The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture No. 13. The statements and recitals 

herein are deemed to be those of the Company and not of the Trustee. 

 

B-4 
I N W ITNESS W HEREOF , Tucson Electric Power Company has caused its corporate name to be hereunto affixed, and this instrument to be 

signed by one of its Vice Presidents, and its corporate seal to be hereunto affixed and attested by its Secretary or one of its Assistant Secretaries 

for and on its behalf; and The Bank of New York Mellon, as trustee, in evidence of its acceptance of the trust hereby created, has caused its 

corporate name to be hereunto affixed, and this instrument to be signed by one of its authorized signatories and its corporate seal to be hereunto 

affixed and attested by one of its authorized signatories, for and on its behalf, all as of the day and year first above written. 

 

 

 

 

 

B-5 

T UCSON E LECTRIC P OWER C OMPANY 

By 

 

 

Kentton C. Grant 

Vice President and Treasurer 

Attest: 

 

 

 

Linda H. Kennedy 

Secretary 
 

 

 

 

B-6 

T HE B ANK OF N EW Y ORK M ELLON , 

Trustee 

By 

 

 Authorized Signatory 

Attest: 

 

 

 Authorized Signatory 
 

This instrument was acknowledged before me this 17th day of November, 2011 by Kentton C. Grant, as Vice President and Treasurer, and 

Linda H. Kennedy, as Secretary, of T UCSON E LECTRIC P OWER C OMPANY , an Arizona corporation, known to me to be the individuals who 

executed this instrument, and known to me to be a Vice President and Treasurer and the Secretary, respectively, of said corporation, and who 

personally acknowledged before me and stated that they executed said instrument on behalf of said corporation for the purposes and 

consideration therein expressed. 

 

B-7 

S TATE OF A RIZONA ) 

 ) ss.: 

C OUNTY OF P IMA ) 

 

N OTARY P UBLIC 
 

This instrument was acknowledged before me this 16th day of November, 2011 by Francine Kincaid, as Authorized Signatory, and Scott 

Klein, as Authorized Signatory, of T HE B ANK OF N EW Y ORK M ELLON , a New York banking corporation, known to me to be the individuals 

who executed this instrument, and known to me to be Authorized Signatories of said corporation, and who personally acknowledged before me 

and stated that they executed said instrument on behalf of said corporation for the purposes and consideration therein expressed. 

 

 

B-8 

S TATE OF N EW Y ORK ) 

 ) ss.: 

C OUNTY OF N EW Y ORK ) 

 

N OTARY P UBLIC 
Exhibit A 

[Form of Bond] 

This bond is non-transferable, 

except to a successor Administrative Agent under the 

Credit Agreement referred to herein. 

 

TUCSON ELECTRIC POWER COMPANY 

FIRST MORTGAGE BOND, COLLATERAL SERIES I 

DUE DECEMBER 9, 2016 

TUCSON ELECTRIC POWER COMPANY, a corporation of the State of Arizona (hereinafter sometimes called the “Company”), for 

value received, promises to pay to as Administrative Agent under the Credit Agreement hereinafter referred to or registered assigns, the principal 

sum of 

DOLLARS 

on December 9, 2016 in coin or currency of the United States of America which at the time of payment shall be legal tender for the payment of 

public and private debts, at the office or agency of the Company in The City of New York, or in the City of Tucson, Arizona, upon presentation 

hereof, and quarterly, on the last Business Day (as defined in Supplemental Indenture No. 11 hereinafter referred to) of March, June, September 

and December in each year, commencing December 31, 2010 (each an “Interest Payment Date”), and at Maturity (as defined in Supplemental 

Indenture No. 11 hereinafter referred to), to pay interest thereon in like coin or currency at the rate specified below, from the Interest Payment 

Date next preceding the date of this bond (unless this bond be dated on an Interest Payment Date, in which case from the date hereof; or unless 

this bond be dated prior to the first Interest Payment Date, in which case from and including the date of the first authentication and delivery of 

the bonds of this series), until the Company’s obligation with respect to such principal sum shall be discharged. 

During the period from and including the date of the first authentication and delivery of the bonds of this series (which date was 

November 9, 2010) to and including the day next preceding the first Interest Payment Date, the bonds of this series shall bear interest at the rate 

of eight per centum (8%) per annum; thereafter, the bonds of this series shall bear interest at a rate equal to the Alternate Base Rate (as defined in 

Supplemental Indenture No. 11 hereinafter referred to) from time to time in effect plus 500 basis points. Interest on the bonds of this series 

during any period for which payment is made shall be computed in accordance with the Credit Agreement. 

 

Exh. A-1 

No. $ 
This bond is one of an issue of bonds of the Company, issued and to be issued in one or more series under and equally and ratably secured 

(except as any sinking, amortization, improvement, renewal or other fund, established in accordance with the provisions of the indenture 

hereinafter mentioned, may afford additional security for the bonds of any particular series) by the Indenture of Mortgage and Deed of Trust, 

dated as of December 1, 1992 (the “Original Indenture”), from the Company to The Bank of New York Mellon, formerly known as The Bank of 

New York (successor in trust to Bank of Montreal Trust Company), as trustee (the “Trustee”), as supplemented by thirteen supplemental 

indentures including Supplemental Indenture No. 11, dated as of November 1, 2010, establishing the bonds of this series, as amended by 

Supplemental Indenture No. 13, dated as of November 1, 2011 (the Original Indenture, as so supplemented, and such Supplemental Indenture 

No. 11, as so amended, being hereinafter called the “Indenture” and “Supplemental Indenture No. 11”, respectively), to which Indenture 

reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security provided by the 

Indenture, the rights and limitations of rights of the Company, the Trustee and the holders of said bonds with respect to the security provided by 

the Indenture, the powers, duties and immunities of the Trustee, the terms and conditions upon which such bonds are and are to be secured, and 

the circumstances under which additional bonds may be issued. The acceptance of this bond shall be deemed to constitute the consent and 

agreement by the holder hereof to all of the terms and provisions of the Indenture. This bond is one of a series of bonds designated as the First 

Mortgage Bonds, Collateral Series I, of the Company. 

The Indenture permits, with certain exceptions as therein provided, the Trustee to enter into one or more supplemental indentures for the 

purpose of adding any provisions to, or changing in any manner or eliminating any of the provisions of, the Indenture with the consent of the 

holders of not less than sixty per centum (60%) in aggregate principal amount of the bonds of all series then outstanding under the Indenture, 

considered as one class; provided, however, that if there shall be bonds of more than one series outstanding under the Indenture and if a proposed 

supplemental indenture shall directly affect the rights of the holders of bonds of one or more, but less than all, of such series, then the consent 

only of the holders of bonds in aggregate principal amount of the outstanding bonds of all series so directly affected, considered as one class, 

shall be required; and provided, further, that if the bonds of any series shall have been issued in more than one tranche and if the proposed 

supplemental indenture shall directly affect the rights of the holder of bonds of one or more, but less than all, of such tranches, then the consent 

only of the holders of bonds in aggregate principal amount of the outstanding bonds of all tranches so directly affected, considered as one class, 

shall be required; and provided, further, that the Indenture permits the Trustee to enter into one or more supplemental indentures for limited 

purposes without the consent of any holders of bonds. Any such consent by the holder of this bond shall be conclusive and binding upon such 

holder and upon all future holders of this bond and of any bond issued upon the registration of transfer hereof or in exchange therefor or in lieu 

hereof, whether or not notation of such consent is made upon this bond. 

The Company has issued and delivered the bonds of this series to Union Bank, N.A., as Administrative Agent (the “Administrative 

Agent”) under the Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among the Company, the Lenders party 

thereto, the Issuing Banks party thereto, the Co-Syndication Agents party thereto, the Co- 

 

Exh. A-2 
Documentation Agents party thereto and Union Bank, N.A. (formerly known as Union Bank of California, N.A.), as Administrative Agent, as 

amended, amended and restated, supplemented or otherwise modified from time to time (the “Credit Agreement”), in order to provide collateral 

security for the obligation of the Company thereunder to pay the Obligations (as defined in Supplemental Indenture No. 11). 

Upon the occurrence of an Event of Default under the Credit Agreement, and further upon such additional conditions as are set forth in 

subdivision (h) of Article II of Supplemental Indenture No. 11, then all bonds of this series shall be redeemed immediately at the principal 

amount thereof plus accrued interest to the date of redemption. 

The obligation of the Company to pay interest on the bonds of this series on any Interest Payment Date prior to Maturity (a) shall be 

deemed to have been satisfied and discharged in full in the event that all amounts then due in respect of the Obligations shall have been paid or 

(b) shall be deemed to remain unsatisfied in an amount equal to the aggregate amount then due in respect of the Obligations and remaining 

unpaid (not in excess, however, of the amount otherwise then due in respect of interest on the bonds of this series). 

The obligation of the Company to pay the principal of and accrued interest on the bonds of this series at or after Maturity (x) shall be 

deemed to have been satisfied and discharged in full in the event that all amounts then due in respect of the Obligations shall have been paid and 

no Letter of Credit (as defined in Supplemental Indenture No. 11) shall remain outstanding or (y) shall be deemed to remain unsatisfied in an 

amount equal to the aggregate amount then due in respect of the Obligations and remaining unpaid plus the aggregate stated amount of the 

outstanding Letters of Credit (not in excess, however, of the amount otherwise then due in respect of principal of and accrued interest on the 

bonds of this series). 

The principal of this bond and the interest accrued hereon may become or be declared due and payable before the stated maturity hereof, on 

the conditions, in the manner and at the times set forth in the Indenture, upon the happening of a default as therein provided. 

This bond is non-transferable except as required to effect transfer to any successor administrative agent under the Credit Agreement, any 

such transfer to be made at the office or agency of the Company in The City of New York, upon surrender and cancellation of this bond, and 

upon any such transfer a new bond of this series, for the same aggregate principal amount and having the same stated maturity date, will be 

issued to the transferee in exchange herefor. Prior to due presentment for registration of transfer, the Company and the Trustee may deem and 

treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payment and for all other 

purposes. This bond, alone or with other bonds of this series, may in like manner be exchanged at such office or agency for one or more bonds of 

this series of the same aggregate principal amount and having the same stated maturity date and interest rate, all as provided in the Indenture. 

No recourse shall be had for the payment of the principal of or interest on this bond, or for any claim based hereon or otherwise in respect 

hereof or of the Indenture, against any incorporator, shareholder, director or officer, as such, past, present or future, of the Company or 

 

Exh. A-3 
of any predecessor or successor corporation, either directly or through the Company or any predecessor or successor corporation, whether by 

virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or by any legal or equitable proceeding or 

otherwise howsoever (including, without limiting the generality of the foregoing, any proceeding to enforce any claimed liability of shareholders 

of the Company, based upon any theory of disregarding the corporate entity of the Company or upon any theory that the Company was acting as 

the agent or instrumentality of the shareholders); all such liability being, by the acceptance hereof and as a part of the consideration for the 

issuance hereof, expressly waived and released by every holder hereof, and being likewise waived and released by the terms of the Indenture 

under which this bond is issued, as more fully provided in said Indenture. 

This bond shall not be valid or become obligatory for any purpose until the certificate of authentication hereon shall have been signed by 

The Bank of New York Mellon, or its successor, as Trustee under the Indenture. 

 

Exh. A-4 
I N W ITNESS W HEREOF , the Company has caused this bond to be signed in its name by the manual or facsimile signature of its President or 

one of its Vice Presidents, and its corporate seal, or a facsimile thereof, to be impressed or imprinted hereon and attested by the manual or 

facsimile signature of its Secretary or one of its Assistant Secretaries. 

Dated: , 20 

 

 

 

Exh. A-5 

TUCSON ELECTRIC POWER COMPANY 

By: 

 

Attest: 

 
[FORM OF TRUSTEE’S CERTIFICATE OF AUTHENTICATION] 

This is one of the bonds, of the series designated therein, described in the within-mentioned Indenture. 

Dated: , 20 

 

 

Exh. A-6 

The Bank of New York Mellon, 

Trustee 

By: 

 

 
EXHIBIT C 

to Amendment No. 1 to Credit Agreement 

FORM OF BONDHOLDER CONSENT 

[See Attached] 
BONDHOLDER CONSENT 

UNION BANK, N.A., as Administrative Agent (the “ Administrative Agent ”) under the Second Amended and Restated Credit Agreement, 

dated as of November 9, 2010, among Tucson Electric Power Company (the “ Company ”), the Lenders party thereto, the Issuing Banks party 

thereto, the Co-Syndication Agents party thereto, the Co-Documentation Agents party thereto and Union Bank, N.A., as Administrative Agent, 

as amended, restated, supplemented or otherwise modified from time to time, being the registered holder of $540,588,000 in aggregate principal 

amount of First Mortgage Bonds, Collateral Series I (the “ Bonds ”), of the Company, DOES HEREBY CONSENT, AS SUCH HOLDER, to 

the changes of the terms of the Bonds in the Supplemental Indenture No. 13, dated as of November 1, 2011, to the Indenture of Mortgage and 

Deed of Trust, dated as of December 1, 1992, between the Company and The Bank of New York Mellon (successor in trust to Bank of Montreal 

Trust Company), as trustee, as amended and supplemented. 

Dated: November 18, 2011 

 

 

C-1 

UNION BANK, N.A., 

as Administrative Agent 

By 

 

 

Name: 

Title: 
Exhibit 4(s)(2) 

[Execution Version] 

AMENDMENT NO. 1 

TO 

CREDIT AGREEMENT 

This AMENDMENT NO. 1, dated as of November 18, 2011 (this “ Amendment ”), is made by and among UNISOURCE ENERGY 

CORPORATION, an Arizona corporation (the “ Borrower ”), the lenders listed on the signature pages of this Amendment as “Lenders” (such 

lenders, together with their respective permitted assignees from time to time, being referred to herein, collectively, as the “ Lenders ”), 

JPMORGAN CHASE BANK, N.A., WELLS FARGO BANK, NATIONAL ASSOCIATION and UNION BANK, N.A., as issuing banks 

(collectively, in such capacities, the “ Issuing Banks ”), and UNION BANK, N.A. (formerly known as Union Bank of California, N.A.), as 

administrative agent (in such capacity, the “ Administrative Agent ”). 

PRELIMINARY STATEMENT : 

The Borrower, the Lenders, the Issuing Banks, JPMorgan Chase Bank, N.A., SunTrust Bank and Wells Fargo Bank, National Association, 

as Co-Syndication Agents, Bank of America, N.A. and U.S. Bank National Association, as Co-Documentation Agents, and the Administrative 

Agent previously entered into that certain Second Amended and Restated Credit Agreement, dated as of November 9, 2010 (the “ Existing 

Agreement ”, as amended by this Amendment, the “ Amended Agreement ”, and as the Amended Agreement may hereafter be amended, 

restated, supplemented or otherwise modified from time to time, the “ Credit Agreement ”). The Borrower desires to amend the Existing 

Agreement to (a) extend the Final Maturity Date to November 9, 2016, (b) reduce the Applicable Margin and the Commitment Fee Rate, and 

(c) make certain other modifications thereto, and the Lenders, the Issuing Banks and the Administrative Agent have agreed to such amendments 

on the terms and conditions set forth herein. The parties therefore agree as follows (capitalized terms used but not defined herein having the 

meanings assigned to such terms in the Existing Agreement): 

SECTION 1. Amendments to Existing Agreement . The Existing Agreement is, effective as of the date hereof and subject to the 

satisfaction of the conditions precedent set forth in Section 2 hereof, hereby amended as follows: 

(a) Disclosure Documents . The definition of “ Disclosure Documents ” contained in Section 1.01 of the Existing Agreement is hereby 

amended and restated in its entirety to read as follows: 

“ Disclosure Documents ” means (a) the Annual Report on Form 10-K of the Borrower for the fiscal year ended December 31, 2010, 

as filed with the SEC, (b) the Quarterly Reports on Form 10-Q of the Borrower for the fiscal quarters ended March 31, 2011, June 30, 2011 

and September 30, 2011, as filed with the SEC, and (c) the Current Reports on Form 8-K of the Borrower as filed with the SEC on 

February 25, 2011, March 21, 2011, May 11, 2011 and August 12, 2011. 
(b) Final Maturity Date . The definition of “ Final Maturity Date ” contained in Section 1.01 of the Existing Agreement is hereby amended 

and restated in its entirety to read as follows: 

“ Final Maturity Date ” means November 9, 2016. 

(c) Additional Definitions . The following new definitions are hereby added to Section 1.01 of the Existing Agreement in appropriate 

alphabetical order: 

“ Amendment No. 1 ” shall mean Amendment No. 1, dated as of November 18, 2011, among the Borrower, the Issuing Banks, the 

Lenders and the Administrative Agent, which Amendment No. 1 amended this Agreement pursuant to the terms thereof. 

“ Amendment No. 1 Effective Date ” shall mean November 18, 2011. 

(d) Financial Condition . Section 3.04(a) of the Existing Agreement is hereby amended by (i) deleting each reference to the date 

“December 31, 2009” in its entirety and substituting therefor in each case the new date “December 31, 2010” and (ii) deleting the phrase “to and 

including the Effective Date” in its entirety and substituting therefor the new phrase “to and including the Amendment No. 1 Effective Date”. 

(e) No Material Adverse Change . Section 3.04(b) of the Existing Agreement is hereby amended by deleting the date “December 31, 

2009” in its entirety and substituting therefor the new date “December 31, 2010”. 

(f) Pricing Schedule . Schedule 1.01 of the Existing Agreement is hereby replaced in its entirety with Schedule A attached hereto. 

SECTION 2. Conditions of Effectiveness . This Amendment shall become effective as of the date first written above (the “ Effective Date 

”) when, and only when, (a) the Administrative Agent shall have received all fees (including, without limitation, all upfront fees) payable by the 

Borrower pursuant to that certain proposal letter agreement, dated October 5, 2011, among Union Bank, the Borrower, TEP, UNS Gas and UNS 

Electric (the “ Proposal Letter ”), together with, to the extent invoiced, reimbursement or payment of all reasonable fees and out-of-pocket 

disbursements of counsel to the Administrative Agent and other out-of-pocket expenses of the Administrative Agent required to be reimbursed 

or paid by the Borrower pursuant to the Proposal Letter, (b) all requisite Governmental Authorities and third parties, if any, shall have approved 

or consented to the execution, delivery and performance by the Borrower of this Amendment and the Amended Agreement and the transactions 

contemplated thereby (collectively, the “ Transactions ”) to the extent required and material (and the Administrative Agent shall have received 

copies, certified by an Authorized Officer to be true, correct and complete and in full force and effect, of all such approvals and consents, which 

shall be in form and substance satisfactory to the Administrative Agent and the Lenders), no stay of any applicable regulatory approval shall 

have been issued and there shall be no litigation or governmental, administrative or judicial action, actual or threatened, that could reasonably be 

expected to restrain, prevent or 

 

2 
impose burdensome conditions on this Amendment, the Amended Agreement, any of the other Loan Documents or the Transactions, and (c) the 

Administrative Agent shall have received: (i) counterparts of this Amendment executed by all of the parties hereto (in sufficient quantity for each 

party to have a fully executed original), and (ii) all of the following documents, each document being dated the Effective Date unless otherwise 

specified below, in form and substance satisfactory to the Administrative Agent and in the number of originals or photostatic copies reasonably 

requested by the Administrative Agent: 

(A) a favorable written opinion (addressed to the Administrative Agent, the Issuing Banks and the Lenders) of (1) Morgan, Lewis & 

Bockius LLP, New York counsel for the Borrower, and (2) Todd C. Hixon, Esq., General Counsel for the Borrower, in each case covering 

such customary matters relating to this Amendment, the Amended Agreement and the Transactions as the Administrative Agent shall 

reasonably request, and the Borrower hereby requests such counsel to deliver such opinions; 

(B) such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, 

existence and good standing of the Borrower, the authorization of the Transactions, and any other legal matters relating to the Borrower, 

this Amendment, the Amended Agreement or the Transactions, all in form and substance satisfactory to the Administrative Agent and its 

counsel; 

(C) a certificate (the statements in which shall be true), signed by an Authorized Officer, certifying that: 

(1) the representations and warranties of the Borrower set forth in this Amendment, the Amended Agreement and the other 

Loan Documents are true and correct on and as of the Effective Date with the same effect as though made on and as of such date, 

except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and 

warranties were true and correct as of such earlier date); and 

(2) both before and after giving effect to this Amendment, no Default has occurred and is continuing; 

(D) a certificate, signed by an Authorized Officer, confirming compliance with the conditions set forth in this Section 2; and 

(E) copies of all amendments to the TEP Loan Documents (including, without limitation, Amendment No. 1, dated as of the date 

hereof, to the TEP Credit Agreement), certified by an Authorized Officer as complete and correct and in full force and effect. 

SECTION 3. Representations and Warranties of the Borrower . The Borrower represents and warrants to the Administrative Agent, the 

Lenders and the Issuing Banks that: 

 

3 
(a) Authorization; Enforceability . The Transactions are within the Borrower’s corporate powers and have been duly authorized by all 

necessary corporate and, if required, stockholder action. This Amendment has been duly executed and delivered by the Borrower, and each of 

this Amendment and the Amended Agreement constitutes a legal, valid and binding obligation of the Borrower, enforceable against the 

Borrower in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting 

creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law. 

(b) Government Approvals; No Conflicts . The Transactions (i) do not require any consent or approval of, registration or filing with, or any 

other action by, any Governmental Authority, except such as have been obtained or made and are in full force and effect, (ii) will not violate any 

Requirement of Law, (iii) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or 

any Subsidiary or its assets, or give rise to a right thereunder to require any payment to be made by the Borrower or any Subsidiary, and (iv) will 

not result in the creation or imposition of any Lien on any asset of the Borrower or any Subsidiary, except Liens created under the Loan 

Documents. 

(c) Litigation . There are no actions, suits or proceedings by or before any arbitrator or Governmental Authority pending against or, to the 

knowledge of the Borrower, threatened against or affecting the Borrower or any Subsidiary that in any manner draws into question the validity or 

enforceability of this Amendment or the Amended Agreement or that otherwise involve this Amendment, the Amended Agreement or the 

Transactions. 

(d) No Default . No Default has occurred and is continuing or would occur as a result of the execution, delivery or performance of this 

Amendment. 

SECTION 4. Reference to and Effect on the Existing Agreement . (a) Upon the effectiveness of this Amendment: (i) each reference in 

the Existing Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Existing Agreement shall mean and 

be a reference to the Amended Agreement; and (ii) each reference in any other Loan Document to “the Credit Agreement”, “thereunder”, 

“thereof” or words of like import referring to the Existing Agreement shall mean and be a reference to the Amended Agreement. This 

Amendment shall constitute a “Loan Document” for all purposes under the Credit Agreement. 

(b) Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects 

ratified and confirmed. Without limiting the generality of the foregoing, the Security Documents and all of the Collateral described therein do 

and shall continue to secure the payment of all Obligations. 

(c) The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any 

right, power or remedy of the Lenders, the Administrative Agent or the Issuing Banks under the Existing Agreement or any other Loan 

Document, nor constitute a waiver of any provision of the Existing Agreement or any other Loan Document. 

 

4 
SECTION 5. Costs and Expenses . The Borrower agrees to pay on demand all reasonable out-of-pocket expenses of the Administrative 

Agent in connection with the preparation, negotiation, syndication, execution and delivery of this Amendment and the other instruments and 

documents to be delivered hereunder, including, without limitation, the reasonable fees, charges and disbursements of counsel to the 

Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities hereunder 

and thereunder, and all out-of-pocket expenses incurred by the Administrative Agent, any Issuing Bank or any Lender (including, without 

limitation, the fees, charges and disbursements of any counsel for the Administrative Agent, any Issuing Bank or any Lender) in connection with 

the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment. 

SECTION 6. Execution in Counterparts . This Amendment may be executed in counterparts (and by different parties hereto on different 

counterparts), each of which shall constitute an original but all of which when taken together shall constitute a single contract. Delivery of an 

executed signature page to this Amendment by facsimile or other electronic transmission (including, without limitation, by Adobe portable 

document format file (also known as a “PDF” file)) shall be as effective as delivery of a manually signed counterpart of this Amendment. 

SECTION 7. Governing Law . This Amendment shall be governed by, and construed in accordance with, the laws of the State of the New 

York. 

SECTION 8. Miscellaneous. This Amendment shall be subject to the provisions of Sections 9.05, 9.07, 9.09, 9.10 and 9.11 of the Existing 

Agreement, each of which is incorporated by reference herein, mutatis mutandis . 

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] 

 

5 
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly 

authorized, as of the date first above written. 

 

 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-1 

 UNISOURCE ENERGY CORPORATION 

 By: /s/ Kentton C. Grant 

 Name: Kentton C. Grant 

 Title: Vice President, Finance & Rates 

 

UNION BANK, N.A ., as Administrative 

Agent, as an Issuing Bank and as a Lender 

 By: /s/ Jeffrey P. Fesenmaier 

 Name: Jeffrey P. Fesenmaier 

 Title: Vice President 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-2 

 

JPMORGAN CHASE BANK, N.A. , as an 

Issuing Bank and as a Lender 

 By: /s/ Nancy R. Barwig 

 Name: Nancy R. Barwig 

 Title: Credit Executive 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-3 

 

WELLS FARGO BANK, NATIONAL ASSOCIATION , as 

an Issuing Bank and as a Lender 

 By: Yann Blindert 

 Name: Yann Blindert 

 Title: Director 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-4 

 SUNTRUST BANK , as a Lender 

 By: /s/ Andrew Johnson 

 Name: Andrew Johnson 

 Title: Director 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-5 

 BANK OF AMERICA, N.A. , as a Lender 

 By: /s/ Kevin P. Bertelsen 

 Name: Kevin P. Bertelsen 

 Title: Managing Director 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-6 

 U.S. BANK NATIONAL ASSOCIATION , as a Lender 

 By: /s/ Raymond J. Palmer 

 Name: Raymond J. Palmer 

 Title: Senior Vice President 
 

 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-7 

 

CREDIT SUISSE AG, CAYMAN ISLANDS 

BRANCH , as a Lender 

 By: /s/ Shaheen Malik 

 Name: Shaheen Malik 

 Title: Vice President 

 By: /s/ Rahul Parmar 

 Name: Rahul Parmar 

 Title: Associate 
 

 

Amendment No. 1 to UniSource Second Amended and Restated Credit Agreement 

 

S-8 

 

THE BANK OF NEW YORK MELLON , as 

a Lender 

 By: /s/ Mark W. Rogers 

 Name: Mark W. Rogers 

 Title: Vice President 
SCHEDULE A 

to Amendment No. 1 to Credit Agreement 

SCHEDULE 1.01 

PRICING SCHEDULE 

The “Applicable Margin” and the “Commitment Fee Rate” for any day (a) from and after the Effective Date through (but not including) the 

Amendment No. 1 Effective Date, are the respective annual percentage rates set forth in Table A below in the applicable row under the column 

corresponding to the Status that exists on such day, and (b) from and after the Amendment No. 1 Effective Date, are the respective annual 

percentages rates set forth in Table B below in the applicable row under the column corresponding to the Status that exists on such day: 

TABLE A 

 

TABLE B 

 

 

Schedule A 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.625 % 1.875 % 2.125 % 2.50 % 3.00 % 3.50 % 

Applicable Margin — ABR Loans 0.625 % 0.875 % 1.125 % 1.50 % 2.00 % 2.50 % 

Commitment Fee Rate 0.175 % 0.225 % 0.350 % 0.450 % 0.600 % 0.750 % 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.00 % 1.125 % 1.25 % 1.50 % 1.75 % 2.00 % 

Applicable Margin — ABR Loans 0.00 % 0.125 % 0.25 % 0.50 % 0.75 % 1.00 % 

Commitment Fee Rate 0.125 % 0.175 % 0.20 % 0.25 % 0.30 % 0.35 % 
For purposes of this Pricing Schedule, the following terms have the following meanings: 

“ Level 1 Status ” exists at any date if, at such date, the Index Debt is rated A- or higher by S&P and A3 or higher by Moody’s. 

“ Level 2 Status ” exists at any date if, at such date (i) the Index Debt is rated BBB+ or higher by S&P and Baa1 or higher by Moody’s and 

(ii) Level 1 Status does not exist. 

“ Level 3 Status ” exists at any date if, at such date (i) the Index Debt is rated BBB or higher by S&P and Baa2 or higher by Moody’s and 

(ii) neither Level 1 Status nor Level 2 Status exists. 

“ Level 4 Status ” exists at any date if, at such date (i) the Index Debt is rated BBB- or higher by S&P and Baa3 or higher by Moody’s and 

(ii) none of Level 1 Status, Level 2 Status or Level 3 Status exists. 

“ Level 5 Status ” exists at any date if, at such date (i) the Index Debt is rated BB+ or higher by S&P and Ba1 or higher by Moody’s and 

(ii) none of Level 1 Status, Level 2 Status, Level 3 Status or Level 4 Status exists. 

“ Level 6 Status ” exists at any date if, at such date, no other Status exists. 

“ Status ” refers to the determination of which of Level 1 Status, Level 2 Status, Level 3 Status, Level 4 Status, Level 5 Status or Level 6 

Status exists at any date. 

Notwithstanding the foregoing, if the Index Debt is split-rated and the ratings differential is two or more ratings levels, the Status shall be 

determined assuming that (a) the lower rating is equal to the midpoint of the two ratings (e.g., for a split rating of BBB+/Baa3, BBB is the 

midpoint and will be deemed to be the lower rating, and for a split rating of BB/Baa1, Baa3 is the midpoint and will be deemed to be the lower 

rating) or (b) if there is no exact midpoint, the lower rating is equal to the lower of the two middle intermediate ratings (e.g., for a split rating of 

BBB+/Ba1, BBB- is the lower of the two middle intermediate ratings and will be deemed to be the lower rating, and for a split rating of 

BB/Baa2, Ba1 is the lower of the two middle intermediate ratings and will be deemed to be the lower rating). 

If at any time the Index Debt is unrated by both Moody’s and S&P, Level 6 Status shall exist; provided that if the reason that there is no 

such Moody’s rating or S&P rating results from Moody’s or S&P, as the case may be, ceasing to issue debt ratings generally, then the Borrower 

and the Administrative Agent may select another nationally-recognized rating agency to substitute for Moody’s or S&P, as applicable, for 

purposes of this Pricing Schedule (and all references herein to Moody’s or S&P, as applicable, shall refer to such substitute rating agency), and 

until a substitute nationally-recognized rating agency is so selected the Status shall be determined by reference to the rating most recently in 

effect prior to such cessation; and provided , further , that if the Index Debt is rated by only one of Moody’s or S&P, the Status shall be 

determined by reference to the rating of such Rating Agency. 

 

Schedule A 
The Applicable Margin and Commitment Fee Rate shall be increased or decreased in accordance with the foregoing Pricing Schedule upon 

any change in the applicable ratings of the Index Debt. The ratings of the Index Debt in effect at any date is that in effect at the close of business 

on such date. 

 

Schedule A 
Exhibit 4(t)(2) 

[Execution Version] 

AMENDMENT NO. 1 

TO 

CREDIT AGREEMENT 

This AMENDMENT NO. 1, dated as of November 18, 2011 (this “ Amendment ”), is made by and among UNS ELECTRIC, INC., an 

Arizona corporation (“ UNS Electric ”), and UNS GAS, INC., an Arizona corporation (“ UNS Gas ”, and together with UNS Electric being 

referred to herein, individually, as a “ Borrower ” and, collectively, as the “ Borrowers ”), UNISOURCE ENERGY SERVICES, INC., an 

Arizona corporation (the “ Guarantor ”), the lenders listed on the signature pages of this Amendment as “Lenders” (such lenders, together with 

their respective permitted assignees from time to time, being referred to herein, collectively, as the “ Lenders ”), JPMORGAN CHASE BANK, 

N.A., WELLS FARGO BANK, NATIONAL ASSOCIATION and UNION BANK, N.A., as issuing banks (collectively, in such capacities, the “

Issuing Banks ”), and UNION BANK, N.A. (formerly known as Union Bank of California, N.A.), as administrative agent (in such capacity, the 

“ Administrative Agent ”). 

PRELIMINARY STATEMENT : 

The Borrowers, the Guarantor, the Lenders and the Administrative Agent previously entered into that certain Second Amended and 

Restated Credit Agreement, dated as of November 9, 2010 (the “ Existing Agreement ”, as amended by this Amendment, the “ Amended 

Agreement ”, and as the Amended Agreement may hereafter be amended, restated, supplemented or otherwise modified from time to time, the “

Credit Agreement ”). The Borrowers desire to amend the Existing Agreement to (a) extend the Final Maturity Date to November 9, 2016, 

(b) reduce the Applicable Margin and the Commitment Fee Rate, and (c) make certain other modifications thereto, and the Lenders, the Issuing 

Banks and the Administrative Agent have agreed to such amendments on the terms and conditions set forth herein. The parties therefore agree as 

follows (capitalized terms used but not defined herein having the meanings assigned to such terms in the Existing Agreement): 

SECTION 1. Amendments to Existing Agreement . The Existing Agreement is, effective as of the date hereof and subject to the 

satisfaction of the conditions precedent set forth in Section 2 hereof, hereby amended as follows: 

(a) Disclosure Documents . The definition of “ Disclosure Documents ” contained in Section 1.01 of the Existing Agreement is hereby 

amended and restated in its entirety to read as follows: 

“ Disclosure Documents ” means (a) the Annual Report on Form 10-K of UniSource Energy for the fiscal year ended December 31, 

2010, as filed with the SEC, (b) the Quarterly Reports on Form 10-Q of UniSource Energy for the fiscal quarters ended March 31, 2011, 

June 30, 2011 and September 30, 2011, as filed with the SEC, and (c) the Current Reports on Form 8-K of UniSource Energy as filed with 

the SEC on May 11, 2011 and August 12, 2011. 
(b) Final Maturity Date . The definition of “ Final Maturity Date ” contained in Section 1.01 of the Existing Agreement is hereby 

amended and restated in its entirety to read as follows: 

“ Final Maturity Date ” means November 9, 2016. 

(c) Additional Definitions . The following new definitions are hereby added to Section 1.01 of the Existing Agreement in appropriate 

alphabetical order: 

“ Amendment No. 1 ” shall mean Amendment No. 1, dated as of November 18, 2011, among the Borrowers, the Guarantor, the 

Issuing Banks, the Lenders and the Administrative Agent, which Amendment No. 1 amended this Agreement pursuant to the terms thereof. 

“ Amendment No. 1 Effective Date ” shall mean November 18, 2011. 

(d) Disclosure; No Material Adverse Change; Etc . Section 7.01(c) of the Existing Agreement is hereby amended by (i) deleting the date 

“December 31, 2009” in its entirety set forth in subsection (ii) thereof and substituting therefor the new date “December 31, 2010” and 

(ii) deleting the phrase “prior to the Closing Date” in its entirety set forth in subsection (iii) thereof and substituting therefor the new phrase 

“prior to the Amendment No. 1 Effective Date”. 

(e) Financial Condition . Section 7.01(d) of the Existing Agreement is hereby amended by (i) deleting each reference to the date 

“December 31, 2009” in its entirety and substituting therefor in each case the new date “December 31, 2010” and (ii) deleting the phrase “to and 

including the date hereof” in its entirety and substituting therefor the new phrase “to and including the Amendment No. 1 Effective Date”. 

(f) Organization and Ownership of Shares of Subsidiaries of each Obligor. Section 7.01(e)(i) of the Existing Agreement is hereby 

amended by deleting the phrase “As of the Closing Date” in its entirety and substituting therefor the new phrase “As of the Amendment No. 1 

Effective Date”. 

(g) Pricing Schedule . Schedule 1.01 of the Existing Agreement is hereby replaced in its entirety with Schedule A attached hereto. 

SECTION 2. Conditions of Effectiveness . This Amendment shall become effective as of the date first written above (the “ Effective Date 

”) when, and only when, (a) the Administrative Agent shall have received all fees (including, without limitation, all upfront fees) payable by the 

Borrowers pursuant to that certain proposal letter agreement, dated October 5, 2011, among Union Bank, the Borrowers, UniSource Energy and 

Tucson Electric Power Company (the “ Proposal Letter ”), together with, to the extent invoiced, reimbursement or payment of all reasonable 

fees and out-of-pocket disbursements of counsel to the Administrative Agent and other out-of-pocket expenses of the Administrative Agent 

required to be reimbursed or paid by the Borrowers pursuant to the Proposal Letter, (b) all requisite Governmental Authorities and third parties, 

if any, shall have approved or consented to the execution, delivery and performance 

 

2 
by the Obligors of this Amendment and the Amended Agreement and the transactions contemplated thereby (collectively, the “ Transactions ”) 

to the extent required and material (and the Administrative Agent shall have received copies, certified by an Authorized Officer of the applicable 

Obligor to be true, correct and complete and in full force and effect, of all such approvals and consents, which shall be in form and substance 

satisfactory to the Administrative Agent and the Lenders), no stay of any applicable regulatory approval shall have been issued and there shall be 

no litigation or governmental, administrative or judicial action, actual or, to the knowledge of the Obligors, threatened, that could reasonably be 

expected to restrain, prevent or impose burdensome conditions on this Amendment, the Amended Agreement, any of the other Loan Documents 

or the Transactions, and (c) the Administrative Agent shall have received: (i) counterparts of this Amendment executed by all of the parties 

hereto (in sufficient quantity for each party to have a fully executed original), and (ii) all of the following documents, each document being dated 

the Effective Date unless otherwise specified below, in form and substance satisfactory to the Administrative Agent and in the number of 

originals or photostatic copies reasonably requested by the Administrative Agent: 

(A) a favorable written opinion (addressed to the Administrative Agent, the Issuing Banks and the Lenders) of (1) Morgan, Lewis & 

Bockius LLP, New York counsel for the Obligors, and (2) Todd C. Hixon, Esq., General Counsel for the Guarantor and counsel for the 

Borrowers, in each case covering such customary matters relating to this Amendment, the Amended Agreement and the Transactions as the 

Administrative Agent shall reasonably request, and the Obligors hereby request such counsel to deliver such opinions; 

(B) such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, 

existence and good standing of the Obligors, the authorization of the Transactions, and any other legal matters relating to the Obligors, this 

Amendment, the Amended Agreement or the Transactions, all in form and substance satisfactory to the Administrative Agent and its 

counsel; 

(C) a certificate (the statements in which shall be true), signed by an Authorized Officer of each Obligor, certifying that: 

(1) the representations and warranties of the Obligors set forth in this Amendment, the Amended Agreement and the other Loan 

Documents are true and correct on and as of the Effective Date with the same effect as though made on and as of such date, except to 

the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties 

were true and correct as of such earlier date); and 

(2) both before and after giving effect to this Amendment, no Default or Event of Default has occurred and is continuing; and 

 

3 
(D) a certificate, signed by an Authorized Officer of each Obligor, confirming compliance with the conditions set forth in this 

Section 2. 

SECTION 3. Representations and Warranties of the Obligors . Each Obligor represents and warrants to the Administrative Agent, each 

Lender and each Issuing Bank that: 

(a) Authorization; Enforceability . Such Obligor has the corporate power and authority to execute and deliver this Amendment and to 

perform the provisions of this Amendment and the Amended Agreement. This Amendment has been duly authorized by all necessary corporate 

action on the part of such Obligor, and each of this Amendment and the Amended Agreement constitutes a legal, valid and binding obligation of 

such Obligor enforceable against such Obligor in accordance with its terms, except as such enforceability may be limited by (i) applicable 

bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally and (ii) general 

principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). This Amendment and has been 

duly executed and delivered by such Obligor. 

(b) Governmental Authorizations . No consent, approval or authorization of, or registration, filing or declaration with, any Governmental 

Authority is required in connection with the execution, delivery or performance by such Obligor of this Amendment, except for the ACC Order, 

which ACC Order has been obtained and is in full force and effect. 

(c) Compliance with Laws, Other Instruments, etc. The execution and delivery by such Obligor of this Amendment, and the performance 

by such Obligor of this Amendment and the Amended Agreement, will not (i) contravene, result in any breach of, or constitute a default under, 

or result in the creation of any Lien in respect of any Property of such Obligor or any of its Subsidiaries under, any indenture, mortgage, deed of 

trust, loan, purchase or credit agreement, lease, corporate charter or by-laws, or any other agreement or instrument to which such Obligor or any 

such Subsidiary is bound or by which such Obligor or any such Subsidiary or any of their respective Properties may be bound or affected, 

(ii) conflict with or result in a breach of any of the terms, conditions or provisions of any order, judgment, decree, or ruling of any court, 

arbitrator or Governmental Authority applicable to such Obligor or any of its Subsidiaries or (iii) violate any provision of any Governmental 

Rule applicable to such Obligor or any of its Subsidiaries. 

(d) Litigation . There are no actions, suits or proceedings pending or, to the knowledge of such Obligor, threatened against or affecting 

such Obligor or any of its Subsidiaries or any Property of such Obligor or any of its Subsidiaries in any court or before any arbitrator of any kind 

or before or by any Governmental Authority that involve this Amendment, the Amended Agreement or the Transactions. 

(e) No Default . No Default or Event of Default has occurred and is continuing or would occur as a result of the execution, delivery or 

performance of this Amendment. 

 

4 
SECTION 4. Reference to and Effect on the Existing Agreement . (a) Upon the effectiveness of this Amendment: (i) each reference in 

the Existing Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Existing Agreement shall mean and 

be a reference to the Amended Agreement; and (ii) each reference in any other Loan Document to “the Credit Agreement”, “thereunder”, 

“thereof” or words of like import referring to the Existing Agreement shall mean and be a reference to the Amended Agreement. This 

Amendment shall constitute a “Loan Document” for all purposes under the Credit Agreement. 

(b) Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects 

ratified and confirmed. 

(c) The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any 

right, power or remedy of the Lenders, the Administrative Agent or the Issuing Banks under the Existing Agreement or any other Loan 

Document, nor constitute a waiver of any provision of the Existing Agreement or any other Loan Document. 

SECTION 5. Costs and Expenses . The Borrowers agree to pay, promptly after delivery to the Borrowers of a reasonably detailed 

statement therefor, all reasonable costs and expenses of the Administrative Agent in connection with the preparation, negotiation, syndication, 

execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder, including, without limitation, the 

reasonable fees and disbursements of counsel to the Administrative Agent with respect thereto and with respect to advising the Administrative 

Agent as to its rights and responsibilities hereunder and thereunder, and all costs and expenses of the Administrative Agent, the Issuing Banks 

and each Lender (including, without limitation, the fees and disbursements of counsel to the Administrative Agent, counsel for each Issuing 

Bank and counsel for each Lender) in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this 

Amendment and the other documents to be delivered hereunder. 

SECTION 6. Execution in Counterparts . This Amendment may be executed in counterparts (and by different parties hereto on different 

counterparts), each of which shall constitute an original but all of which when taken together shall constitute a single contract. Delivery of an 

executed signature page to this Amendment by facsimile or other electronic transmission (including, without limitation, by Adobe portable 

document format file (also known as a “PDF” file)) shall be as effective as delivery of a manually signed counterpart of this Amendment. 

SECTION 7. Governing Law . This Amendment shall be governed by, and construed in accordance with, the laws of the State of the New 

York. 

SECTION 8. Miscellaneous. This Amendment shall be subject to the provisions of Sections 12.09, 12.10, 12.11 and 12.13 of the Existing 

Agreement, each of which is incorporated by reference herein, mutatis mutandis . 

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] 

 

5 
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly 

authorized, as of the date first above written. 

 

 

 

 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-1 

 UNS ELECTRIC, INC. , as a Borrower 

 By: /s/ Kentton C. Grant 

 Name: Kentton C. Grant 

 Title: Vice President 

 UNS GAS, INC. , as a Borrower 

 By: /s/ Kentton C. Grant 

 Name: Kentton C. Grant 

 Title: Vice President 

 UNISOURCE ENERGY SERVICES, INC ., as Guarantor 

 By: /s/ Kentton C. Grant 

 Name: Kentton C. Grant 

 Title: Vice President and Treasurer 

 

UNION BANK, N.A ., as Administrative Agent and as an Issuing 

Bank 

 By: /s/ Jeffrey P. Fesenmaier 

 Name: Jeffrey P. Fesenmaier 

 Title: Vice President 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-2 

 

WELLS FARGO BANK, NATIONAL 

ASSOCIATION, as an Issuing Bank 

 By: /s/ Yann Blindert 

 Name: Yann Blindert 

 Title: Director 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-3 

 JPMORGAN CHASE BANK, N.A. , as an Issuing Bank 

 By: /s/ Nancy R. Barwig 

 Name: Nancy R. Barwig 

 Title: Credit Executive 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-4 

 Lender 

 UNION BANK, N.A . 

 By: /s/ Jeffrey P. Fesenmaier 

 Name: Jeffrey P. Fesenmaier 

 Title: Vice President 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-5 

 Lender 

 WELLS FARGO BANK, NATIONAL ASSOCIATION 

 By: /s/ Yann Blindert 

 Name: Yann Blindert 

 Title: Director 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-6 

 Lender 

 JPMORGAN CHASE BANK, N.A. 

 By: /s/ Nancy R. Barwig 

 Name: Nancy R. Barwig 

 Title: Credit Executive 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-7 

 Lender 

 SUNTRUST BANK 

 By: /s/ Andrew Johnson 

 Name: Andrew Johnson 

 Title: Director 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-8 

 Lender 

 BANK OF AMERICA, N.A. 

 By: /s/ Kevin P. Bertelsen 

 Name: Kevin P. Bertelsen 

 Title: Managing Director 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-9 

 Lender 

 U.S. BANK NATIONAL ASSOCIATION 

 By: /s/ Raymond J. Palmer 

 Name: Raymond J. Palmer 

 Title: Senior Vice President 
 

 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-10 

 Lender 

 CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH 

 By: /s/ Shaheen Malik 

 Name: Shaheen Malik 

 Title: Vice President 

 By: /s/ Rahul Parmer 

 Name: Rahul Parmer 

 Title: Associate 
 

 

Amendment No. 1 to UNS Gas/UNS Electric Second Amended and Restated Credit Agreement 

 

S-11 

 Lender 

 THE BANK OF NEW YORK MELLON 

 By: /s/ Mark W. Rogers 

 Name: Mark W. Rogers 

 Title: Vice President 
SCHEDULE A 

to Amendment No. 1 to Credit Agreement 

SCHEDULE 1.01 

PRICING SCHEDULE 

The “Applicable Margin” and the “Commitment Fee Rate” for any day for any Borrower (a) from and after the Closing Date through (but 

not including) the Amendment No. 1 Effective Date, are the respective annual percentage rates set forth in Table A below in the applicable row 

under the column corresponding to the Status that exists on such day for such Borrower, which Status shall be determined based on the 

applicable ratings of such Borrower’s Index Debt on such day, and (b) from and after the Amendment No. 1 Effective Date, are the respective 

annual percentages rates set forth in Table B below in the applicable row under the column corresponding to the Status that exists on such day 

for such Borrower, which Status shall be determined based on the applicable ratings of such Borrower’s Index Debt on such day: 

TABLE A 

 

TABLE B 

 

 

17 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.625 % 1.875 % 2.125 % 2.50 % 3.00 % 3.50 % 

Applicable Margin — ABR Loans 0.625 % 0.875 % 1.125 % 1.50 % 2.00 % 2.50 % 

Commitment Fee Rate 0.175 % 0.225 % 0.350 % 0.450 % 0.600 % 0.750 % 

 

Level 1 

≥ A-/A3 

Level 2 

BBB+/Baa1 

Level 3 

BBB/Baa2 

Level 4 

BBB-/Baa3 

Level 5 

BB+/Ba1 

Level 6 

≤ BB/Ba2 

Applicable Margin — Eurodollar Loans 1.00 % 1.125 % 1.25 % 1.50 % 1.75 % 2.00 % 

Applicable Margin — ABR Loans 0.00 % 0.125 % 0.25 % 0.50 % 0.75 % 1.00 % 

Commitment Fee Rate 0.125 % 0.175 % 0.20 % 0.25 % 0.30 % 0.35 % 
For purposes of this Pricing Schedule, the following terms have the following meanings: 

“ Level 1 Status ” exists at any date if, at such date, the Index Debt is rated either A- or higher by S&P or A3 or higher by Moody’s. 

“ Level 2 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB+ or higher by S&P or Baa1 or higher by 

Moody’s and (ii) Level 1 Status does not exist. 

“ Level 3 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB or higher by S&P or Baa2 or higher by Moody’s 

and (ii) neither Level 1 Status nor Level 2 Status exists. 

“ Level 4 Status ” exists at any date if, at such date (i) the Index Debt is rated either BBB- or higher by S&P or Baa3 or higher by Moody’s 

and (ii) none of Level 1 Status, Level 2 Status or Level 3 Status exists. 

“ Level 5 Status ” exists at any date if, at such date (i) the Index Debt is rated either BB+ or higher by S&P or Ba1 or higher by Moody’s 

and (ii) none of Level 1 Status, Level 2 Status, Level 3 Status or Level 4 Status exists. 

“ Level 6 Status ” exists at any date if, at such date, no other Status exists. 

“ Status ” refers to the determination of which of Level 1 Status, Level 2 Status, Level 3 Status, Level 4 Status, Level 5 Status or Level 6 

Status exists at any date. 

Notwithstanding the foregoing, if the Index Debt is split-rated and the ratings differential is two or more ratings levels, the Status shall be 

determined assuming that (a) the higher rating is equal to the midpoint of the two ratings (e.g., for a split rating of BBB+/Baa3, BBB is the 

midpoint and will be deemed to be the higher rating, and for a split rating of BB/Baa1, Baa3 is the midpoint and will be deemed to be the higher 

rating) or (b) if there is no exact midpoint, the higher rating is equal to the higher of the two middle intermediate ratings (e.g., for a split rating of 

BBB+/Ba1, BBB is the higher of the two middle intermediate ratings and will be deemed to be the higher rating, and for a split rating of 

BB/Baa2, Ba3 is the higher of the two middle intermediate ratings and will be deemed to be the higher rating). 

If at any time the Index Debt is unrated by both Moody’s and S&P, Level 6 Status shall exist; provided that if the reason that there is no 

such Moody’s rating or S&P rating results from Moody’s or S&P, as the case may be, ceasing to issue debt ratings generally, then the Borrowers 

and the Administrative Agent may select another nationally-recognized rating agency to substitute for Moody’s or S&P, as applicable, for 

purposes of this Pricing Schedule (and all references herein to Moody’s or S&P, as applicable, shall refer to such substitute rating agency), and 

until a substitute nationally-recognized rating agency is so selected the Status shall be determined by reference to the rating most recently in 

effect prior to such cessation; and provided , further , that if the Index Debt is rated by only one of Moody’s or S&P, the Status shall be 

determined by reference to the rating of such Rating Agency. 

 
The Applicable Margin and Commitment Fee Rate applicable to any Borrower (and, accordingly, the Status of such Borrower at any date) 

shall be based on the applicable ratings in effect from time to time on such Borrower’s Index Debt. The Applicable Margin and Commitment Fee 

Rate applicable to each Borrower shall be increased or decreased in accordance with the foregoing Pricing Schedule upon any change in the 

applicable ratings of the Index Debt of such Borrower. The ratings of the Index Debt in effect at any date is that in effect at the close of business 

on such date. 

 
Exhibit 12a 

UniSource Energy Corporation 

Computation of Ratio of Earnings to Fixed Charges 

 

* As revised. See Note 1 to the financial statements for more information. 

(1) Excludes recognition of Allowance for Borrowed Funds Used During Construction. 

 12 Months Ended 

 

Dec 31, 

2011 

Dec. 31, 

2010* 

Dec. 31, 

2009* 

Dec. 31, 

2008* 

Dec. 31, 

2007* 

Dec. 31, 

2006* 

 - Thousands of Dollars - 

Fixed Charges: 

Interest on Long-Term Debt $ 73,217 $ 65,020 $ 58,134 $ 70,227 $ 73,095 $ 75,039 

Other Interest (1) 2,535 1,651 3,468 1,837 5,480 7,922 

Interest on Capital Lease Obligations 44,874 52,540 53,682 57,272 64,499 72,586 

Estimated Interest Portion of Rental 

Expense 926 240 345 188 258 326 

 

Total Fixed Charges $ 121,552 $ 119,451 $ 115,629 $ 129,524 $ 143,332 $ 155,873 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income $ 109,975 $ 112,984 $ 105,901 $ 16,955 $ 60,712 $ 68,524 

Add: 

Discontinued Operations Loss-Net of 

Tax — — — — — 1,796 

 

Net Income from Continuing Operations 109,975 112,984 105,901 16,955 60,712 70,320 

Add (Deduct): 

(Income) Losses from Equity 

Investees — 5,570 1,834 713 340 (210 ) 

Income Taxes 66,951 76,921 63,232 18,747 40,274 42,143 

Total Fixed Charges 121,552 119,451 115,629 129,524 143,332 155,873 

 

Total Earnings before Taxes and Fixed 

Charges $ 298,478 $ 314,926 $ 286,596 $ 165,939 $ 244,658 $ 268,126 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges 2.456 2.636 2.479 1.281 1.707 1.720 
Exhibit 12b 

Tucson Electric Power Company 

Computation of Ratio of Earnings to Fixed Charges 

 

 

 

 12 Months Ended 

 

Dec. 31, 

2011 

Dec. 31, 

2010* 

Dec. 31, 

2009* 

Dec. 31, 

2008* 

Dec. 31, 

2007* 

Dec. 31, 

2006* 

 - Thousands of Dollars - 

Fixed Charges: 

Interest on Long-Term Debt $ 49,858 $ 42,378 $ 36,226 $ 47,456 $ 50,230 $ 51,422 

Other Interest (1) 1,127 433 1,571 1,367 4,538 6,436 

Interest on Capital Lease Obligations 44,874 52,534 53,670 57,252 64,477 72,556 

Estimated Interest Portion of Rental Expense 795 72 106 130 160 188 

 

Total Fixed Charges $ 96,654 $ 95,417 $ 91,573 $ 106,205 $ 119,405 $ 130,602 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income $ 85,334 $ 108,260 $ 90,688 $ 7,206 $ 55,591 $ 67,306 

Add (Deduct): 

(Income) Losses from Equity Investees — — — (1,381 ) — (320 ) 

Income Taxes 52,000 59,936 54,220 12,729 36,940 42,845 

Total Fixed Charges 96,654 95,417 91,573 106,205 119,405 130,602 

 

Total Earnings before Taxes and Fixed Charges $ 233,988 $ 263,613 $ 236,481 $ 124,759 $ 211,936 $ 240,433 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges 2.421 2.763 2.582 1.175 1.775 1.841 

* As revised. See Note 1 to the financial statements for more information. 

(1) Excludes recognition of Allowance for Borrowed Funds Used During Construction. 
Exhibit 21 

UniSource Energy Corporation Subsidiaries 

 

Subsidiary 

State or Other Jurisdiction of 

Incorporation or Organization 

Tucson Electric Power Company (TEP) Arizona 

TEP Subsidiaries: 

San Carlos Resources Inc. Arizona 

Escavada Company. Arizona 

UniSource Energy Services, Inc. (UES) Arizona 

UES Subsidiaries: 

UNS Electric, Inc. Arizona 

UNS Gas, Inc. Arizona 
Exhibit 23a 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Nos. 333-43765, 333-43767, 333-

43769, 333-53309, 333-53333, 333-99317,333-140353, 333-156491 and 333-175001) and on Form S-3 (No. 333-159244) of 

UniSource Energy Corporation of our report dated February 27, 2012 relating to the financial statements, financial statement 

schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. 

 

/s/PricewaterhouseCoopers LLP 

PricewaterhouseCoopers LLP 

Phoenix, Arizona 

February 27, 2012 
Exhibit 23b 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-159244-01) of Tucson 

Electric Power Company of our report dated February 27, 2012 relating to the financial statements and financial statement 

schedule, which appears in this Form 10-K. 

 

/s/PricewaterhouseCoopers LLP 

PricewaterhouseCoopers LLP 

Phoenix, Arizona 

February 27, 2012 
Exhibit 24(a) 

Power of Attorney 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, 

Principal Accounting Officer, officers and/or directors of UniSource Energy Corporation, an Arizona corporation, which corporation 

proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 

2011, under the Securities Exchange Act of 1934, as amended, does each for himself and not for one another, hereby constitute 

and appoint Kevin P. Larson, Todd C. Hixon, and Karen G. Kissinger and each of them, his true and lawful attorneys, in his name, 

place and stead, to sign his name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to 

cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said 

attorneys, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the 

premises as fully and to all intents and purposes as the undersigned could do if personally present; and each of the undersigned for 

himself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or cause to be done by virtue 

hereof. 
IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 27 of February 2012.

 

/s/ Paul J. Bonavia /s/ Robert A. Elliott 

 

Paul J. Bonavia 

Principal Executive Officer 

and Chairman of the Board of 

Directors 

 

Robert A. Elliott, Director 

/s/ Kevin P. Larson /s/ Daniel W.L. Fessler 

 

Kevin P. Larson 

Principal Financial Officer 

 

Daniel W.L. Fessler, Director 

/s/ Karen G. Kissinger /s/ Louise L. Francesconi 

 

Karen G. Kissinger 

Principal Accounting Officer 

 

Louise L. Francesconi, Director 

/s/ Lawrence J. Aldrich /s/ Warren Y. Jobe 

 

Lawrence J. Aldrich, Director 

 

Warren Y. Jobe, Director 

/s/ Barbara M. Baumann /s/ Ramiro G. Peru 

 

Barbara M. Baumann, Director 

 

Ramiro G. Peru, Director 

/s/ Larry W. Bickle /s/ Gregory A. Pivirotto 

 

Larry W. Bickle, Director 

 

Gregory A. Pivirotto, Director 

/s/ Harold W. Burlingame /s/ Joaquin Ruiz 

 

Harold W. Burlingame, Director 

 

Joaquin Ruiz, Director 

th 
Exhibit 24(b) 

Power of Attorney 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, 

Principal Accounting Officer, officers and/or directors of Tucson Electric Power Company, an Arizona corporation, which 

corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended 

December 31, 2011, under the Securities Exchange Act of 1934, as amended, does each for himself and not for one another, 

hereby constitute and appoint Kevin P. Larson, Todd C. Hixon, and Karen G. Kissinger and each of them, his true and lawful 

attorneys, in his name, place and stead, to sign his name to said proposed Annual Report on Form 10-K and any and all 

amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant 

and hereby granting to said attorneys, and each of them, full power and authority to do and perform any act and thing necessary 

and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; 

and each of the undersigned for himself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or 

cause to be done by virtue hereof. 
IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 27 day of February, 2012. 

 

 

 

 

 

/s/ Paul J. Bonavia 

Paul J. Bonavia 

Principal Executive Officer 

and Chairman of the Board of 

Directors 

/s/ Kevin P. Larson 

Kevin P. Larson 

Principal Financial Officer and Director 

/s/ Karen G. Kissinger 

Karen G. Kissinger 

Principal Accounting Officer 

/s/ Michael J. DeConcini 

Michael J. DeConcini 

Director 

/s/ David G. Hutchens 

David G. Hutchens 

Director 

th 
Exhibit 31(a) 

CERTIFICATION 

Pursuant to Section 302 of the Sarbanes-Oxley Act 

I, Paul J. Bonavia, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: February 27, 2012 

 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2011, of UniSource Energy Corporation; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not 

misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods 

presented in this report; 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 

defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, 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; 

 

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this 

report based on such evaluation; and 

 

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons 

performing the equivalent functions): 

 

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting 

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial 

information; and 

 

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ Paul J. Bonavia 

 Paul J. Bonavia 

 Chairman and Principal Executive Officer 
Exhibit 31(b) 

CERTIFICATION 

Pursuant to Section 302 of the Sarbanes-Oxley Act 

I, Kevin P. Larson, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: February 27, 2012 

 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2011, of UniSource Energy Corporation; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not 

misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods 

presented in this report; 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 

defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

 

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, 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; 

 

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this 

report based on such evaluation; and 

 

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons 

performing the equivalent functions): 

 

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting 

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial 

information; and 

 

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ Kevin P. Larson 

Kevin P. Larson 

Senior Vice President, Treasurer and Principal Financial Officer 
Exhibit 31(c) 

CERTIFICATION 

Pursuant to Section 302 of the Sarbanes-Oxley Act 

I, Paul J. Bonavia, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: February 27, 2012 

 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2011, of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not 

misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods 

presented in this report; 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 

defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have: 

 

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, 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; 

 

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this 

report based on such evaluation; and 

 

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons 

performing the equivalent functions): 

 

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting 

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial 

information; and 

 

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ Paul J. Bonavia 

Paul J. Bonavia 

Chairman and Principal Executive Officer 
Exhibit 31(d) 

CERTIFICATION 

Pursuant to Section 302 of the Sarbanes-Oxley Act 

I, Kevin P. Larson, certify that: 

 

 

 

 

 

 

 

 

 

 

 

Date: February 27, 2012 

 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact 

necessary to make the statements made, in light of the circumstances under which such statements were made, not 

misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all 

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods 

presented in this report; 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 

defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have: 

 

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 

under our supervision, to ensure that material information relating to the registrant, including its consolidated 

subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 

being prepared; 

 

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be 

designed under our supervision, 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; 

 

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this 

report based on such evaluation; and 

 

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the 

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons 

performing the equivalent functions): 

 

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting 

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial 

information; and 

 

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting. 

/s/ Kevin P. Larson 

Kevin P. Larson 

Senior Vice President and Principal Financial Officer 
Exhibit 32 

UNISOURCE ENERGY CORPORATION 

TUCSON ELECTRIC POWER COMPANY 

 

STATEMENTS OF CORPORATE OFFICERS 

(Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) 

 

Each of the undersigned, Paul J. Bonavia, Chairman of the Board and Principal Executive Officer of UniSource Energy 

Corporation and Tucson Electric Power Company (each a “Company”), and Kevin P. Larson, Senior Vice President and Principal 

Financial Officer of each Company, hereby certifies, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that each 

Company’s Annual Report on Form 10-K for the year ended December 31, 2011, fully complies with the requirements of Section 13

(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all 

material respects, the financial condition and results of operations of such Company. 

February 27, 2012 

 

 

 

 

/s/ Paul J. Bonavia 

Paul J. Bonavia 

Chairman of the Board and 

Principal Executive Officer 

UniSource Energy Corporation 

Tucson Electric Power Company 

/s/ Kevin P. Larson 

Kevin P. Larson 

Senior Vice President and 

Principal Financial Officer 

UniSource Energy Corporation 

Tucson Electric Power Company