10-K 1 form10-k.htm ANNUAL REPORT form10-k.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
(Mark One)
[ X ]      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF      
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
[   ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission
File Number
Registrant; State of Incorporation;
Address; and Telephone Number
IRS Employer
Identification Number
     
1-13739
UNISOURCE ENERGY CORPORATION
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ  85701
(520) 571-4000
86-0786732
     
1-5924
TUCSON ELECTRIC POWER COMPANY
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ  85701
(520) 571-4000
86-0062700

Securities registered pursuant to Section 12(b) of the Act:
  
 
Registrant
 
Title of Each Class
Name of Each Exchange
on Which Registered
     
UniSource Energy Corporation
Common Stock, no par value, and
Preferred Share Purchase Rights
New York Stock Exchange
 

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act.
 
UniSource Energy Corporation
Yes
X
No
    
 
Tucson Electric Power Company
Yes
  
No
X
  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act.
 
UniSource Energy Corporation
Yes
  
No
X
  
 
Tucson Electric Power Company
Yes
X
No
    

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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.  Yes    X       No____

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 definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):
 
 
UniSource Energy Corporation
Large Accelerated Filer
X
Accelerated Filer
  
Non-accelerated filer
    
 
Smaller Reporting Company
    

Tucson Electric Power Company
Large Accelerated Filer
  
Accelerated Filer
  
Non-accelerated filer
X
  
 
Smaller Reporting Company
    

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
 
UniSource Energy Corporation
Yes
  
No
X
  
 
Tucson Electric Power Company
Yes
  
No
X
  

The aggregate market value of UniSource Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,148,148,938 based on the last reported sale price thereof on the consolidated tape on June 30, 2007.

At February 26, 2008, 35,389,434 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.

At February 26, 2008, 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 2008 Annual Meeting of Shareholders are incorporated by reference into Part III.
 
 
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The abbreviations and acronyms used in the 2007 Form 10-K are defined below:
 
 
ACC
Arizona Corporation Commission.
ACC Holding Company Order
The order approved by the ACC in November 1997 allowing TEP to form a holding company.
AECC
Arizonans for Electric Choice and Competition.
AMT
Alternative Minimum Tax.
APS
Arizona Public Service Company.
BMGS
Black Mountain Generating Station under development by UED.
Btu
British thermal unit(s).
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.
Citizens
Citizens Communications Company.
Collateral Trust Bonds
Bonds issued under the Indenture of Trust, dated as of August 1, 1998, of TEP to The Bank of New York, successor trustee.
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.
Emission Allowance(s)
An allowance issued by the Environmental Protection Agency which permits emission of one ton of sulfur dioxide or one ton of nitrogen oxide.  These 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.
ESP
Energy Service Provider.
FAS 71
Statement of Financial Accounting Standards No. 71: Accounting for the Effects of Certain Types of Regulation.
FAS 133
Statement of Financial Accounting Standards No. 133: Accounting for Derivative Instruments and Hedging Activities, as amended.
FAS 143
Statement of Financial Accounting Standards No. 143: Accounting for Asset Retirement Obligations.
FERC
Federal Energy Regulatory Commission.
Fixed CTC
Competition Transition Charge of approximately $0.009 per kWh that is included in TEP’s retail rate for the purpose of recovering TEP’s $450 million TRA by December 31, 2008.
Four Corners
Four Corners Generating Station.
Global Solar
Global Solar Energy, Inc., a company that develops and manufactures thin-film photovoltaic cells.  Millennium sold its interest in Global Solar in March 2006.
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.
ICRA
Implementation Cost Regulatory Asset.
IDBs
Industrial development revenue or pollution control revenue bonds.
IPS
Infinite Power Solutions, Inc., a company that develops thin-film batteries. Millennium owns 8.9% of IPS.
IRS
Internal Revenue Service.
ISO
Independent System Operator.
ITC
Investment Tax Credit.
kWh
Kilowatt-hour(s).
 
 
kV
Kilovolt(s).
LIBOR
London Interbank Offered Rate.
Luna
Luna Energy Facility.
Mark-to-Market Adjustments
Forward energy sales and purchase contracts that are considered to be derivatives are adjusted monthly by recording unrealized gains and losses to reflect the market prices at the end of each month.
MEG
Millennium Environment Group, Inc., a wholly-owned subsidiary of Millennium, which manages and trades emission allowances and related financial instruments.
MicroSat
MicroSat Systems, Inc. is a company formed to develop and commercialize small-scale satellites.  Millennium currently owns 35%.
Millennium
Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UniSource Energy.
MMBtu
Million British Thermal Units.
Mortgage
TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York, successor trustee, as supplemented.
Mortgage Bonds
Bonds issued under the Mortgage.
MW
Megawatt(s).
MWh
Megawatt-hour(s).
Navajo
Navajo Generating Station.
NOL
Net Operating Loss carryback or carryforward for income tax purposes.
PGA
Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers.
Phelps Dodge Decision
An Arizona Court of Appeals decision issued in 2005 that invalidated portions of the ACC’s Retail Electric Competition Rules.
PNM
Public Service Company of New Mexico.
PNMR
PNM Resources.
Powertrusion
POWERTRUSION International, Inc., a company owned 77% by Millennium, which manufactures lightweight utility poles.
PPFAC
Purchased Power and Fuel Adjustment Clause.
PWMT
Pinnacle West Marketing and Trading.
REST
Renewable Energy Standard and Tariff rules approved by the ACC in October 2006.
Repurchased Bonds
$221 million of fixed-rate tax-exempt bonds that TEP purchased from bondholders on May 11, 2005.
RTO
Regional Transmission Organization.
RUCO
Residential Utility Consumer Office.
Rules
Retail Electric Competition Rules.
Sabinas
Carboelectrica Sabinas, S. de R.L. de C.V., a Mexican limited liability company.  Millennium owns 50% of Sabinas.
San Carlos
San Carlos Resources Inc., a wholly-owned subsidiary of TEP.
San Juan
San Juan Generating Station.
SES
Southwest Energy Solutions, Inc., a wholly-owned subsidiary of Millennium.
Settlement Agreement
TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery.
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.
 
 
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.
TCRA
Termination Cost Regulatory Asset.
TEP
Tucson Electric Power Company, the principal subsidiary of UniSource Energy.
TEP Credit Agreement
Amended and Restated Credit Agreement between TEP and a syndicate of Banks, dated as of August 11, 2006.
TEP Guarantee Home Program
The TEP Home Guarantee Program provides incentives to new home builders to construct homes that meet high construction and energy-efficiency standards.
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).
TOU
Time of use.
Track A
An order issued by the ACC in 2002 which granted a waiver from the requirement in TEP’s Settlement Agreement that TEP transfer its generating assets to a subsidiary.
TRA
Transition Recovery Asset, a $450 million regulatory asset established in TEP’s 1999 Settlement Agreement to be fully recovered by December 31, 2008.
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.
UES Settlement Agreement
An agreement with the ACC Staff dated April 1, 2003, addressing rate case and financing issues in the acquisition by UniSource Energy of Citizens’ Arizona gas and electric assets.
UniSource Credit Agreement
Amended and Restated Credit Agreement between UniSource Energy and a syndicate of banks, dated as of August 11, 2006.
UniSource Energy
UniSource Energy Corporation.
UNS Electric
UNS Electric, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona electric utility assets in 2003.
UNS Gas
UNS Gas, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona gas utility assets in 2003.
UNS Gas/UNS Electric Revolver
Revolving credit facility under the 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 August 11, 2006.
Valencia
Valencia power plant owned by UNS Electric.



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 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.

ITEM 1. – BUSINESS

OVERVIEW OF CONSOLIDATED BUSINESS
 
UniSource Energy is a holding company that has no significant operations of its own.  Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities.  UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).  We conduct our business in three primary business segments – TEP, UNS Gas and UNS Electric.

TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years.  UES was established in 2003 when it acquired the Arizona gas and electric properties from Citizens.  UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in Northern and Southern Arizona.  Millennium has existing investments in unregulated businesses; no new investments are planned in Millennium.  On March 31, 2006, Millennium sold its interest in Global Solar Energy, Inc. (Global Solar), its largest holding.  UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to ACC approval, is expected to provide energy to UNS Electric.  

UniSource Energy was incorporated in the State of Arizona in 1995 and obtained regulatory approval to form a holding company in 1997.  In 1998, TEP and UniSource Energy exchanged shares of stock resulting in TEP becoming a subsidiary of UniSource Energy.  Following the share exchange, TEP transferred the stock of its subsidiary Millennium to UniSource Energy.

BUSINESS SEGMENT CONTRIBUTIONS

The table below shows the contributions to our consolidated after-tax earnings by our three business segments and Other net income (loss).

 
2007
2006
2005
 
-Millions of Dollars-
TEP
$    53
$    67
$    49
UNS Gas
       4
       4
       5
UNS Electric
       5
       5
       5
Other (1)
       (4)
       (7)
       (7)
Income Before Discontinued Operations and
Cumulative Effect of Accounting Change
     58
     69
      52
Discontinued Operations – Net of Tax (2)
    -
      (2)
       (5)
Cumulative Effect of Accounting Change – Net of Tax
    -
     -
       (1)
Consolidated Net Income
$    58
$    67
$    46
 
 
(1) Includes: UniSource Energy parent company expenses; interest expense on the note payable from UniSource Energy to TEP in 2005 and 2006; income and losses from Millennium investments and UED,  interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement in 2007 and 2006; and, 2005 includes costs associated with the proposed acquisition of UniSource Energy by an unrelated party.

(2) Relates to the discontinued operations of Global Solar.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Outlook and Strategies, for a discussion of our plans and strategies and Rates and Regulation, below, for the status of competition in Arizona.

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

TEP ELECTRIC UTILITY OPERATIONS

TEP was incorporated in the State of Arizona in 1963.  TEP is the principal operating subsidiary of UniSource Energy.  In 2007, TEP’s electric utility operations contributed 77% of UniSource Energy’s operating revenues and comprised 80% of its assets.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to more than 397,000 retail customers in Southeastern Arizona.  TEP’s service territory consists of a 1,155 square mile area and includes a population of over 1 million in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County.  TEP holds a franchise to provide electric distribution service to customers in the Cities of Tucson and South Tucson. These franchises expire in 2026 and 2017, respectively.  TEP also sells electricity to other utilities and power marketing entities in the Western U.S.

Retail Customers

TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers.  Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases and other governmental entities.  TEP’s retail sales are influenced by several factors, including seasonal weather patterns and overall economic climate.

Local, regional, and national economic factors can impact the financial condition and operations of TEP’s large industrial customers. Such economic conditions may directly impact energy consumption by large industrial customers and may indirectly impact residential and small commercial sales and revenues if employment levels and consumer spending change.

 In 2007, TEP’s average number of retail customers increased by approximately 2% and total retail kWh sales increased by 5%. The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years.

 
2007
2006
2005
Residential
42%
41%
41%
Commercial
21%
21%
21%
Non-mining Industrial
24%
25%
26%
Mining
10%
10%
9%
Public Authority
3%
3%
3%

TEP expects the number of its retail customers to increase 2% annually through 2012.  TEP’s historic customer growth rate averaged 2-3%; however, future projections are lower due to general economic conditions.  The retail energy consumption by customer class through 2010 is expected to be similar to the 2007 distribution.

In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however by 2002, none of TEP’s retail customers were served by an alternate ESP.  Certain portions of the ACC rules that enabled ESPs to compete in the retail market were invalidated by an Arizona Court of Appeals decision
 
 
in 2005. Unless and until the ACC clarifies the competition rules and ESPs offer to provide energy in TEP’s service area, it is not possible for TEP’s retail customers to use other energy providers.  Even if some of TEP’s retail customers are, in the future, able to choose other energy providers, the forecasted customer growth rates referred to above would continue to apply to TEP’s distribution business.  See Rates and Regulation, State, below.

Wholesale Business

TEP’s electric utility operations include the wholesale marketing of electricity to other utilities and power marketers.  Wholesale sales transactions are made on both a firm and interruptible basis.  A firm contract requires TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions.  See Purchases and Interconnections, below.

TEP typically uses its own generation to serve the requirements of its retail and long-term wholesale customers.  Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified portfolio approach to provide a balance between long-term, mid-term and spot energy sales.  When TEP expects to have excess coal generating capacity and energy (usually in the first, second and fourth calendar quarters), its wholesale sales consist primarily of two types of sales:

(1)  Long-term sales contracts for periods of more than one year.  TEP currently has long-term contracts with three entities to sell firm capacity and energy:  Salt River Project Agricultural Improvement and Power District (SRP), which will expire in May 2016, the Navajo Tribal Utility Authority, which expires in December 2015, and the Tohono O’odham Utility Authority, which expires in August 2009.

(2)  Short-term sales.  Under forward contracts, TEP commits to sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one-month, three-month or one-year periods.  Under short-term sales, TEP sells energy in the daily or hourly markets at fluctuating spot market prices and makes other non-firm energy sales.

Over the past three years, both the natural gas and the Western U.S. wholesale electricity markets experienced some price spikes and volatility due to severe winter weather, gas production and storage concerns and, in 2005, hurricane activity in the Gulf of Mexico.  TEP cannot predict, however, whether gas and wholesale electricity prices will remain volatile or how these prices will impact TEP’s sales and revenues in the future.

TEP expects the market price in the Western U.S. and the demand for capacity and energy to continue to be influenced by the following factors, among others:

·           availability and price of natural gas;
·           weather;
·           continued population growth in the Western U.S.;
·           economic conditions in the Western U.S.;
·           availability of generation capacity throughout the Western U.S.;
·           environmental regulations and the cost of compliance;
·           transmission constraints;
·           the extent of electric utility restructuring in Arizona, California and other Western states;
·           FERC regulation of wholesale energy markets; and
·           the availability of hydropower.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Market Prices, for additional discussion of TEP’s wholesale marketing activities.
 

GENERATING AND OTHER RESOURCES

At December 31, 2007, TEP owned or leased 2,204 MW of net generating capability, as set forth in the following table:

         
Net
    
 
Unit
  
Date
Fuel
Capability
Operating
TEP’s Share
Generating Source
No.
Location
In Service
Type
MW
Agent
%
MW
Springerville Station(1)
1
Springerville, AZ
1985
Coal
380
TEP
100.0
380
Springerville Station
2
Springerville, AZ
1990
Coal
390
TEP
100.0
390
San Juan Station
1
Farmington, NM
1973
Coal
327
PNM
  50.0
164
San Juan Station
2
Farmington, NM
1980
Coal
316
PNM
  50.0
158
Navajo Station
1
Page, AZ
1974
Coal
750
SRP
    7.5
  56
Navajo Station
2
Page, AZ
1975
Coal
750
SRP
    7.5
  56
Navajo Station
3
Page, AZ
1976
Coal
750
SRP
    7.5
  56
Four Corners Station
4
Farmington, NM
1969
Coal
784
APS
    7.0
  55
Four Corners Station
5
Farmington, NM
1970
Coal
784
APS
    7.0
  55
Luna Energy Facility
1
Deming, NM
2006
Gas
570
PNM
  33.3
190
Sundt Station
1
Tucson, AZ
1958
Gas/Oil
  81
TEP
100.0
  81
Sundt Station
2
Tucson, AZ
1960
Gas/Oil
  81
TEP
100.0
  81
Sundt Station
3
Tucson, AZ
1962
Gas/Oil
104
TEP
100.0
104
Sundt Station(1)
4
Tucson, AZ
1967
Coal/Gas
156
TEP
100.0
156
Internal Combustion Turbines
  
Tucson, AZ
1972
Gas/Oil
122
TEP
100.0
122
Internal Combustion Turbines
  
Tucson, AZ
2001
Gas
  95
TEP
100.0
 95
Solar Electric Generation
  
Springerville/
Tucson, AZ
2002-2005
Solar
    5
TEP
100.0
   5
Total TEP Capacity (2)
              
2,204

(1) Leased assets.

 (2) Excludes 860 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2007, total owned capacity was 1,668 MW and leased capacity was 536 MW.

Springerville Generating Station

Springerville Unit 1 is leased by TEP.  The Springerville Generating Station also includes the Springerville Coal Handling Facilities and the Springerville Common Facilities.

The terms of the Springerville Unit 1 Leases, which include a 50% interest in the Springerville Common Facilities, expire in 2015, but have optional fair market value renewal and purchase provisions.  In 1985, TEP sold and leased back its remaining 50% interest in the Springerville Common Facilities.   The terms of the Springerville Common Facilities Leases expire in 2017 and 2021, but have a fixed price purchase provision.   In 1984, TEP sold and leased back the Springerville Coal Handling Facilities.  The terms of the Springerville Coal Handling Facilities Leases expire in 2015, but have a fixed price purchase provision.

Since entering into the Springerville leases, TEP has purchased a 14% equity ownership interest in the Springerville Unit 1 Leases and a 13% equity ownership interest in the Springerville Coal Handling Facilities Leases.

Sundt Generating Station

The Sundt Generating Station and the internal combustion turbines located in Tucson are designated as “must-run generation” facilities.  Must-run generation units are required to run in certain circumstances to maintain distribution system reliability and to meet local load requirements.

Sundt Unit 4 is leased by TEP.  The terms of the Sundt Lease expire in 2011, but have optional fair market value renewal and purchase provisions.

See Note 7 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, and Capital Lease Obligations, and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson
 
 
Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for more information regarding the Springerville and Sundt leases.

Luna Energy Facility

The Luna Energy Facility (Luna), located in Southern New Mexico, is a 570 MW combined cycle plant and was completed in 2006. TEP’s one-third share of the plant’s capacity is 190 MW.  Luna allows TEP to displace some of its less efficient gas-fired generation and purchased power requirements and to make additional short-term energy sales in the wholesale market.

Purchases and Interconnections

TEP purchases power from other utilities and power marketers.  TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy for resale to certain wholesale customers under load and resource management agreements.

TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers.  Some of these purchased power contracts are price indexed to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years.  TEP also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when it is more economical than generating its own energy.

TEP is a member of various regional reserve sharing, reliability and power sharing organizations.  These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry.

Springerville Units 3 and 4

Springerville Unit 3, which commenced commercial operation in July 2006, is a 400 MW coal-fired generating facility located at the same site as Springerville Units 1 and 2.  Tri-State is leasing 100% of Unit 3 from a financial owner.  TEP allocates a portion of the fixed costs of the existing common facilities to the additional generating unit.  TEP operates Unit 3 and receives annual pre-tax benefits in the form of transmission revenues, rental payments and other fees and cost savings.  As part of the project to develop Springerville Unit 3, Tri-State provided funding to improve sulfur dioxide scrubbers, low-nitrogen oxide burners and other emission control upgrades for Units 1 and 2, which were completed in 2005.

In May 2006, SRP announced its intention to build Unit 4, a 400 MW coal-fired generating facility at the same Springerville site.  Unit 4 is under construction and, under the terms of the existing siting permit, is required to be completed by December 31, 2009.  Prior to Unit 4’s completion, TEP may be required, along with Tri-State, to exercise best efforts to find a replacement purchaser for SRP to purchase 100 MW of capacity from Unit 3.  If TEP and Tri-State are unable to find such a replacement purchaser, TEP would then purchase 100 MW of output from Unit 4, beginning with the commercial operation of Unit 4.  Given the current level of wholesale power market prices, we believe it is unlikely that TEP would be required to find a replacement purchaser or to purchase SRP’s 100 MW.  See Item 7. – Management’s Discussion and Analysis of Financial Condition. Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Units 3 and 4.
 

Peak Demand and Resources

Peak Demand
2007
2006
2005
2004
2003
 
-MW-
Retail Customers
2,386
2,365
2,225
2,088
2,060
Firm Sales to Other Utilities
   369
   331
   342
  187
  171
Coincident Peak Demand (A)
2,755
2,696
2,567
2,275
2,231
 
 
 
 
 
 
Total Generating Resources
2,204
2,194
2,004
2,004
2,003
Other Resources (1)
   785
   719
   788
  454
   486
Total TEP Resources (B)
2,989
2,913
2,792
2,458
2,489
 
 
 
 
 
 
Total Margin (B) – (A)
   234
   217
   225
  183
  258
Reserve Margin (% of Coincident Peak Demand)
    8%
   8%
   9%
   8%
 12%

(1) Other Resources include firm power purchases and interruptible retail and wholesale loads.

Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers.  Retail peak demand has grown at an average annual rate of approximately 4% from 2003 to 2007, but can vary year-to-year due to weather, economic conditions and other factors.

The chart above shows the relationship over a five-year period between TEP’s peak demand and its energy resources.  TEP’s margin is the difference between total energy resources and coincident peak demand, and the reserve margin is the ratio of margin to coincident peak demand.  TEP maintains a minimum reserve margin in excess of 7% to comply with reliability criteria set forth by the Western Electricity Coordinating Council.  TEP’s actual reserve margin in 2007 was 8%.

Forecasted retail peak demand for 2008 is approximately 2,456 MW, compared with actual peak demand of 2,386 MW in 2007.  Except for certain peak hours during the summer, when TEP will acquire power in the spot market,  TEP believes it will have sufficient resources to meet expected demand in 2008 with its existing generation capacity and power purchase agreements.

Future Generating Resources

TEP will continue to add peaking resources to serve the Tucson area as needed based upon our forecasts of retail and firm wholesale load, as well as statewide transmission infrastructure.  TEP’s current forecast projects that additional import capacity and/or additional local generation resources of 75 to 150 MW will be required in the 2012 to 2015 time frame.

FUEL SUPPLY

Fuel Summary

Fuel cost and usage information is provided below:

 
Average Cost per MMBtu
Percentage of Total Btu
   
Consumed
    
Consumed
  
 
2007
2006
2005
2007
2006
2005
Coal
$1.81
$1.69
$1.69
  92%
  94%
  96%
Gas
$8.30
$7.03
$8.09
   8%
   6%
   4%
All Fuels
$2.30
$2.03
$1.93
100%
100%
100%

Coal

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona, New Mexico and Colorado.  The majority of its coal supplies are purchased under long-term contracts, which result in more predictable prices.  The average cost per ton of coal, including transportation, for 2007, 2006, and 2005 was $34.71, $32.36, and $32.43, respectively.
 

     
Average
  
   
Contract
Sulfur
  
Station
Coal Supplier
Expiration
Content
Coal Obtained From (A)
Springerville
Peabody Coalsales Company
2020
0.9%
   Lee Ranch Coal Company
Four Corners
BHP Billiton
2016
0.8%
   Navajo Indian Tribe
San Juan
San Juan Coal Company
2017
0.8%
   Federal and State Agencies
Navajo
Peabody Coalsales Company
2011
0.4%
   Navajo and Hopi Indian Tribes
Sundt
Rio Tinto Energy America
2008
0.4%
   Colowyo Mine

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

TEP Operated Generating Facilities

TEP is the sole owner (or lessee) and operator of the Springerville Units 1 and 2 and Sundt Unit 4 Generating Stations.  The coal supplies for the Springerville Units 1 and 2 are transported approximately 200 miles by railroad from Northwestern New Mexico.  TEP expects coal reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining lives.

The coal supply agreement for Sundt Unit 4 expired on December 31, 2006.  On December 28, 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through 2008.  The coal supplies are transported approximately 1,300 miles by railroad from Colorado.  The cost of coal and transportation under the new agreements increased $11 million or 79% compared with 2006, primarily due to significantly higher rail costs.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations and Note 5 of Notes to Consolidated Financial Statements – Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.

Generating Facilities Operated by Others

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan.  Four Corners and San Juan are mine mouth generating stations located adjacent to the coal reserves.  Navajo coal supply is provided 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 lives of the stations.

Natural Gas Supply

TEP typically uses generation from its facilities fueled by natural gas and purchased power, in addition to energy from its coal-fired facilities, to meet the summer peak demands of its retail customers and local reliability needs.  Some of these purchased power contracts are price indexed to natural gas prices.  Short-term and spot power purchase prices are also closely correlated to natural gas prices.  Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed purchased power and spot market purchases with fixed price contracts for a maximum of three years.  TEP purchases its remaining gas fuel needs from the Permian Basin, and purchased power in the spot and short-term markets.

TEP purchases gas from Southwest Gas Corporation (SWG) under a retail tariff for North Loop and under transportation agreements for DeMoss Petrie and Sundt.  TEP expects to complete a bypass of SWG and connect the Sundt plant directly to El Paso Natural Gas (EPNG) in the first quarter of 2008.  TEP has purchased capacity from EPNG for transportation from the Permian basin to its Sundt plant. TEP expects to enter into a five year contract with EPNG for transportation from the San Juan and Permian Basins to its Sundt plant after its current agreement expires on April 30, 2008.

TEP purchases gas transportation for Luna from EPNG from the Permian basin to the plant site.  The initial term of this agreement is from February 2006 to January 2009, with rights of first refusal for continuation thereafter.  TEP purchases gas for Luna from various suppliers in the Permian Basin region.
 

WATER SUPPLY

The Four Corners region of New Mexico, where the San Juan and Four Corners Generating Stations are located, experiences drought conditions periodically that could affect the water supply for these plants.  The operating agents for San Juan and Four Corners have negotiated supplemental water contracts with BHP Billiton and the Jicarilla Apache Nation to assist the generating plants in meeting their water requirements in the event of a shortage.

Drought conditions within the Southwestern United States, combined with increased water usage in Arizona, Nevada and Southern California, have caused water levels to recede at Lake Powell, which supplies operating water for the Navajo Generating Station.  TEP has a 7.5% ownership interest in Navajo Units 1, 2 and 3 (168 MW capacity).  Since 2005, the annual snow pack that supplies water flowing into Lake Powell has been sufficient to adequately increase the lake’s water levels.  A project is underway to lower the water intake structures to ensure adequate water supply is available in the event drought conditions adversely affect the water level at Lake Powell.  This project is expected to be completed in early 2009.


TEP has transmission access and power transaction arrangements with over 120 electric systems or suppliers.  TEP is taking steps to increase the capacity and reliability of its transmission and distribution system.  TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability and efficiency of its existing transmission and distribution systems.

TEP is participating in the development of a 500 kV transmission line that will provide TEP with additional access to energy resources in the Palo Verde market.  Completion of this transmission line along with an associated 345 kV substation to interconnect to TEP’s existing 345 kV line between Phoenix and Tucson is expected in mid-2008.  In addition, TEP is participating in the continuation of this line to the Pinal Central substation, which further enhances TEP’s ability to access the region’s energy resources.

TEP has also invested in a new Static Var Compensator that will improve TEP’s ability to import energy while stabilizing voltage on its local transmission and distribution systems.  The device is expected to be operational in May 2008.

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 62-mile transmission line from Tucson to Nogales, Arizona.  The project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona.

Since receiving ACC approval of the location and construction of the proposed 345-kV transmission line along a specified route, TEP has been working to obtain all other required permits from state and federal agencies.

The Department of Energy has completed a Final Environmental Impact Statement (FEIS) for the project accepting any of the routes identified in the FEIS.  The U.S. Forest Service, however, prefers a route that was not approved by the ACC.

Based on the alternative proposals and passage of time since it approved the location of the line, in 2006 the Line Siting Committee of the ACC was directed to gather facts related to options for improving service reliability in Nogales, Arizona.  TEP continues to evaluate alternatives for improving service reliability in Nogales, Arizona.  In 2007, TEP met with major property owners and impacted governmental agencies along the proposed transmission line routes to discuss alternatives.

RATES AND REGULATION

The FERC and the ACC regulate portions of TEP’s utility accounting practices and electricity rates.  The FERC regulates the terms and prices of TEP’s transmission services and wholesale electricity sales.  TEP has a FERC tariff to sell power at market based rates.  The ACC has authority over rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.
 

State

Historically, the ACC determined TEP’s rates for retail sales of electric energy on a “cost of service” basis, which was designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable rate of return on TEP’s “fair value rate base.”  Fair value rate base was generally determined by reference to the original cost and the reconstruction cost (net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items, plus a working capital component.  Over time, additions to utility plant in service increased rate base and depreciation and retirements of utility plant reduced rate base.

Settlement Agreement

In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Rates, for more information.

ACC Rate Proceeding

In July 2007, TEP filed three rate proposal methodologies with the ACC to establish new rates for TEP when the existing rate increase moratorium of the Settlement Agreement is lifted on January 1, 2009.  The proposed rate increases projected under the various methodologies range from 15%-23%.  TEP has requested the rate proposal proceeding be concluded within 18 months in order for a rate increase to be effective no later than January 1, 2009.

As part of this proceeding, all of TEP’s legal rights and claims arising out of the Settlement Agreement and the decision approving the Settlement Agreement are fully preserved.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Rates, for more information.

Arizona Court of Appeals Decision Invalidating Certain Retail Electric Competition Rules

In 2004, an Arizona Court of Appeals decision held invalid certain portions of the ACC Rules and related market pricing.  Based on this decision, we expect that the ACC will address the Rules in an administrative proceeding.  We cannot predict what changes, if any, the ACC will make to the Rules.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Competition, for more information.
 

TEP’S UTILITY OPERATING STATISTICS
   
For Years Ended December 31,
  
   
2007
    
2006
    
2005
    
2004
    
2003
  
Generation and Purchased Power – kWh (000)
                              
Remote Generation (Coal)
     11,001,318       10,854,710       10,059,315       10,159,729       10,182,706  
Local Tucson Generation (Oil, Gas & Coal)
     1,065,778       966,476       1,165,001       1,174,500       1,082,058  
Purchased Power
     2,046,864       1,680,495       1,638,737       1,322,084       1,153,305  
Total Generation and Purchased Power
     14,113,960       13,501,681       12,863,053       12,656,313       12,418,069  
Less Losses and Company Use
     921,024       885,120       806,168       821,008       778,285  
Total Energy Sold
     13,192,936       12,616,561       12,056,885       11,835,305       11,639,784  
                                         
Sales – kWh (000)
                                        
Residential
     4,004,797       3,778,369       3,633,226       3,459,750       3,389,744  
Commercial
     2,057,982       1,959,141       1,855,432       1,787,472       1,689,014  
Industrial
     2,341,025       2,278,244       2,302,327       2,226,314       2,245,340  
Mining
     983,173       924,898       842,881       829,028       701,638  
Public Authorities
     247,430       260,767       241,119       240,426       250,038  
Total – Electric Retail Sales
     9,634,407       9,201,419       8,874,985       8,542,990       8,275,774  
Electric Wholesale Sales
     3,558,529       3,415,142       3,181,900       3,292,315       3,364,010  
Total Electric Sales
     13,192,936       12,616,561       12,056,885       11,835,305       11,639,784  
                                         
Operating Revenues (000)
                                        
Residential
   $ 362,967     $ 343,459     $ 330,614     $ 315,402     $ 309,807  
Commercial
     213,364       203,284       192,966       186,625       175,559  
Industrial
     168,279       165,068       165,988       161,338       160,276  
Mining
     48,707       43,724       39,749       38,549       28,022  
Public Authorities
     18,332       18,935       17,559       17,427       17,839  
Total – Electric Retail Sales
     811,649       774,470       746,876       719,341       691,503  
Electric Wholesale Sales
     195,999       179,022       178,428       159,918       151,030  
Other Revenues
     62,855       35,502       12,166       10,039       9,018  
Total Operating Revenues
   $ 1,070,503     $ 988,994     $ 937,470     $ 889,298     $ 851,551  
                                         
Customers (End of Period)
                                        
Residential
     361,945       357,646       350,628       341,870       334,131  
Commercial
     34,759       34,104       33,534       32,923       32,369  
Industrial
     641       664       673       676       676  
Mining
     2       2       2       2       2  
Public Authorities
     61       61       61       61       61  
Total Retail Customers
     397,408       392,477       384,898       375,532       367,239  
                                         
Average Retail Revenue per kWh Sold (cents)
                                        
Residential
     9.1       9.1       9.1       9.1       9.1  
Commercial
     10.4       10.4       10.4       10.4       10.4  
Industrial and Mining
     6.6       6.6       6.5       6.5       6.4  
Average Retail Revenue per kWh Sold
     8.4       8.4       8.4       8.4       8.4  
                                         
Average Revenue per Residential Customer
   $ 1,009     $ 971     $ 954     $ 933     $ 937  
Average kWh Sales per Residential Customer
     11,129       10,681       10,484       10,231       10,249  



Air and water quality, resource extraction, waste disposal and land use are regulated by federal, state and local authorities.  TEP believes that all of its existing facilities are in compliance and will be in compliance with expected environmental regulations.

Federal Clean Air Act Amendments

The 1990 Federal Clean Air Act Amendments (CAAA), through the Acid Rain Program, requires reductions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions; this affects all of TEP’s generating facilities (except 142 MW of its internal combustion turbines).

TEP’s generating units affected by CAAA Phase II have been allocated SO2 Emission Allowances based on past operational history.  Each allowance gives the owner the right to emit one ton of SO2.  Generating units subject to CAAA Phase II must hold Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years.  TEP has Emission Allowances in excess of what is required to comply with the CAAA Phase II SO2 regulations.  The excess results primarily from a higher removal rate of SO2 emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations.

Title V of the CAAA requires that all of TEP’s generating facilities obtain more stringent air quality permits.  All TEP facilities (including those jointly owned and operated by others) have obtained these permits.  TEP received a new Title V permit for Springerville in 2006 and for Sundt in 2007.  TEP must pay an annual emission-based fee for each generating facility subject to a Title V permit.  These emission-based fees are included in the CAAA compliance expenses.  The CAAA also requires the EPA and other agencies to conduct multi-year studies of visibility impairment in specified areas and studies of hazardous air pollutants.  The results of these studies may impact the development of future regulation of electric utility generating units.

Mercury Emissions

In 2005, the EPA adopted regulations relating to mercury emissions requiring states to develop rules for implementing federal requirements.  Arizona adopted its mercury emission limits in 2007.  Based on these rules, emission control may be required at Springerville and Sundt by 2013. TEP expects the associated capital costs for this equipment to be approximately $6 million at these generating stations.  If the emission control equipment is installed, TEP expects the annual operating expenses to be approximately $3 million, once all installations are completed.

TEP is also monitoring the New Mexico and Navajo Nation mercury emission regulations affecting plants in which TEP has an ownership share.  TEP does not anticipate that additional controls will be required at any of these generating stations prior to 2015 in order to meet the existing state or federal limits.  However, under the terms of a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department (PNM Consent Decree), the co-owners of San Juan Units 1 and 2 will install new equipment to reduce mercury emissions by December 31, 2009, based on the control technology used at San Juan Units 3 and 4.  TEP owns 50% of San Juan Units 1 and 2.

A recent federal court decision may require revisions to the existing mercury emissions regulations.  TEP will continue to review any changes to state and federal regulations required as a result of the recent decision and will comply with any revised regulations.  See Capital and Operating Costs, below for information regarding the costs of compliance with the PNM Consent Decree.

Greenhouse Gas Emissions

In April 2007, the Supreme Court ruled in Commonwealth of Massachusetts, et al v. EPA, that carbon dioxide (CO2) and other greenhouse gases are air pollutants under the Clean Air Act.  Based in part on this decision, federal, state and local regulatory bodies are considering the regulation of greenhouse gas emissions.  In addition, several pieces of legislation have been introduced at the federal level, but not yet acted upon, which propose to regulate greenhouse gas emissions.  Based on the number of competing legislative proposals and uncertainty in the regulatory process, the scope of such regulations and their effect on our operations cannot be determined.
 

Regional Haze

The EPA's Regional Haze Rule requires states to develop plans to restore visibility in Federal Class I Areas (such as parks, monuments and wilderness areas) to their natural conditions by 2064.  State plans could require pollution control upgrades at some of TEP’s power plants.  The level of control required, if any, will not be known until the state plans are submitted and approved by the EPA.  State plans are expected to be submitted to the EPA during 2008, and approved by the EPA during 2009.  If required, controls would need to be in place by 2013 or later.

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.

State Regulations

Arizona and New Mexico have adopted regulations restricting the emissions from existing and future coal, oil and gas-fired plants.  TEP believes that all existing generating facilities are in compliance with all existing state regulations.  These regulations are in some instances more stringent than those adopted by the EPA. The principal generating units of TEP are located relatively close to national parks, monuments, wilderness areas and Indian reservations.  These areas have relatively high air quality and TEP could be subject to control standards that relate to the “prevention of significant deterioration” of visibility and tall stack limitation rules.  See Note 5 of Notes to Consolidated Financial Statements, Commitments and Contingencies, TEP Contingencies, Litigation and Claims Related to San Juan Generating Station.

Renewable Energy Standard and Tariff

In June 2007, the Arizona Attorney General certified the Renewable Energy Standard and Tariff (REST) approved by the ACC in October 2006.  The REST rules require TEP and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years starting with when the REST Implementation Plan and Tariff submitted by an affected utility is approved by the ACC.   The REST rules provide for recovery of above market costs a utility incurs in providing the renewable energy.

In October 2007, TEP filed a proposed REST Implementation Plan and Tariff with the ACC.  The filing contained two proposals: (1) a full compliance proposal that TEP estimates would require additional revenues of $24 million to cover the costs of meeting the 2008 REST requirements; and (2) a proposal based on the ACC’s sample REST tariff that would require additional revenues of $12 million to cover the proposal’s costs, but would not meet the residential portion of the 2008 REST requirements.  TEP’s REST Implementation Plan and Tariff are subject to ACC approval, which is expected to occur in mid-2008.

Capital and Operating Costs

TEP capitalized $7 million in 2007, $1 million in 2006, and $1 million in 2005 in construction costs to comply with environmental requirements and expects to capitalize $60 million in 2008 and $16 million in 2009.  The increase in environmental capital expenditures in 2008 and 2009 is due primarily to emission control upgrades to be made at San Juan.

TEP recorded expenses of $10 million in 2007, $10 million in 2006, and $11 million in 2005 related to environmental compliance, including the cost of lime used to scrub the stack gas.  TEP expects environmental expenses to be $11 million in 2008.  TEP may incur additional costs to comply with recent and future changes in federal and state environmental laws, regulations and permit requirements at existing electric generating facilities.  Compliance with these changes may result in a reduction in operating efficiency.

As a result of the PNM Consent Decree, the co-owners of San Juan are installing new pollution control equipment at the generating station to reduce mercury, particulate matter, NOx, and SO2 emissions.  The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan.  In 2007, TEP’s share of potential stipulated penalties at San Juan was $2 million.  TEP’s share of stipulated penalties in 2006 was less than $0.5 million.  TEP expects its share of stipulated penalties at San Juan to approximate $1 million in 2008.  The new pollution control equipment is expected to be installed at the generating units that TEP jointly owns in 2008 and early 2009, and is designed to remedy all emission violations.
 

In order to meet Title V permit requirements in connection with the construction of Springerville Unit 3, between 2003 and 2005, the Springerville Unit 3 project paid approximately $63 million for upgrades to emission control equipment on Springerville Units 1 and 2; and from 2003 to 2007, paid approximately $32 million for improvements to Springerville common facilities.

UNS GAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 146,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in Southeast Arizona.  These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 800,000 in 2007.  Average customer growth in 2007 was approximately 2%, which is lower than in previous years due to general economic conditions.

UNS Gas’ customer base is primarily residential.  Total revenues derived from residential customers were approximately 61% of total revenues in 2007, while sales to other retail customer classes accounted for approximately 29% of total revenues.  Approximately 10% of total revenues in 2007 were derived from gas transportation services and a Negotiated Sales Program (NSP).  UNS Gas supplies natural gas transportation service to the 600 MW Griffith Power Plant located near Kingman, Arizona, under a 20-year contract which expires in 2021.  UNS Gas also supplies natural gas to some of its large transportation customers through an NSP approved by the ACC.  One half of the margin earned on these NSP sales is retained by UNS Gas, while the other half benefits retail customers through a credit to the purchased gas adjustor (PGA) mechanism which reduces the gas commodity price.

In February 2008, UNS Gas and UED entered into a 20-year gas transportation agreement and a 20-year natural gas sales agreement, whereby UNS Gas will purchase natural gas for UED and transport to BMGS.

GAS SUPPLY AND TRANSMISSION

UNS Gas has a natural gas supply and management agreement with BP Energy Company (BP).  Under the contract, BP manages UNS Gas’ existing supply and transportation contracts and its incremental requirements.    UNS Gas gave BP notice of its intent to terminate this agreement in September 2008.  At that time, UNS Gas will directly manage its gas supply and transportation contracts. The market price for gas will continue to vary based upon the period during which the commodity is purchased.  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 El Paso and Transwestern interstate pipeline systems. UNS Gas has firm transportation agreements with EPNG and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its customers’ demands.

With EPNG, the average daily capacity right of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000  therms per day in the winter season (November through March) to serve its Northern and Southern Arizona service territories.   UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline.  The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman, Arizona, and also delivers gas to UNS Gas’ facilities serving the Griffith Power Plant in Mohave County.

UNS Gas signed a separate transportation agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line.  The 15-year agreement is expected to begin in late 2008, when construction of that pipeline is expected to be complete.  The average daily capacity right of UNS Gas will be 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 REGULATION

The ACC regulates UNS Gas with respect to retail gas rates, the issuance of securities, and transactions with affiliated parties.  UNS Gas’ retail gas rates include a monthly customer charge, a base rate charge for delivery services and the cost of gas (expressed in cents per therm), and a PGA.

Purchased Gas Adjustor

The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor.  The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportation recovered through base rates is deferred and recovered or returned to customers through the PGA mechanism.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, for more information.

2007 Rate Order

In November 2007, the ACC issued a final order in the UNS Gas rate case filed in July 2006, approving a $5 million, or 4% base rate increase.  New rates went into effect in December 2007. UNS Gas had requested a $9 million, or 7% base rate increases (over test year revenues) to recover the costs related to serving its growing customer base.  UNS Gas also received modifications to its PGA mechanism to help address problems posed by volatile gas prices.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Rates, for more information.

2008 Rate Case

On February 21, 2008, UNS Gas filed a rate case with the ACC.  UNS Gas is seeking a base rate increase of 7% or $10 million, based on a September 30, 2007 test year.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Rates, for more information.


UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities.  UNS Gas believes that all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is an electric transmission and distribution company serving approximately 90,000 retail customers in Mohave and Santa Cruz counties.  These counties had a combined population of approximately 250,000 in 2007.  Average customer growth in 2007 was approximately 3%, which is lower than in previous years due to general economic conditions.

UNS Electric’s customer base is primarily residential, with some small commercial and both light and heavy industrial customers.  Peak demand for 2007 was 417 MW.

POWER SUPPLY AND TRANSMISSION

Power Supply

UNS Electric has a full requirements power supply agreement with Pinnacle West Marketing and Trading (PWMT) which expires in May 2008.  The agreement obligates PWMT to supply all of UNS Electric’s power requirements at a fixed price.  Payments under the contract are usage based, with no fixed customer or demand charges.

UNS Electric is in the process of evaluating and securing power supply resources to ensure adequate resources are in place when its PWMT agreement expires.  In 2006 and 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  In addition, as part of its general rate
 
 
case filing, UNS Electric included a proposal to purchase the 90 MW Black Mountain Generating Station (BMGS) in 2008, which is under development by UED.  As of February 2008, UNS Electric had acquired approximately 76% of its total expected capacity needs for June 2008.  UNS Electric expects to have sufficient capacity needs in place when the PWMT agreement expires.  UNS Electric will rely on some short-term purchases to meet customer load requirements.

UNS Electric owns and operates the Valencia Power Plant (Valencia), located in Nogales, Arizona.  Valencia consists of four gas and diesel-fueled combustion turbine units and provides approximately 68 MW of peaking resources.  This includes a 20 MW unit installed in 2006.  The facility is directly interconnected with the distribution system serving the city of Nogales and the surrounding areas.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Liquidity and Capital Resources, Contractual Obligations and Other, UED, below for more information.

Transmission

UNS Electric imports the power it purchases from PWMT into its Mohave County and Santa Cruz County service territories over Western Area Power Administration’s (WAPA) transmission lines.  UNS Electric negotiated a network transmission service agreement for its primary transmission capacity agreement with WAPA for the Parker-Davis system that expires in May 2017.  UNS Electric also has a long-term electric point to point transmission capacity agreement with WAPA for the Southwest Intertie system that expires in 2011 and a point-to-point transmission capacity agreement with WAPA for the Parker-Davis system for service to Santa Cruz County that expired in February 2008.  UNS Electric is working with WAPA to extend the agreement.

UNS Electric plans to upgrade its existing 115 kV transmission line over time to improve the reliability of service in Santa Cruz County.

RATES AND REGULATION

UNS Electric is regulated by the ACC with respect to retail electric rates, quality of service, the issuance of securities, and transactions with affiliated parties, and by the FERC with respect to wholesale power contracts and interstate transmission service.  In 2007, UNS Electric was granted a FERC tariff to sell power at market based rates.  UNS Electric’s retail electric rates include a purchased power and fuel adjustment clause (PPFAC), which allows for UNS Electric to recover the actual costs of its power purchases.

General Rate Case

In December 2006, UNS Electric filed a general rate case to recover the costs related to serving its growing customer base.  UNS Electric is seeking a rate increase of 5.5% or $8.5 million.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Rates, for more information.


UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal and land use by federal, state and local authorities.  UNS Electric believes that all existing facilities are in compliance with all existing regulations and will be in compliance with expected environmental regulations.

Renewable Energy Standard and Tariff

In June 2007, the Arizona Attorney General certified the REST approved by the ACC in October 2006.  The REST rules require UNS Electric and other affected utilities to generate or purchase at least 15% of their total annual retail energy requirements from renewable energy technologies by 2025, with smaller amounts required in earlier years starting with when the REST Implementation Plan and Tariff submitted by an affected utility is approved by the ACC.  The REST rules provide for recovery of above market costs a utility incurs in providing the renewable energy.

In October 2007, UNS Electric filed a proposed REST Implementation Plan and Tariff with the ACC.  The filing contained two proposals: (1) a full compliance proposal that UNS Electric estimates would require additional revenues of $4 million to meet the 2008 REST requirements; and (2) a proposal based on the ACC’s sample
 
 
REST tariff that would require additional revenues of $2 million, but would not meet the residential portion of the 2008 REST requirements.  The REST Implementation Plan and Tariff are subject to ACC approval, which is expected to occur in mid-2008.


UED

UED facilitated the expansion of the Springerville Generating Station and is currently developing the 90 MW gas-fired BMGS in Kingman, Arizona. Completion of the project is estimated to occur in May 2008.  Pending ACC approval, BMGS is expected to be used as a resource for UNS Electric. The project is expected to cost between $60 million and $65 million.

UED entered into a 20-year gas transportation agreement in January 2008 and a 20-year natural gas sales agreement in December 2007 with UNS Gas, whereby UNS Gas will purchase natural gas for UED and transport to BMGS.

Millennium Investments

Through affiliates, Millennium holds investments in unregulated energy and emerging technology companies.  At December 31, 2007, Millennium’s assets represented 3% of UniSource Energy’s total assets. UniSource Energy has ceased making loans or equity contributions to Millennium.  We anticipate that the funding for Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Other, Liquidity and Capital Resources.

Consolidated Millennium Investments

Southwest Energy Solutions, Inc. (SES), a wholly-owned Millennium subsidiary, provides electrical contracting services in Arizona to commercial, industrial and governmental customers in both high voltage and inside wiring capacities.  SES also provides meter reading services to TEP and UNS Electric.

Equity Method Millennium Investments

Haddington Energy Partners II, LP (Haddington) is a limited partnership that funds energy-related investments.  As of December 31, 2007, Millennium had invested $15 million in Haddington since its inception, and received distributions of $15 million.  Millennium has no remaining commitment to Haddington.  Millennium’s total investment balance in Haddington at December 31, 2007 was $5 million.

Valley Ventures III, LP (Valley Ventures) is a venture capital fund that focuses on investments in information technology, microelectronics and biotechnology, primarily within the Southwestern U.S.  Millennium committed $6 million, including fees, to the fund and owns approximately 15% of the fund.  As of December 31, 2007, Millennium has not received any distributions from Valley Ventures and had $1 million remaining on this commitment, which is expected to be funded over the next one to two years.  Millennium’s total investment balance in Valley Ventures at December 31, 2007 was $5 million.

Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 MW of coal-fired generation in the Sabinas region of Coahuila, Mexico.  Sabinas also owns 19.2% of Minerales de Monclova, S.A. de C.V. (Mimosa).  Mimosa is an owner of coal and associated gas reserves and a supplier of metallurgical coal to the Mexican steel industry and thermal coal to the major electric utility in Mexico.  Millennium owns 50% of Sabinas.  Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates own the remaining 50%.  UniSource Energy’s Chairman, President and Chief Executive Officer is a member of the Board of Directors of AHMSA.  Since 1999, both AHMSA and Mimosa have been parties to a suspension of payments procedure, under applicable Mexican law, which is the equivalent of a U.S. Chapter 11 proceeding.  Millennium has the right to sell (a put option) its interest in Sabinas to an AHMSA affiliate for $20 million upon conclusion of its evaluation of Mimosa’s coal and associated gas reserves.  Millennium’s investment balance in Sabinas at December 31, 2007 was $14 million.
 

Discontinued Operations - Global Solar Energy

On March 31, 2006, Millennium completed the sale of its interest in Global Solar.  The operating results of Global Solar are reported as discontinued operations.

EMPLOYEES (As of December 31, 2007)

TEP had 1,306 employees, of which approximately 53% 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 2009.

UNS Gas had 203 employees, of which 118 employees were represented by IBEW Local No. 1116 and 6 employees were represented by IBEW Local No. 387.  The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2009 and February 2010, respectively.

UNS Electric had 168 employees, of which 27 employees were represented by the IBEW Local No. 387 and 112 employees were represented by the IBEW Local No. 769.  The existing agreement with the IBEW Local No. 387 expires in February 2010 and the agreement with IBEW Local No. 769 was ratified in August 2007 and expires in 2010.

SES had 274 employees, of which approximately 96% are represented by unions.  Of the employees represented by unions, 237 are represented by IBEW Local No. 1116 and 25 by IBEW Local No. 570.  The existing agreements with IBEW Local No. 1116 and IBEW Local No. 570 expire on December 31, 2009.

SEC REPORTS AVAILABLE ON UNISOURCE ENERGY’S WEBSITE

UniSource Energy and TEP make available their annual reports  on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after they electronically file them with, or furnish them to, the Securities and Exchange Commission (SEC).  These reports are available free of charge through UniSource Energy’s website address:  http://www.uns.com.  A link from UniSource Energy’s website to these SEC reports is accessible as follows:  At the UniSource Energy main page, select Investor Relations from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page.  UniSource Energy’s code of ethics, and any amendments made to the code of ethics, is also available on UniSource Energy’s website.

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


ITEM 1A. – RISK FACTORS

The business and financial results of UniSource Energy and TEP are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the SEC.

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

UniSource Energy is a holding company that is dependent on the earnings and distributions of funds from its subsidiaries to service its debt and pay dividends to shareholders.

Restrictions include:

 
·
TEP, UNS Gas and UNS Electric are restricted from lending or transferring funds or issuing securities without ACC approval;

 
·
The Federal Power Act restricts electric utilities’ ability to pay dividends out of funds that are properly included in their capital account.  TEP has an accumulated deficit rather than positive retained earnings.  Although the terms of the Federal Power Act are unclear, we believe there is a reasonable basis for TEP to pay dividends from current year earnings.  However, the FERC could attempt to stop TEP from paying further dividends or could seek to impose additional restrictions on the payment of dividends; and
 
 
 
·
TEP, UNS Gas and UNS Electric must be in compliance with their respective debt agreements to make dividend payments to UniSource Energy.

UniSource Energy does not expect to receive distributions from UNS Gas or UNS Electric over the next few years due to the need to apply internally generated funds to the growth of these businesses.

TEP does not have a purchased power and fuel adjustor clause (PPFAC), which could negatively impact TEP’s results of operations, net income and cash flows.

Increases in the cost of coal, gas and related transportation costs and purchased power necessary to serve TEP’s retail load are not passed through to TEP’s customers.  Operational failures or unplanned outages at TEP’s generating stations, especially during peak seasons, could result in unanticipated power purchases which could significantly increase the cost of serving TEP’s retail load.

In the event that purchased power or fuel costs increase, TEP could be adversely affected.
 
The operation of electric generating stations involves risks that could result in unplanned outages or reduced generating capability that could adversely affect TEP’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 generating stations operate below expectations, TEP could be adversely affected.

TEP may not receive an adequate rate increase effective January 2009, which could negatively impact TEP’s results of operations, net income and cash flows.

TEP’s current retail rates were established under a Settlement Agreement approved by the ACC in 1999.  Under the Settlement Agreement, TEP’s rates are capped until December 31, 2008.  There is disagreement between a number of participants in TEP’s rate proceedings regarding the interpretation of the Settlement Agreement, and as to how TEP’s rates for generation service will be determined beginning in 2009.  TEP believes the Settlement Agreement requires TEP to charge market-based generation service rates; other participants, including ACC Staff, disagree and have stated that the Settlement Agreement does not control how TEP’s rates for generation service will be established after 2008.

Since TEP’s rates were capped in 1999, the cost of serving TEP’s customers has risen significantly.  In a July 2007 filing with the ACC, TEP estimated that charging market-based rates for generation services would result in a projected rate increase of 22% over existing rates.  TEP also proposed two alternate methodologies for setting rates after December 31, 2008, which would result in projected rate increases ranging from 15%-23%.  If TEP does not receive adequate rate relief from the ACC, TEP’s results of operations, net income and cash flows could be negatively impacted.

TEP may be required to refund to customers approximately $65 million of revenues to be collected in 2008, which could negatively impact TEP’s results of operations, net income and cash flows.

According to a May 2007 order of the ACC, TEP’s current Standard Offer rates shall remain at their current level, including collection of the Fixed CTC, until the effective date of a final order in the rate proposal proceeding. The incremental revenue collected as a result of maintaining rates at their current level after the TRA is fully amortized in mid-2008 is estimated to be approximately $65 million.  This revenue shall accrue interest and shall be subject to refund or credit or other such mechanism to protect customers, as determined in the rate proposal docket; however, TEP does not expect to record these amounts as revenue until or unless the ACC issues a final order that authorizes TEP to retain any incremental revenue.  If TEP is unable to recognize these amounts as revenue in 2008, TEP’s net income will be reduced as will the amount of dividends it can pay to UniSource Energy in 2008.

UNS Electric may not be able to secure sufficient energy resources to serve its retail customers in 2009 and beyond.

At December 31, 2007, UNS Electric owned 68 MW of peaking generation resources.  As part of its general rate case filing, UNS Electric included a proposal to purchase the 90 MW gas-fired BMGS in 2008, which is under development by UED.  In 2007, UNS Electric’s peak retail demand was 417 MW.  Even if the ACC permits UNS Electric to acquire BMGS, UNS Electric will need to rely heavily on purchased power contracts to meet its retail energy demand.  UNS Electric cannot predict whether it will be able to obtain sufficient resources to meet its retail energy demand for 2009 and beyond.  UNS Electric’s cash flows and net income could be negatively impacted if UNS Electric is unable to secure adequate energy resources to sell to its retail customers.
 

UNS Electric may not receive ACC approval to acquire the BMGS, which could negatively impact UED’s results of operations, net income and cash flows.

In its December 2006 rate case filing, UNS Electric requested the ACC to approve the acquisition of the 90 MW BMGS combustion turbine project under development by UED and to include the cost of the project in rate base effective June 1, 2008.   The cost of BMGS is expected to be $60 million to $65 million.

If the ACC denies UNS Electric’s request, UED may need to sell BMGS to a third party or enter into a purchased power contract or contracts to sell the output of BMGS.  Regional wholesale energy markets and the demand for generating assets can be unpredictable.  UED could be adversely affected if it is not able to recover the costs of BMGS.

UNS Electric may be required to post margin under its power supply agreements which could negatively impact its liquidity.

UNS Electric is in the process of evaluating and securing power supply resources to replace the full requirements power supply agreement which expires in May 2008.  The agreements under which UNS Electric contracts for such resources include requirements to post credit enhancement in the form of cash or letters of credit under certain circumstances, including changes in market prices which affect contract values, or a change in the creditworthiness of UNS Electric.

In order to post such credit enhancement, UNS Electric would have to use available cash, draw under its revolving credit agreement, or issue letters of credit under its revolving credit agreement.  The maximum amount UNS Electric may use under its revolving credit facility is $45 million.  As of February 26, 2008, UNS Electric had $15 million available to borrow under its revolving credit facility.  If UNS Electric is required to use its revolving credit facility to post collateral, it would negatively impact UNS Electric’s ability to fund its capital requirements.

TEP’s, UNS Gas’ and UNS Electric’s revenues, results of operations and cash flows are seasonal, and are subject to weather conditions, economic conditions and customer usage patterns, which are beyond the Company’s control.

TEP typically earns the majority of its operating revenue and net income in the third quarter because of higher air conditioning usage by its retail customers due to hot summer weather.  Furthermore, TEP typically reports limited net income in the first quarter because of relatively mild winter weather in its retail service territory.  UNS Gas’ peak sales occur in the winter; UNS Electric’s peak sales occur in the summer.  Cool summers or warm winters may adversely affect the utility subsidiaries’ operating revenues and net income by reducing sales.

Changes in federal energy regulation may affect TEP, UNS Gas and UNS Electric’s results of operations, net income and cash flows.

TEP, UNS Gas and UNS Electric are subject to comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industries and the ways in which these industries are regulated. UniSource Energy’s utility subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC).   The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale prices.

UniSource Energy and its subsidiaries have a substantial amount of indebtedness which could adversely affect its business and results of operations.

UniSource Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries.  At December 31, 2007, total debt (including capital lease obligations net of investments in lease debt) to total capitalization for UniSource Energy and its subsidiaries was 71%.  The substantial amount of indebtedness of UniSource Energy and its subsidiaries:

 
·
requires UniSource Energy and its subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on its debt, which could reduce the funds available for working capital, capital expenditures, acquisitions and other general corporate purposes; 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.

The cost of renewing or purchasing TEP’s leased assets, or the cost of procuring alternate sources of generation or purchased power, could adversely affect TEP’s results of operations, net income and cash flows.

TEP, under separate sale and leaseback arrangements, leases the following generation facilities:

 
·
Springerville Unit 1;
 
·
Sundt Unit 4;
 
·
Springerville Coal Handling Facilities; and
 
·
Springerville Common Facilities.
 
TEP may renew the leases or purchase the assets when the leases expire at various times between 2011 and 2021.  The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, whereas fixed purchase price options exist for the coal handling and common facilities leases.  Upon expiration of the coal handling and common facilities leases (whether at the end of the initial term or any renewal term), TEP has the obligation under agreements with the Springerville Units 3 and 4 owners to purchase such facilities, and each of the owners of Springerville Units 3 and 4 has the obligation to purchase from TEP a 14% and 17% interest, respectively, in these facilities.
 
UniSource Energy’s utility subsidiaries are subject to numerous environmental laws and regulations which may increase their cost of operations or expose them to environmentally-related litigation and liabilities.

UniSource Energy’s utility subsidiaries are subject to numerous federal, state and local environmental regulations affecting present and future operations, including regulations regarding air emissions, water quality, wastewater discharges, solid waste and hazardous waste.  Many of these regulations arise from TEP’s use of coal as the primary fuel for energy generation.

Existing environmental regulations may be revised or new regulations may be adopted or become applicable to UniSource Energy’s utility subsidiaries.  Compliance with existing or new environmental laws and regulations can result in increased capital, operating and other costs.  The U.S. Congress is considering the regulation of greenhouse gas emissions.  At this time, we are unable to predict whether any such regulations will be adopted, the scope of such regulations or how any such regulations could affect our operations.

TEP is also contractually obligated to pay a portion of its environmental reclamation costs at generating stations in which it has a minority interest and possibly at the mines that supply these generating stations.  While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.

TEP or UNS Electric may not be able to secure adequate right-of-way to construct transmission lines and may be required to find alternate ways to provide adequate sources of energy and maintain reliability in TEP and UNS Electric’s service areas.

TEP and UNS Electric rely on federal, state and local governmental agencies to secure right-of-way and siting permits to construct transmission lines.  If adequate right-of-way and siting permits to build new transmission lines cannot be secured:
 

 
·
TEP and UNS Electric may need to rely on more costly alternatives to provide energy to their customers;
 
·
TEP and UNS Electric may not be able to maintain reliability in their service areas; or
 
·
TEP and UNS Electric’s ability to provide electric service to new customers may be negatively impacted.

TEP may be required to redeem significant amounts of its outstanding tax-exempt bonds.

TEP has financed a portion of its utility plant assets with tax-exempt bonds for which the exemption from income taxes requires that the financed facilities be used for the local furnishing of electric energy.  Approximately $359 million of these bonds were outstanding as of December 31, 2007.  Various events, including, in certain circumstances, the formation of an RTO or an independent system operator, asset divestitures, changes in tax laws or changes in system operations, could require TEP to redeem or defease some or all of these bonds which would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater principal amount.

TEP may not be permitted to construct a Tucson to Nogales transmission line and TEP or UNS Electric may be required to find alternate ways to improve reliability in UNS Electric’s Santa Cruz service area.

In 2001, TEP entered into an agreement to build an approximately 60-mile transmission line from Tucson to Nogales, Arizona, in response to an order from the ACC to improve reliability to UNS Electric’s retail customers in Nogales.  Required regulatory approvals have delayed the construction of the transmission line, and in 2005, the ACC initiated proceedings to review the status of service in Nogales and need for the 345-kV line.  After a hearing on the issue in February 2006, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona.

If TEP does not receive required approvals or if we abandon the project, it may be required to expense a portion of the $11 million it has incurred through December 31, 2007, in land acquisition, engineering and environmental expenses.  In such an event, TEP or UNS Electric may be required to make additional expenditures to improve reliability.  In the event TEP or UNS Electric are not able to recover such expenditures, their results of operations and net income could be adversely affected.


ITEM 2. – PROPERTIES

TEP PROPERTIES

TEP’s transmission facilities, located in Arizona and New Mexico, transmit electricity from TEP’s remote electric generating stations at Four Corners, Navajo, San Juan, Springerville and Luna to the Tucson area for use by TEP’s retail customers (see Item 1. – Business – Generating and Other Resources).  The transmission system is interconnected at various points in Arizona and New Mexico with a number of regional utilities.  TEP has arrangements with approximately 120 companies to interchange generation capacity and transmission of energy.

As of December 31, 2007, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

 
·
512 circuit-miles of 500-kV lines;
 
·
1,098 circuit-miles of 345-kV lines;
 
·
365 circuit-miles of 138-kV lines;
 
·
469 circuit-miles of 46-kV lines; and
 
·
2,623 circuit-miles of lower voltage primary lines.

The underground electric distribution system is comprised of 4,242 cable-miles.  TEP owns approximately 60% of the poles on which the lower voltage lines are located.  Electric substation capacity consisted of 101 substations with a total installed transformer capacity of 7,052,267 kilovolt amperes.

Substantially all of the utility assets owned by TEP are subject to the lien of the 1992 Mortgage.  Springerville Unit 2, which is owned by San Carlos Resources Inc., a wholly-owned subsidiary of TEP (San Carlos), is not subject to the lien.
 

The electric generating stations (except as noted below), operating headquarters, warehouse and service center are located on land owned by TEP.  The electric distribution and transmission facilities owned by TEP are located:

 
·
on property owned by TEP;
 
·
under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which are generally subject to termination;
 
·
under or over private property as a result of easements obtained primarily from the record holder of title; or
 
·
over American Indian reservations under grant of easement by the Secretary of Interior or lease by American Indian tribes.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

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

Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation, respectively.  TEP, individually and in conjunction with PNM in connection with San Juan, has acquired easements and leases for transmission lines and a water diversion facility located on land owned by the Navajo Nation.  TEP has also acquired easements for transmission facilities, related to San Juan, Four Corners, and Navajo, across the Zuni, Navajo and Tohono O’odham Indian Reservations.  TEP, in conjunction with PNM and Phelps Dodge, holds an undivided ownership interest in the property on which Luna is located.

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

 
·
possible conflicting grants or encumbrances due to the absence of or inadequacies in the recording laws or record systems of the Bureau of Indian Affairs and the American Indian tribes;
 
·
possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without Congressional consent; or
 
·
failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.

These possible defects have not interfered and are not expected to materially interfere with TEP’s interest in and operation of its facilities.

TEP, under separate sale and leaseback arrangements, leases the following generation facilities (which do not include land):

 
·
coal handling facilities at Springerville;
 
·
a 50% undivided interest in the Springerville Common Facilities;
 
·
Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities; and
 
·
Sundt Unit 4 and related common facilities.

See Note 7 of Notes to Consolidated Financial Statements, Debt, Credit Facilities, and Capital Lease Obligations and Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Liquidity and Capital Resources, Contractual Obligations, for additional information on TEP’s capital lease obligations.

UES PROPERTIES

UNS Gas

As of December 31, 2007, UNS Gas’ transmission and distribution system consisted of approximately 58 miles of steel transmission mains, 4,309 miles of steel and plastic distribution mains, and 151,438 customer service lines.
 

UNS Electric

As of December 31, 2007, UNS Electric’s transmission and distribution system consisted of approximately 56 circuit-miles of 115-kV transmission lines, 252 circuit-miles of 69-kV transmission lines, and 3,510 circuit-miles of underground and overhead distribution lines.  UNS Electric also owns 40 substations having a total installed capacity of 1,685,050 kilovolt amperes and the 65 MW Valencia plant.

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

 
·
on property owned by UNS Gas or UNS Electric;
 
·
under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which are generally subject to termination; or
 
·
under or over private property as a result of easements obtained primarily from the record holder of title.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

UED PROPERTIES

As of December 31, 2007, UED owned a 90 MW gas-fired generation facility under construction in Kingman, Arizona, known as BMGS, that is expected to be completed by the end of May 2008.  BMGS is located on property that is owned by UNS Electric and currently licensed or leased to UED.
 

ITEM 3 – LEGAL PROCEEDINGS

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Operations, for litigation related to ACC orders and retail competition.

We discuss legal proceedings in Note 5 of Notes to Consolidated Financial Statements, Commitments and Contingencies.


ITEM 4. – SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.




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

Stock Trading

UniSource Energy’s Common Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange.  On February 26, 2008, the closing price was $27.07, with 10,618 shareholders of record.  UniSource Energy did not purchase any shares of its Common Stock during the fourth quarter of 2007.

Dividends

UniSource Energy’s Board of Directors currently expects to continue to pay regular quarterly cash dividends on our Common Stock subject, however, to the Board’s evaluation of our financial condition, earnings, cash flows and dividend policy.

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.
 

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Dividends on Common Stock.
 
Common Stock Dividends and Price Ranges
 
 
2007
  
2006
Quarter:
Market Price per
Dividends
  
Market Price per
Dividends
 
Share of Common
Declared
  
Share of Common
Declared
 
Stock (1)
    
Stock (1)
  
 
High
Low
    
High
Low
               
First
$ 39.17
$ 35.46
$ 0.225
  
$ 32.73
$ 29.90
$ 0.21
Second
   39.94
   33.10
   0.225
  
   31.54
   29.47
   0.21
Third
   33.72
   27.66
   0.225
  
   35.17
   31.04
   0.21
Fourth
   32.66
   29.14
   0.225
  
   37.46
   36.95
   0.21
Total
    
$ 0.900
      
$ 0.84
 
(1) UniSource Energy’s Common Stock price as reported in the consolidated reporting system.

On February 27, 2008, UniSource Energy declared a cash dividend of $0.24 per share on its Common Stock.  The dividend will be paid March 21, 2008 to shareholders of record at the close of business March 10, 2008.

TEP declared and paid cash dividends to UniSource Energy of $53 million in 2007, $62 million in 2006, and $46 million in 2005.

Convertible Senior Notes

In 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes due 2035.  Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of our Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Liquidity and Capital Resources, Financing Activities.

Issuer Purchases of Common Equity

UniSource Energy did not purchase any of its common stock during 2007, 2006 or 2005.

 
ITEM 6. – SELECTED CONSOLIDATED FINANCIAL DATA
 
 
2007
    
2006
    
2005
    
2004
    
2003
  
   
- In Thousands -
  
   
(except per share data)
  
Summary of Operations
                              
Operating Revenues (1)
   $ 1,381,373     $ 1,308,141     $ 1,224,056     $ 1,164,988     $ 970,651  
Income Before Discontinued Operations and Accounting Change (1)
   $ 58,373     $ 69,243     $ 52,253     $ 50,982     $ 53,942  
Net Income (1) (2)
   $ 58,373     $ 67,447     $ 46,144     $ 45,919     $ 113,941  
                                         
Basic Earnings per Share:
                                        
Before Discontinued Operations & Accounting Change
   $ 1.64     $ 1.96     $ 1.51     $ 1.49     $ 1.60  
Net Income
   $ 1.64     $ 1.91     $ 1.33     $ 1.34     $ 3.37  
                                         
Diluted Earnings per Share:
                                        
Before Discontinued Operations & Accounting Change
   $ 1.57     $ 1.85     $ 1.44     $ 1.45     $ 1.57  
Net Income
   $ 1.57     $ 1.80     $ 1.28     $ 1.31     $ 3.32  
                                         
Shares of Common Stock Outstanding
                                        
Average
     35,486       35,264       34,798       34,380       33,828  
End of Year
     35,315       35,190       34,874       34,255       33,788  
                                         
Year-end Book Value per Share
   $ 19.54     $ 18.59     $ 17.69     $ 16.95     $ 16.47  
Cash Dividends Declared per Share
   $ 0.90     $ 0.84     $ 0.76     $ 0.64     $ 0.60  
                                         
Financial Position
                                        
Total Utility Plant – Net
   $ 2,407,295     $ 2,259,620     $ 2,171,461     $ 2,081,137     $ 2,069,215  
Investments in Lease Debt and Equity
     152,544       181,222       156,301       170,893       178,789  
Other Investments and Other Property
     70,677       66,194       58,468       68,846       90,137  
Total Assets
   $ 3,185,716     $ 3,187,409     $ 3,180,211     $ 3,186,936     $ 3,135,013  
                                         
Long-Term Debt
   $ 993,870     $ 1,171,170     $ 1,212,420     $ 1,257,595     $ 1,286,320  
Non-Current Capital Lease Obligations
     530,973       588,771       665,737       701,931       762,968  
Common Stock Equity
     690,075       654,149       616,741       580,718       556,472  
Total Capitalization
   $ 2,214,918     $ 2,414,090     $ 2,494,898     $ 2,540,244     $ 2,605,760  
                                         
Selected Cash Flow Data
                                        
Net Cash Flows From Operating Activities
   $ 322,766     $ 282,659     $ 273,883     $ 306,979     $ 263,396  
                                         
Capital Expenditures
   $ (245,366 )   $ (238,261 )   $ (203,362 )   $ (166,861 )   $ (135,731 )
Other Investing Cash Flows
     27,961       (7,820 )     32,794       10,672       (215,001 )
Net Cash Flows From Investing Activities
   $ (217,405 )   $ (246,081 )   $ (170,568 )   $ (156,189 )   $ (350,732 )
                                         
Net Cash Flows From Financing Activities
   $ (119,229 )   $ (77,016 )   $ (112,664 )   $ (98,028 )   $ 97,674  
                                         
Ratio of Earnings to Fixed Charges (3)
     1.68       1.73       1.55       1.48       1.44  

(1) In 2003, Operating Revenues, Income Before Discontinued Operations and Accounting Change and Net Income include results from UES for the period from August 11, 2003 to December 31, 2003.
 

(2) Net Income includes an after-tax loss for discontinued operations of $2 million in 2006, $5 million in 2005, $5 million in 2004 and $7 million in 2003.  Net income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005 and an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the implementation of FAS 143 in 2003.

(3) For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense, and amortization of debt discount and expense related to indebtedness.  Fixed charges are interest expense, including amortization of debt discount and expense on indebtedness.

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

 
2007
    
2006
    
2005
    
2004
    
2003
  
   
-Thousands of Dollars-
  
Summary of Operations
                              
Operating Revenues
   $ 1,070,503     $ 988,994     $ 937,470     $ 889,298     $ 851,551  
Income Before Accounting Change
     53,456       66,745       48,893       46,127       61,442  
Net Income (1)
   $ 53,456     $ 66,745     $ 48,267     $ 46,127     $ 128,913  
                                         
Financial Position
                                        
Total Utility Plant – Net
   $ 1,957,506     $ 1,887,387     $ 1,866,622     $ 1,816,782     $ 1,832,156  
Investments in Lease Debt and Equity
     152,544       181,222       156,301       170,893       178,789  
Other Investments and Other Property
     35,460       30,161       27,013       23,393       41,285  
Total Assets
   $ 2,573,036     $ 2,623,063     $ 2,617,219     $ 2,742,168     $ 2,767,047  
                                         
Long-Term Debt
   $ 682,870     $ 821,170     $ 821,170     $ 1,097,595     $ 1,126,320  
Non-Current Capital Lease Obligations
     530,714       588,424       665,299       701,405       762,323  
Common Stock Equity
     577,349       554,714       558,646       414,510       406,054  
Total Capitalization
   $ 1,790,933     $ 1,964,308     $ 2,045,115     $ 2,213,510     $ 2,294,697  
                                         
Selected Cash Flow Data
                                        
Net Cash Flows From Operating Activities
   $ 264,112     $ 227,228     $ 243,013     $ 275,151     $ 260,989  
                                         
Capital Expenditures
   $ (162,539 )   $ (156,180 )   $ (149,906 )   $ (129,505 )   $ (121,854 )
Other Investing Cash Flows
     25,414       (25,786 )     21,001       3,743       11,408  
Net Cash Flows From Investing Activities
   $ (137,125 )   $ (181,966 )   $ (128,905 )   $ (125,762 )   $ (110,446 )
                                         
Net Cash Flows From Financing Activities
   $ (120,088 )   $ (78,984 )   $ (173,882 )   $ (101,444 )   $ (141,059 )
                                         
Ratio of Earnings to Fixed Charges (2)
     1.75       1.84       1.60       1.52       1.51  

(1) Net Income includes an after-tax loss of $0.6 million for the Cumulative Effect of Accounting Change from the implementation of FIN 47 in 2005 and an after-tax gain of $67 million for the Cumulative Effect of Accounting Change from the implementation of FAS 143 in 2003.

(2) For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense on indebtedness.

Note: Disclosure of earnings per share information for TEP is not presented as the common stock of TEP is not publicly traded.

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

NON-GAAP MEASURES

Adjusted EBITDA

Adjusted EBITDA represents EBITDA excluding the cumulative effect of accounting change which is a non-cash item.  EBITDA is earnings before interest, taxes, depreciation and amortization.  Adjusted EBITDA is presented here as a measure of liquidity because it can be used as an indication of a company’s ability to incur and service debt and is commonly used as an analytical indicator in our industry.  Adjusted EBITDA measures presented may not be comparable to similarly titled measures used by other companies.  Adjusted EBITDA is not a measurement presented in accordance with United States generally accepted accounting principles (GAAP), and we do not intend Adjusted EBITDA to represent cash flows from operations as defined by GAAP. Adjusted EBITDA should not be considered to be an alternative to cash flows from operations or any other items calculated in accordance with GAAP or an indicator of our operating performance.

UniSource Energy and TEP believe Adjusted EBITDA, which is a non-GAAP financial measure, provides useful information to investors as a measure of liquidity.  The most directly comparable GAAP measure to Adjusted EBITDA is Net Cash Flows from Operating Activities.

 
Adjusted EBITDA and Net Cash Flows from Operating Activities

UniSource Energy
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
  Adjusted EBITDA (non-GAAP)
   $ 461     $ 470     $ 445     $ 444  
  Net Cash Flows - Operating Activities (GAAP)
   $ 323     $ 283     $ 274     $ 307  
  Net Cash Flows - Investing Activities (GAAP)
   $ (217 )   $ (246 )   $ (170 )   $ (156 )
  Net Cash Flows - Financing Activities (GAAP)
   $ (119 )   $ (77 )   $ (113 )   $ (98 )

TEP
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
  Adjusted EBITDA (non-GAAP)
   $ 409     $ 420     $ 400     $ 411  
  Net Cash Flows - Operating Activities (GAAP)
   $ 264     $ 227     $ 243     $ 275  
  Net Cash Flows - Investing Activities (GAAP)
   $ (137 )   $ (182 )   $ (129 )   $ (126 )
  Net Cash Flows - Financing Activities (GAAP)
   $ (120 )   $ (79 )   $ (174 )   $ (101 )

Reconciliation of Adjusted EBITDA to Cash Flows from Operating Activities

UniSource Energy
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
Adjusted EBITDA (non-GAAP) (1)
   $ 461     $ 470     $ 445     $ 444  
Amounts from the Income Statements:
                                
  Less:  Income Taxes
     (39 )     (44 )     (38 )     (37 )
            Total Interest Expense
     (138 )     (152 )     (160 )     (168 )
Changes in Assets and Liabilities and Other Non-Cash Items
     39       9       27       68  
Net Cash Flows - Operating Activities (GAAP)
   $ 323     $ 283     $ 274     $ 307  
Net Cash Flows - Investing Activities (GAAP)
   $  (217 )   $  (246 )   $  (170 )   $  (156 )
Net Cash Flows - Financing Activities (GAAP)
   $  (119 )   $  (77 )   $  (113 )   $  (98 )
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP)
   $ (14 )   $ (40 )   $ (9 )   $ 53  


TEP
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
Adjusted EBITDA (non-GAAP) (1)
   $ 409     $ 420     $ 400     $ 411  
Amounts from the Income Statements:
                                
  Less:   Income Taxes
     (36 )     (42 )     (34 )     (35 )
             Total Interest Expense
     (117 )     (127 )     (140 )     (157 )
Changes in Assets and Liabilities and Other Non-Cash Items
     8       (24 )     17       56  
Net Cash Flows - Operating Activities (GAAP)
   $ 264     $ 227     $ 243     $ 275  
Net Cash Flows - Investing Activities (GAAP)
   $  (137 )   $  (182 )   $  (129 )   $  (126 )
Net Cash Flows - Financing Activities (GAAP)
   $  (120 )   $  (79 )   $  (174 )   $  (101 )
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP)
   $ 7     $ (34 )   $ (60 )   $ 48  

(1) Adjusted EBITDA was calculated as follows:

UniSource Energy
  
2007
    
2006
  
 
2005
    
2004
  
   
- Millions of Dollars -
  
Net Income (GAAP)
   $ 58     $ 67     $ 46     $ 46  
Amounts from the Income Statements:
                                
  Less:  Discontinued Operations
     -       (2 )     (5 )     (5 )
            Cumulative Effect of Accounting Change
     -       -       (1 )     -  
  Plus:   Income Taxes
     39       44       38       37  
Total Interest Expense
     138       152       160       168  
            Depreciation and Amortization
     141       131       133       132  
            Amortization of Transition Recovery Asset
     78       66       56       50  
            Depreciation Included in Fuel and Other O&M
                                
              Expense (See Note 16 of Notes to Consolidated
                                
              Financial Statements)
     7       8       6       6  
Adjusted EBITDA (non-GAAP)
   $ 461     $ 470     $ 445     $ 444  

TEP
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
Net Income (GAAP)
   $ 53     $ 67     $ 48     $ 46  
Amounts from the Income Statements:
                                
  Less:  Cumulative Effect of Accounting Change
     -       -       (1 )     -  
  Plus:   Income Taxes
     36       42       34       35  
            Total Interest Expense
     117       127       140       157  
            Depreciation and Amortization
     120       112       115       117  
            Amortization of Transition Recovery Asset
     78       66       56       50  
            Depreciation Included in Fuel and Other O&M
                                
              Expense (See Note 16 of Notes to Consolidated
                                
              Financial Statements)
     5       6       6       6  
Adjusted EBITDA (non-GAAP)
   $ 409     $ 420     $ 400     $ 411  


Net Debt, Total Debt and Capital Lease Obligations - TEP

Net Debt represents the current and non-current portions of TEP’s long-term debt and capital lease obligations less investment in lease debt.  We have subtracted investment in lease debt because it represents TEP’s ownership of the debt component of its own capital lease obligations.  Net Debt measures may not be comparable to similarly titled measures used by other companies.  Net Debt is not a measurement presented in accordance with GAAP and we do not intend Net Debt to represent debt as defined by GAAP.  You should not consider Net Debt to be an alternative to debt or any other items calculated in accordance with GAAP.  We believe Net Debt, which is a non-GAAP measure, provides useful information to investors as a measure of TEP’s debt and capital lease obligations.
 

As of December 31,
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
Net Debt (non-GAAP)
   $ 1,306     $ 1,335     $ 1,379     $ 1,684  
Total Debt and Capital Lease Obligations (GAAP)
   $ 1,411     $ 1,468     $ 1,535     $ 1,855  

Reconciliation of Total Debt and Capital Lease Obligations to Net Debt

As of December 31,
  
2007
    
2006
    
2005
    
2004
  
   
- Millions of Dollars -
  
Long-Term Debt
   $ 683     $ 821     $ 821     $ 1,098  
Current Portion – Long-Term Debt
     138       -       -       2  
  Total Debt (GAAP)
     821       821       821       1,100  
                                 
Capital Lease Obligations
     531       588       665       701  
Current Portion – Capital Lease Obligations
     59       59       49       54  
Total Debt and Capital Lease Obligations (GAAP)
     1,411       1,468       1,535       1,855  
                                 
Investment in Lease Debt
     (105 )     (133 )     (156 )     (171 )
Net Debt (non-GAAP)
   $ 1,306     $ 1,335     $ 1,379     $ 1,684  


ITEM 7. – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UniSource Energy and its three primary business segments and includes the following:

 
·
outlook and strategies,
 
·
operating results during 2007 compared with 2006, and 2006 compared with 2005,
 
·
factors which affect our results and outlook,
 
·
liquidity, capital needs, capital resources, and contractual obligations,
 
·
dividends, and
 
·
critical accounting policies.

UniSource Energy is a holding company that has no significant operations of its own.  Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities.  UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years.  UES was established in 2003, when it acquired the Arizona gas and electric properties from Citizens.  UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in Northern and Southern Arizona.  Millennium has existing investments in unregulated businesses; however no new investments are planned at Millennium.  UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a gas turbine project in Northern Arizona that, subject to ACC approval, is expected to provide energy to UNS Electric.  We conduct our business in three primary business segments – TEP, UNS Gas and UNS Electric.

On March 31, 2006, Millennium sold its interest in Global Solar Energy, Inc. (Global Solar), its largest holding.  At December 31, 2007, the investment in Millennium represented 3% of UniSource Energy’s Total Assets.

UNISOURCE ENERGY CONSOLIDATED

OUTLOOK AND STRATEGIES

Our financial prospects and outlook for the next few years will be affected by many competitive, regulatory and economic factors.  Our plans and strategies include the following:

·
Obtain ACC approval of a rate increase for TEP, effective January 2009, that resolves the uncertainty surrounding TEP’s rates for generation service after 2008, while providing adequate revenues to cover the rising cost of serving TEP’s customers and preserving TEP’s benefits under the Settlement Agreement;

·
Obtain ACC approval of rate increases for UNS Gas and UNS Electric to provide adequate revenues to cover the rising cost of providing service to their customers;

·
Efficiently manage our generation, transmission and distribution resources and seek ways to control our operating expenses while maintaining and enhancing reliability, safety and profitability;

·
Diversify TEP’s portfolio of generating and purchased power resources, along with programs to expand renewable energy sources and demand side management,  to meet growing retail energy demand and respond to wholesale market opportunities;

·
Expand UNS Electric’s portfolio of generating and purchased power resources to substitute for the May 2008 expiration of the full requirements contract with Pinnacle West Marketing and Trading (PWMT) and to meet growing retail energy demand;
 

·
Enhance the value of existing generation assets by working with Salt River Project to support the construction of Springerville Unit 4;

·
Enhance the value of TEP’s transmission system while continuing to provide reliable access to generation for TEP and UNS Electric’s retail customers and market access for all generating assets;

·
Continue to develop synergies between UNS Gas, UNS Electric and TEP;

·
Improve UniSource Energy’s and TEP’s ratio of common equity to total capitalization; and

·
Promote economic development in our service territories.

While we believe that our plans and strategies will continue to have a positive impact on our financial prospects and position, we recognize that we continue to be highly leveraged, and as a result, our access to the capital markets may be limited or more expensive than for less leveraged companies.

RESULTS OF OPERATIONS

Executive Overview

UniSource Energy recorded Income Before Discontinued Operations and Cumulative Effect of Accounting Change of $58 million in 2007, $69 million in 2006 and $52 million in 2005.  Net Income of $67 million in 2006 reflects a $2 million loss from discontinued operations; net income of $46 million in 2005 reflects a $5 million loss from discontinued operations and a $1 million loss from the cumulative effect of an accounting change.
 
2007 Compared With 2006

The decrease in UniSource Energy’s net income in 2007 is due primarily to higher fuel and purchased power costs.  Coal-related fuel expense at TEP was higher due primarily to a new rail and coal contract for Sundt Unit 4 that took effect at the beginning of 2007.  Hot summer weather and planned coal plant outages at TEP during the first quarter put upward pressure on gas-related fuel costs and purchased power costs.  Other factors impacting UniSource Energy’s net income in 2007 included higher TRA amortization expense at TEP and increased operations and maintenance costs.

On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar in the future. In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $2 million related to the discontinued operations and disposal of Global Solar.
See Other Non-Reportable Segments, Results of Operations, Discontinued Operations – Global Solar, below.
 
2006 Compared With 2005

The improvement in UniSource Energy’s results in 2006 compared with 2005 was due primarily to: the higher availability of TEP’s coal-fired generating plants; the start of commercial operations at Luna in April 2006; retail customer growth at TEP; interest savings related to various financing activities in 2005 and 2006; and the commencement of commercial operation of Springerville Unit 3 in August 2006.  See Tucson Electric Power Company, Results of Operations, below, and Tucson Electric Power Company, Liquidity and Capital Resources, Financing Activities, below.
 

CONTRIBUTION BY BUSINESS SEGMENT

The table below shows the contributions to our consolidated after-tax earnings by our three business segments and Other net income (loss).

 
2007
2006
2005
 
-Millions of Dollars-
TEP
$  53
$  67
$  49
UNS Gas
     4
    4
     5
UNS Electric
     5
    5
     5
Other (1)
     (4)
    (7)
     (7)
Income Before Discontinued Operations and
Cumulative Effect of Accounting Change
   58
  69
   52
Discontinued Operations – Net of Tax (2)
  -
   (2)
     (5)
Cumulative Effect of Accounting Change – Net of Tax
  -
   -
     (1)
Consolidated Net Income
$  58
$  67
$  46

(1) Includes: UniSource Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement; in the first nine months of 2005, interest expense (net of tax) on the note payable from UniSource Energy to TEP; and income and losses from Millennium investments and UED.

(2) Relates to the discontinued operations of Global Solar.


LIQUIDITY AND CAPITAL RESOURCES

UniSource Energy Consolidated Cash Flows

 
2007
2006
2005
 
-Millions of Dollars-
Cash provided by (used in):
      
Operating Activities
$ 323
$ 283
$ 274
Investing Activities
  (217)
  (246)
  (170)
Financing Activities
  (119)
    (77)
  (113)

UniSource Energy’s consolidated cash flows are provided primarily from retail and wholesale energy sales at TEP, UNS Gas and UNS Electric, net of the related payments for fuel and purchased power.  Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load.  Cash used for investing activities is primarily a result of capital expenditures at TEP, UNS Gas and UNS Electric.  In 2006, cash used for investing activities was higher due to TEP’s purchase of a 14% interest in Springerville Unit 1.  Cash used for financing activities can fluctuate year-to-year depending on:  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.

The primary source of liquidity for UniSource Energy, the parent company, is dividends from its subsidiaries, primarily TEP.  Also, 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 on a stand-alone basis and each of its segments.
 

Balances As of
February 26, 2008
Cash and Cash
Equivalents
Borrowings
under Revolving
Credit Facility(3)
Amount Available
under Revolving
Credit Facility
 
-Millions of Dollars-
UniSource Energy stand-alone
$     2
$    33
$    37
TEP
     19
     70
     80
UNS Gas
      8
     10
         20 (1)
UNS Electric
      6
     30
        15 (1)
Other
         31 (2)
     NA
     NA
Total
$   66
    

(1) Currently, either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, but the total combined amount borrowed cannot exceed $60 million.
(2) Includes cash and cash equivalents at Millennium.
(3) Includes LOCs issued under Revolving Credit Facilities

Executive Overview

Operating Activities

In 2007, net cash flows from operating activities were $40 million higher than 2006.  The increase is primarily due to higher retail kWh sales in TEP’s service territory, operating receipts received by TEP related to Springerville Unit 3, lower income taxes paid and lower interest paid on capital lease obligations.

Investing Activities

Net cash used for investing activities was $29 million lower in 2007 compared with 2006, primarily because in 2006, TEP used $48 million to purchase lease equity related to Springerville Unit 1.  This was partially offset by the $16 million in proceeds that UniSource Energy received in 2006 related to the sale of Global Solar.  In addition, capital expenditures were higher in 2007 due primarily to the construction of BMGS by UED, as well as overall utility system growth.

Forecasted Capital Expenditures

Business Segment
2008
2009
2010
2011
2012
 
-Millions of Dollars-
TEP
$307
$249
$284
$295
$223
UNS Gas
   26
   24
   21
   24
   25
UNS Electric
   45
   40
   33
   41
   40
Other(1)
   15
   -
   -
   -
   -
UniSource Energy Consolidated
$393
$313
$338
$360
$288

(1) Represents capital expenditures by UED related to the 90 MW BMGS that is currently under construction in Kingman, Arizona, in UNS Electric’s service area.  The project is expected to be completed by May 2008.

Capital expenditures of $1.4 billion for 2008 through 2011 are expected to be $187 million, or 15% higher than forecasted amounts reported in 2007.  This increase is the result of several factors including: higher material and construction costs; the need to increase high-voltage transmission capacity into TEP’s service territory; the reinforcement and expansion of distribution facilities; environmental upgrades to generating facilities; generation needs for UNS Electric and customer growth in UniSource Energy’s utility service territories.

Financing Activities

Net cash flows used for financing activities were $42 million higher in 2007 compared with 2006, primarily due to higher net repayments on revolving credit facilities and higher scheduled payments on capital lease obligations by TEP.
 

As a result of the activities described above, our consolidated cash and cash equivalents decreased to $90 million at December 31, 2007, from $104 million at December 31, 2006.  We invest cash balances in high-grade money market securities with an emphasis on preserving the principal amounts invested.

UniSource Energy Credit Agreement

The UniSource Credit Agreement consists of a $30 million amortizing term loan facility and a $70 million revolving credit facility and matures in August 2011.

Principal payments of $1.5 million on the outstanding term loan are due quarterly, with the balance due at maturity.  At December 31, 2007, there was $21 million outstanding under the term loan facility and $20 million outstanding under the UniSource Energy revolving credit facility at a weighted average interest rate of 6.27%.  

We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, sales of assets, and certain investments and acquisitions.  We must also meet: (1) a minimum cash flow to debt service coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis. We may pay dividends if, after giving effect to the dividend payment, we have more than $15 million of unrestricted cash and unused revolving credit.  As of December 31, 2007, we were in compliance with the terms of the UniSource Credit Agreement.

If an event of default occurs, the UniSource Credit Agreement may become immediately due and payable.  An event of default includes failure to make required payments under the UniSource Credit Agreement, failure of UniSource Energy or certain subsidiaries to make payments or default on debt greater than $20 million, or certain bankruptcy events at UniSource Energy or certain subsidiaries.

Liquidity Outlook

As a result of growing capital expenditures at UniSource Energy’s subsidiaries, the revolving credit facilities at UniSource Energy, TEP, UNS Gas and UNS Electric may be used on a more frequent basis.  Other funding sources to meet the capital requirements of the strong utility customer growth could include the issuance of long-term debt, as well as capital contributions from UniSource Energy to its subsidiaries.  The need for external funding sources is partially dependent on the outcome of rate-related proceedings at TEP, UNS Gas and UNS Electric.

In August 2008, TEP and UNS Electric will have long-term debt maturities of $138 million and $60 million, respectively.  Both companies expect to refinance the maturing debt with new debt issuances prior to August 2008.

For more information concerning liquidity and capital resources, see Tucson Electric Power Company, Liquidity and Capital Resources, below, UNS Gas, Liquidity and Capital Resources, UNS Electric, Liquidity and Capital Resources, and Other Non-Reportable Segments, Liquidity and Capital Resources, below.

Guarantees and Indemnities

In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis.  The most significant of these guarantees at December 31, 2007 were:

 
·
UES’ guarantee of senior unsecured notes issued by UNS Gas ($100 million) and UNS Electric ($60 million);
 
·
UES’ guarantee of the $60 million UNS Gas/UNS Electric revolver; and
 
·
UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas.  In January 2008, UniSource Energy was released from a $3 million guarantee on behalf of UNS Gas.
 

To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in UniSource Energy’s consolidated balance sheets.

In addition, UniSource Energy and its subsidiaries have indemnified the purchasers of interests in certain investments from additional taxes due for years prior to the sale.  The terms of the indemnifications provide for no limitation on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations.  We have not made any payments under the terms of these indemnifications to date.

We believe that the likelihood that UniSource Energy would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.

Contractual Obligations

The following chart displays UniSource Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2007.

UniSource Energy’s Contractual Obligations
- Millions of Dollars -
  
Payment Due in Years
       Ending December 31,
  
2008
    
2009
    
2010
    
2011
    
2012
    
2013
and after
    
 
Other
    
Total
  
Long Term Debt
                                                
     Principal(1)
   $ 204     $ 6     $ 6     $ 428     $ -     $ 555     $ -     $ 1,199  
     Interest(2)
     62       44       45       42       32       506       -       731  
Capital Lease Obligations(3):
                                                                
     Springerville Unit 1(4)
     82       30       57       83       85       231       -       568  
     Springerville Coal Handling
     18       15       17       19       23       56       -       148  
     Sundt Unit 4
     12       13       14       -       -       -       -       39  
     Springerville Common
     5       5       5       5       10       135       -       165  
Operating Leases
     2       2       2       1       -       2       -       9  
Purchase Obligations(5):
                                                                
     Coal and Rail Transportation(6)
     87       78       78       44       37       216       -       540  
     Purchase Power(7)
     66       83       39       15       8       8       -       219  
     Electric Generating Turbines
     13       -       -       -       -       -       -       13  
     Transmission
     6       5       5       3       2       7       -       28  
     Gas(8)
     84       51       29       11       3       26       -       204  
Other Long-Term Liabilities(9):
                                                                
     Pension & Other Post
        Retirement Obligations(10)
     15       5       5       6       6       32       -       69  
     San Juan Pollution Control
        Equipment(11)
     58       15       -       -       -       -       -       73  
     Acquisition of Springerville
        Coal Handling and Common
        Facilities(12)
     -       -       -       -       -       226         -       226  
     Unrecognized Tax Benefits(13)
     -       -       -       -       -       -       12       12  
 Total Contractual Cash
        Obligations
   $ 714     $ 352     $ 302     $ 657     $ 206     $ 2,000     $ 12     $ 4,243  

(1)  Includes quarterly principal payments due on the term loan facility in UniSource Energy’s Credit Agreement and amounts outstanding under the UniSource Energy and UNS Electric revolving credit facilities.  TEP’s variable rate IDBs are backed by letters of credit issued pursuant to TEP’s Credit Agreement which expires in August 2011.  Although the variable rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the letters of credit terminate without replacement upon expiration of the TEP Credit Agreement.
 (2)  Includes letter of credit and remarketing fees on variable rate debt.  The interest rates for variable rate debt are estimated using Eurodollar futures rates for an approximation of LIBOR.  For variable rate IDBs, a
 
 
discount is applied to estimated LIBOR based on the historical discount the IDBs have had to LIBOR.  Excludes interest on revolving credit facilities.
(3)  Beginning with commercial operation of Springerville Unit 3 in September 2006, Tri-State is reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% of the Springerville Common Lease payments and 17% of the Springerville Coal Handling Facilities Lease payments.  Similar reimbursement obligations are required after Springerville Unit 4 is constructed.  TEP remains the obligor under these capital leases.  Capital Lease Obligations do not reflect any reduction associated with this reimbursement.
(4) Annual payments under the Springerville Unit 1 lease vary in accordance with the amortization schedules of the debt underlying the capital lease, with significantly larger principal payments occurring in 2008, 2011, and 2012.
(5)  Purchase obligations reflect the minimum contractual obligation under legally enforceable contracts with contract terms that are both fixed and determinable.   The total amount paid under these contracts depends on the quantity purchased and transported.  TEP and UES’ requirements are expected to be in excess of these minimums.  UniSource Energy has excluded open purchase orders of approximately $19 million expected to be fulfilled in 2008.
(6) On average, TEP expects to spend $214 million annually for the purchase and transportation of coal through 2012.
(7) Includes TEP and UNS Electric’s forward power purchases.
(8) Amounts include TEP and UNS Gas’ fixed price forward gas purchases and firm transportation agreements with EPNG and Transwestern. Incremental gas purchases are excluded as prices and volumes vary.  Amounts also exclude swap agreements which are marked to market on a monthly basis and do not include any minimum payment obligation.  TEP and UNS Gas entered into forward gas purchases for 2008 through 2011 totaling $9 million subsequent to December 31, 2007, which are excluded from the table above.
(9)  Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the remote generating stations.  TEP estimates its undiscounted final reclamation liability is $47 million with reclamation beginning in 2028.  See Note 5.  Also excludes asset retirement obligations expected to occur through 2066.  Also, excludes Millennium’s equity commitments totaling $1 million over two years to fund a subsidiary (Valley Ventures III and Valley Ventures III Annex) as suitable investments are identified.
 (10)  These obligations represent TEP and UES’ minimum required contributions to pension plans in 2008 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 2008 due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts.  TEP funds the postretirement benefit plan on a pay-as-you-go basis.
(11)  These obligations represent TEP’s share of the cost of new pollution control equipment based on its ownership of San Juan.  Under a settlement agreement signed in March 2005 with the New Mexico Environmental Department and environmental activist groups, the co-owners of San Juan will install new technology at the generating station to reduce mercury, particulate matter, NOx, and SO2 emissions.  In addition, TEP’s share of increased operating and maintenance costs associated with the new technologies is expected to be approximately $1 million per year over the next 10 years.
(12)  TEP has agreed with the owners of Springerville Units 3 and 4 that, upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP will exercise its fixed price purchase option under such lease and  acquire the leased facilities.  The fixed prices to acquire such facilities will be $120 million in 2015, $38 million in 2017, and $68 million in 2021.  Upon such acquisitions by TEP, each of the owners of Springerville Unit 3 and Unit 4 have the obligation to purchase from TEP a 17% interest in the Springerville Coal Handling Facilities and a 14% interest in the Springerville Common Facilities.
(13)  As a result of adopting FIN 48 on January 1, 2007, TEP recorded a liability for uncertain tax positions.  At December 31, 2007, TEP’s liability totals $12 million.  TEP is unable to estimate when its liability for uncertain tax positions will be settled.  Tax years 2002 through 2006 are open under federal, Arizona and New Mexico statutes.

We have reviewed our contractual obligations and provide the following additional information:

 
·
We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
 
·
None of our contracts or financing arrangements contains acceleration clauses or other consequences triggered by changes in our stock price.


Dividends on Common Stock

On February 27, 2008, UniSource Energy declared a first quarter cash dividend of $0.24 per share on its Common Stock.  The first quarter dividend, totaling approximately $9 million, will be paid March 21, 2008 to shareholders of record at the close of business March 10, 2008.  During 2007, UniSource Energy paid quarterly dividends to its shareholders of $0.225 per share; for all of 2007, total dividends paid were $32 million.  In 2006, UniSource Energy paid quarterly dividends to its shareholders of $0.21 per share; for all of 2006, total dividends paid were $29 million.

Income Tax Position

At December 31, 2007, UniSource Energy and TEP had, for federal and state income tax filing purposes, the following carryforward amounts:

 
UniSource Energy
TEP
 
Amount
Expiring
Amount
Expiring
 
-Millions of Dollars-
Year
-Millions of Dollars-
Year
Capital Loss
$     4
2010-2011
$     -
-
AMT Credit
     41
-
     27
-

Internal Revenue Service Matters

On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets.  The new accounting method was also used on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.

In 2005, the Internal Revenue Service (IRS) issued a ruling limiting the ability of electric and gas utilities to use the new accounting method.  As a result, TEP, UNS Gas and UNS Electric amended their 2002, 2003 and 2004 Federal and state tax returns to remove the benefit previously claimed using the accounting method and remitted tax and interest of $31 million for TEP and $1 million for UNS Gas and UNS Electric to the IRS and state tax authorities.   Based on settlement guidelines relating to the accounting method that were issued by the IRS in March 2007, TEP, UNS Gas and UNS Electric have settled this issue with the IRS.  The company recorded the effects of the settlement in December 2007 by recognizing $2 million in interest income related to the settlement.  The company anticipates receiving $12 million in taxes and interest during 2008 which will have no impact on the overall tax provision or on net income.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

The financial condition and results of operations of TEP are currently the principal factors affecting the financial condition and results of operations of UniSource Energy on an annual basis.  The following discussion relates to TEP’s utility operations, unless otherwise noted.

2007 Compared with 2006

TEP recorded net income of $53 million in 2007 compared with $67 million last year.  The following factors contributed to the decrease:

 
·
a $7 million increase in total operating revenues less fuel and purchased power expense due to the following:

·
a $37 million increase in retail revenues due to hot weather during the third quarter, cool weather during the first quarter and customer growth;

·
a $17 million increase in wholesale revenues.   Wholesale revenues in 2007 and 2006 included $8 million and $3 million, respectively, of transmission revenues related to Springerville Unit 3.  Wholesale revenues also benefited from higher short-term wholesale sales activity;
 

·
a $27 million increase in other revenues due primarily to fees and reimbursements received from Tri-State for fuel and O&M costs related to Springerville Unit 3 and reimbursements received from SRP for expenses related to Springerville Unit 4; offset by:

·
a $40 million increase in purchased power expense due to increased retail energy demand during the third quarter, higher short-term wholesale activity and expenses related to the 100 MW purchased power contract with Tri-State that commenced in September 2006 and ended August 1, 2007; and

·
a $34 million increase in fuel expense due to an increase in gas-fired generating output, as well as increases in coal and rail expenses.  See Operating Expenses, Fuel and Purchased Power Expense, below.
 
Other factors impacting the results for 2007 include:
 
·
a $13 million increase in O&M expense due in part to planned maintenance outages at San Juan Unit 2 and Springerville Unit 2 during the first quarter of 2007.  Other factors contributing to higher O&M include a full year of operating expenses at Luna, and expenses related to Springerville Units 3 and 4 that TEP incurred and for which TEP received reimbursement from Tri-State and SRP.  TEP’s O&M expense in 2007 included $24 million related to Springerville Units 3 and 4, compared with $9 million last year.  O&M expense in 2007 was partially offset by a pre-tax gain of $15 million related to the sale of excess SO2 Emission Allowances, compared with a pre-tax gain of $7 million in the same period last year;

·
a $12 million increase in the amortization of TEP’s Transition Recovery Asset (TRA);

·
a $7 million increase in depreciation and amortization due primarily to additions to plant in service; and

·
a $10 million decrease in total interest expense due to lower balances on capital lease obligations.  In addition, interest expense in 2006 included an interest payment to the IRS for proposed adjustments to previously filed tax returns and the write-off of fees related to the amendment of TEP’s Credit Agreement.

In 2007, the net pre-tax benefit recognized by TEP related to Springerville Unit 3 for operating fees, a construction bonus and a reduction in its share of the common costs was $13 million.  See Tucson Electric Power Company, Factors Affecting Results of Operations Springerville Units 3 and 4, below. 

2006 Compared with 2005

TEP recorded net income of $67 million in 2006 compared with $48 million in 2005.  The following factors contributed to the improvement:

2006 included:

 
·
a $53 million increase in total operating revenues less fuel and purchased power expense due to the following:

 
·
a $28 million increase in retail revenues due to warm weather during the second quarter and retail customer growth;

 
·
a $9 million increase in wholesale revenues due primarily to $3 million of transmission revenues related to Springerville Unit 3 and a $6 million increase in unrealized gains related to mark-to-market adjustments on forward sales.  Margins on wholesale sales were lower than last year due to a decline in the average market price for power;

 
·
a $23 million increase in other revenues due primarily to fees and reimbursements received from Tri-State for fuel and O&M costs related to Springerville Unit 3;

 
·
a $24 million decrease in purchased power expense due to increased production at TEP’s coal-fired generating plants and the availability of Luna to offset some of the wholesale purchases to meet retail customer demand during peak summer periods.  Purchased power expense also reflects a $4 million increase in unrealized losses due to mark-to-market adjustments on forward purchases of energy; offset by
 

 
·
a $31 million increase in fuel expense due to increased generation at TEP’s coal-fired plants, gas-related fuel expense at Luna and $8 million of fuel costs associated with Springerville Unit 3;

 
·
a $31 million increase in O&M expense.  TEP’s O&M includes $9 million of expenses related to Springerville Unit 3.  In addition, pre-tax gains related to the sale of excess SO2 emission allowances were $7 million lower than 2005.  Other factors contributing to higher O&M include operating expenses at Luna; generating plant maintenance; and higher payroll expenses;

 
·
a $10 million increase in the amortization of TEP’s TRA; and

 
·
a $13 million decrease in total interest expense due primarily to lower interest on long-term debt and capital lease obligations, which was partially offset by interest paid to the IRS related to a notice of a proposed adjustment to previously filed tax returns and fees incurred in the third quarter of 2006 related to amending TEP’s Credit Agreement.

In 2006, the net pre-tax benefit recognized by TEP related to Springerville Unit 3 for operating fees and its share of the common costs was $4 million.

Utility Sales and Revenues

Customer growth, weather and other consumption factors affect retail sales of electricity.  Electric wholesale revenues are affected by market prices in the wholesale energy market, the availability of TEP generating resources, and the level of wholesale forward contract activity.

The table below provides trend information on retail sales by major customer class and electric wholesale sales made by TEP in the last three years as well as weather data for TEP’s service territory.

   
Sales
    
Operating Revenue
  
   
2007
    
2006
    
2005
    
2007
    
2006
    
2005
  
   
-Millions of kWh-
    
-Millions of Dollars-
  
Electric Retail Sales:
                                    
Residential
     4,005       3,778       3,633     $ 363     $ 343     $ 331  
Commercial
     2,058       1,959       1,856       214       203       193  
Industrial
     2,341       2,278       2,302       168       165       166  
Mining
     983       925       843       49       44       40  
Public Authorities
     247       261       241       18       19       17  
Total Electric Retail Sales
     9,634       9,201       8,875       812       774       747  
Electric Wholesale Sales Delivered:
                                                
   Long-term Contracts
     1,101       1,076       1,188       56       51       55  
Other Sales
     2,458       2,340       1,994       125       117       115  
Transmission
     -       -       -       15       11       8  
Total Electric Wholesale Sales
     3,559       3,416       3,182       196       179       178  
           Total Electric Sales
     13,193       12,617       12,057     $ 1,008     $ 953     $ 925  
                                                 
Weather Data:
                                                
Cooling Degree Days
     1,517       1,371       1,529                          
10-Year Average
     1,424       1,414       1,426                          
                                                 
Heating Degree Days
     1,506       1,295       1,257                          
10-Year Average
     1,497       1,487       1,488                          

2007 Compared with 2006

Total revenues from kWh sales to retail customers increased by $38 million, or 5%, in 2007 compared with 2006, due to hot summer weather, cooler temperatures during the winter months and customer growth.  Cooling degree days were 11% higher than last year and 7% above the 10-year average; heating degree days were 16% higher than last year and 2% above the 10-year average.
 

Wholesale revenues increased $17 million in 2007 compared with last year.  Wholesale revenues included $8 million in transmission revenues related to Springerville Unit 3 in 2007 and $3 million in 2006.  Wholesale kWh sales increased 3%; however, margins on wholesale sales were lower due to a 6% decrease in the average market price of wholesale energy.  See Factors Affecting Results of Operations,, Market Prices, below.

Mark-to-Market Adjustments on Trading Activity

The table below summarizes the net unrealized gains (losses) on TEP’s forward sales and purchases of energy.  The net unrealized gain (loss) on forward sales and purchases of energy is presented on the income statement in wholesale revenues.  Amounts for 2007 are based on the market price of energy as of December 31, 2007.

 
2007
2006
2005
 
-Millions of Dollars-
Net Unrealized Gain (Loss) on
Forward Sales of Energy

  $(8)

$ 7

$ 1
Net Unrealized (Loss) Gain on
Forward Purchases of Energy

    8

  (6)

  (2)
Net Unrealized Gain (Loss)
$  -
$ 1
$ (1)

2006 Compared with 2005

Total revenues from kWh sales to retail customers increased by $28 million, or 4%, in 2006 compared with 2005, due primarily to customer growth.

Wholesale revenues increased $9 million in 2006 compared with 2005.  In 2006, wholesale revenues included $3 million in transmission revenues related to Springerville Unit 3 and a $6 million increase in net unrealized gain due to mark-to-market adjustments on forward sales.  Wholesale kWh sales increased 8% primarily due to the higher availability of TEP’s coal plants; however, margins on wholesale sales were lower due to a 16% decrease in the average market price of wholesale energy.  TEP’s margins on wholesale sales were higher in 2005, as hurricane activity in the Gulf of Mexico boosted market prices for wholesale energy in the last six months of the year.  See Factors Affecting Results of Operations, Market Prices, below.
 

Operating Expenses

2007 Compared with 2006

Fuel and Purchased Power

TEP’s fuel and purchased power expense, and energy resources for 2007, 2006 and 2005 are detailed below:

   
Generation
    
Expense
  
   
2007
    
2006
    
2005
    
2007
    
2006
    
2005
  
   
-Millions of kWh-
    
-Millions of Dollars-
  
Coal-Fired Generation
                                    
   Four Corners
     717       812       783     $ 12     $ 12     $ 11  
   Navajo
     1,283       1,215       1,221       21       17       16  
   San Juan
     2,306       2,486       2,484       53       56       53  
   Springerville
     5,914       5,827       5,572       96       96       94  
   Sundt 4
     750       623       787       25       14       16  
Total Coal-Fired Generation
     10,970       10,963       10,847     $ 207     $ 195     $ 190  
Gas-Fired Generation
                                                
   Luna
     782       516       -       46       24       -  
   Other Units
     306       334       368       33       31       36  
Total Gas-Fired Generation
     1,088       850       368       79       55       36  
Solar and Other Generation
     9       9       9       -       -       -  
Total Generation (1)
     12,067       11,822       11,224       286       250       226  
Total Purchased Power
     2,047       1,680       1,639       140       100       133  
Total Resources
     14,114       13,502       12,863     $ 426     $ 350     $ 359  
Less Line Losses and Company Use
     921       885       806                          
Total Energy Sold
     13,193       12,617       12,057                          

(1) Fuel expense in 2007 and 2006 excludes $5 million and $8 million, respectively, related to Springerville Unit 3; the fuel costs incurred on behalf of Unit 3 are recorded in Fuel Expense and the reimbursement by Tri-State is recorded in Other Revenue.

Despite similar output from TEP’s coal-fired generating units compared with last year, total coal-related fuel expense was $12 million, or 6% higher than 2006.  Higher coal and rail costs at Sundt Unit 4 and higher mining costs at Navajo were partially offset by $8 million of settlement benefits and year-end adjustments associated with mining costs at San Juan.

As a result of higher retail demand, TEP used Luna to help offset the amount of purchased power needed to serve peak demand during the summer months.  Gas-fired generation increased by 28% and gas-related fuel expense was $24 million higher than 2006 due to the availability of Luna for all of 2007 and higher retail energy demand.

Higher retail energy demand, increased wholesale sales activity and energy purchased from Tri-State under a purchased power agreement contributed to an increase in power purchases of 458,000 MWh, or 27%, compared with last year.  Purchased power expense increased by $40 million as a result of the higher purchase volumes and demand charges associated with the Tri-State purchased power contract.

The table below shows TEP’s average resource cost per kWh generated and purchased:

 
2007
2006
2005
 
-cents per kWh-
Coal
1.89
1.78
1.75
Gas*
7.26
6.69
9.78
Purchased Power
6.84
5.95
8.11
All Sources - Average
3.02
2.59
2.79

*In 2006, the average cost of gas generation per kWh excludes test energy produced at Luna and its associated fuel costs.
 

TRA Amortization

TRA amortization was $12 million higher in 2007 compared with 2006.  Amortization of the TRA is the result of the Settlement Agreement with the ACC, which changed the accounting method for TEP’s generation operations.  This item reflects the recovery, through 2008, of transition recovery assets which were previously regulatory assets of the generation business.  The amount of amortization is a function of the TRA balance and total kWh consumption by TEP’s distribution customers.  TEP expects the TRA balance of $24 million at December 31, 2007 to be fully amortized in May 2008. See Factors Affecting Results of Operations, TEP Rate Proposal Filing, Fixed CTC, below.

Operating Expenses

2006 Compared with 2005

Fuel and Purchased Power

The start of commercial operation of Luna and higher coal plant availability in the summer months led to a $24 million increase in fuel expense in 2006 (excluding fuel expenses at Springerville Unit 3); however, purchased power expense decreased $24 million as these same factors reduced TEP’s need to purchase power during the summer months to meet retail demand.  Gas-fired generation more than doubled in 2006, causing gas-related fuel expense to increase $19 million, or 53%.  Coal-fired generation increased 1%, leading to a $5 million increase in coal-related fuel expense.  Luna’s generation output reported in the table above includes energy generated during its test phase, but does not include any associated fuel costs which were capitalized and reported as project costs.

Despite a 4% increase in purchased energy volumes, purchased power expense was $24 million, or 18%, lower due to a decrease in average wholesale energy prices in 2006 as well as fewer short-term purchases during the summer months when market prices for wholesale energy are typically higher.  In September 2006, TEP began purchasing energy from Tri-State under a 100 MW purchased power agreement that was terminated August 1, 2007.

TRA Amortization

TRA amortization increased $10 million in 2006.  See 2007 Compared with 2006, TRA Amortization, above for further explanation of the TRA.

Other Income (Deductions)

In 2005, TEP’s Income Statement included inter-company Interest Income of $2 million.  This represented Interest Income on a promissory note TEP received from UniSource Energy in exchange for the transfer to UniSource Energy of its stock in Millennium in 1998.  UniSource Energy repaid the inter-company promissory note on March 1, 2005.  On UniSource Energy’s Consolidated Statement of Income, this Interest Income, as well as UniSource Energy’s related interest expense, was eliminated as an inter-company transaction. See Liquidity and Capital Resources, TEP Cash Flows, Inter-Company Note from UniSource Energy, below.

FACTORS AFFECTING RESULTS OF OPERATIONS
 
Competition

Retail

In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however, only a small number of commercial and industrial customers initially chose an ESP.  By 2002, none of TEP’s retail customers were served by an alternative ESP.

In 2004, an Arizona Court of Appeals decision held invalid certain portions of the ACC rules on retail competition and related market pricing.  In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition.  We cannot predict what changes, if any, the ACC will make to the competition rules.  TEP has met all conditions required by the ACC to facilitate electric retail competition, including ACC approval of TEP’s direct access tariffs.
 

TEP competes against gas service suppliers and others that provide energy services.  Other forms of energy technologies may provide competition to TEP’s services in the future, but to date, are generally not financially viable alternatives for its retail customers.  Self-generation by TEP’s large industrial customers could also provide competition for TEP’s services in the future, but has not had a significant impact to date.

Wholesale

In the wholesale market, TEP competes with other utilities, power marketers and independent power producers in the sale of electric capacity and energy.

Settlement Agreement

In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.

The Rules and the Settlement Agreement established:

 
·
a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;
 
·
the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (Fixed CTC);
 
·
capped rates for TEP retail customers through 2008;
 
·
an ACC interim review of TEP retail rates in 2004;
 
·
unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;
 
·
a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers;
 
·
access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs); and
 
·
transmission and distribution services would remain subject to regulation on a cost of service basis.

We believe that the Settlement Agreement contemplates that TEP’s retail rates for generation service be market-based beginning on January 1, 2009.

Track A Proceeding

During 2002 and 2003, the ACC reexamined circumstances that had changed since it approved the Rules in 1999.  One issue, called Track A, related primarily to the divestiture of generation.

Under the ACC’s Rules, TEP and other utilities were required to divest their generation assets.  TEP later requested a waiver of the divestiture requirement.  The Track A order granted TEP’s request and eliminated the divesture requirement.  As a result, generation assets remain at TEP.  At the same time, the ACC ordered the parties, including TEP, to develop a competitive bidding process and reduced the minimum amount of power to be acquired in the competitive bidding process to only that portion not supplied by TEP’s existing resources.

2004 General Rate Case Information

In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC.  TEP’s filing did not propose any change in retail rates at that time and, under the terms of the Settlement Agreement, no rate case filed by TEP through 2008 may result in a net rate increase.  However, absent the restriction on raising rates, TEP believes that the data in its filing would have justified an increase in retail rates of 16%.

The general rate case information used a historical test year ended December 31, 2003 and established, based on TEP’s Standard Offer service, excluding the $0.009 per kWh Fixed CTC, that TEP was experiencing a revenue deficiency of $111 million.  None of the intervenor testimony filed proposed any decrease to TEP’s rates.  Testimony filed by the ACC Staff, RUCO and Arizonans for Electric Choice and Competition indicated revenue deficiencies, excluding Fixed CTC revenue, for TEP of $67 million, $32 million and $38 million, respectively.  In 2005, the ALJ issued a procedural order suspending the remaining testimony filing deadlines and hearing in the 2004 rate review.
 

TEP Rate Proceeding

Beginning in May 2005, TEP filed a series of pleadings requesting the ACC to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008.  TEP filed the pleadings in response to the Arizona Court of Appeals’ ruling related to retail competition and market pricing and a lack of agreement by a number of participants in TEP’s rate proceedings on rate methodology after 2008.  TEP believes that the Settlement Agreement contemplated market based rates for generation service after 2008; other participants, including ACC Staff, disagree and have stated that the Settlement Agreement does not control how TEP’s rates for generation service will be established after 2008.

Procedural Schedule

In February 2008, the ACC modified the schedule for TEP’s rate proceeding.  ACC Staff and intervenor testimony is due February 29, 2008.  The remainder of the procedural schedule is as follows:

 
Date
TEP rebuttal to intervenor testimony
April 1, 2008
ACC Staff and intervenor surrebuttal testimony
April 24, 2008
TEP rejoinder testimony
May 7, 2008
Hearings before ALJ
May 12, 2008

In accordance with an ACC order in this proceeding, TEP filed the three rate proposal methodologies described below, with the ACC to establish new rates for TEP when the existing rate increase moratorium of the Settlement Agreement is lifted on January 1, 2009.  At this time, TEP cannot predict whether any of the proposed methodologies will be adopted by the ACC or when the ACC will issue its final order.

As part of this proceeding, all of TEP’s legal rights and claims arising out of the Settlement Agreement and the decision approving the Settlement Agreement are fully preserved.  If TEP does not receive adequate rate relief from the ACC, TEP’s results of operations, net income and cash flows could be negatively impacted.  In that case, TEP may initiate legal proceedings against i) the ACC, and other parties, for breach of the Settlement Agreement and, ii) against the ACC for inadequate rates.

Fixed CTC and Incremental Revenue
According to a May 8, 2007 order of the ACC, TEP’s current Standard Offer rates shall  remain at their current level, including continued collection of an amount equivalent to the Fixed CTC ($0.009 per kWh), until the effective date of a final order in the rate proposal proceeding.  The incremental revenue collected as a result of continuing to collect an amount equivalent to the Fixed CTC after it would otherwise terminate (estimated to be $65 million) shall accrue interest and shall be subject to refund or credit or other such mechanism to protect customers, as determined in the rate proposal docket.

An ACC decision regarding TEP’s rate proceeding is expected in the fourth quarter of 2008.  Prior to an ACC decision, the revenues will not be recognized as income because the revenues collected are subject to refund.  Consequently, second and third quarter earnings are expected to be substantially below prior year quarterly results.

The Fixed CTC would otherwise terminate when the TRA balance is amortized to zero (approximately May 2008).  From January 1, 2008 to approximately May 31, 2008, TEP expects to record Fixed CTC revenues of approximately $28 million and amortization expense of approximately $24 million related to the TRA.  In 2007, TEP recorded $78 million of amortization expense related to the TRA.  After the expiration of the Fixed CTC, TEP does not expect to record any similar revenues or expense until or unless the ACC issues a final order that authorizes TEP to retain any incremental revenues.

TEP has proposed a full refund of these “true up” revenues over a 12-month period under the Market Methodology.  Under the Cost-of-Service and Hybrid Methodologies, TEP proposes other credits and offsets to be provided to customers in lieu of a refund.
 

TEP Rate Proposals

Rate Proposal Summary

The table below summarizes the major components for each of the rate methodologies, which are all based on a test year ending December 31, 2006.  All methodologies reflect a pro forma capital structure of 45% equity and 55% debt, as well as a 10.75% return on equity, a 6.39% cost of debt and an 8.35% weighted average cost of capital.

 
 
Market
 
Cost of Service
 
Hybrid
Rate increase over current average rates
22%
23%
15%
 
Annual revenue increase based on current average rates
$172 million
$181 million (including collection of TCRA)
 
$117 million
Original cost rate base
$540 million
$983 million
$921 million
 
Fair value rate base*
$777 million
$1.42 billion
$1.31 billion
 
Rate base composition
Distribution and Local Generation assets
Distribution and Generation assets
Distribution and Generation assets (excluding Navajo and Four Corners)
 
TCRA
N/A
$788 million; not included in rate base
 
N/A
ICRA
$14 million included in rate base
$47 million included in rate base
$47 million included in rate base
 
PPFAC
 
N/A
 
Yes
 
Yes
*Fair value rate base as traditionally calculated by the ACC

Market Methodology

Under this methodology, rates for generation service would be determined by using the market-based proxy, the Market Generation Credit (MGC), which was developed pursuant to the Settlement Agreement and approved by the ACC.  Rates for transmission and distribution would be determined using cost-of-service principles.

TEP’s ACC rate base under this methodology would include an Implementation Cost Regulatory Asset (ICRA) of $14 million amortized over four years to reflect a portion of the costs of TEP’s transition to retail competition under the Settlement Agreement.  Under this methodology, transmission and ancillary service rates would reflect the rates in TEP’s FERC-approved Open Access Transmission Tariff (OATT), and TEP’s service area would remain open to direct access retail competition.

If adopted, TEP’s rate filing indicated that the Market Methodology would result in a projected overall increase of approximately 22% over current rates.

Cost-of-Service Methodology

This methodology would determine rates for generation, transmission and distribution using cost-of-service principles.

TEP’s ACC rate base under this methodology would include an ICRA of $47 million (including the $14 million described in the Market Methodology) amortized over four years to reflect the total costs of TEP’s transition to retail competition under the Settlement Agreement, in addition to a Termination Cost Regulatory Asset (TCRA) of $788 million to be recovered over 10 years for the economic burden shouldered by TEP under the Settlement Agreement, assuming TEP is not permitted to charge market rates for generation service beginning in 2009.

Also with this methodology, a Purchased Power and Fuel Adjustor Clause (PPFAC) would be implemented.  Luna would be included in the PPFAC at $7 per KW-month for capacity plus the cost of fuel; in addition, Springerville
 
 
Unit 1 would be included in base rates at its market value of $25.67 per kW-month; transmission and ancillary service rates would reflect TEP’s OATT rate; and the exclusivity of TEP’s Certificate of Convenience and Necessity would be restored.

If adopted, TEP’s rate filing indicated that the Cost-of-Service Methodology would result in a projected overall increase of approximately 23% over current rates.  Excluding the TCRA, TEP’s rate filing indicated a projected overall rate increase of approximately 8% over current rates.

Hybrid Methodology

This methodology would utilize a hybrid ratemaking approach whereby TEP’s generation, transmission and distribution rates would be established by the same cost-of-service principles in the Cost-of-Service Methodology described above including the PPFAC and $47 million ICRA.  However, certain generation assets would be excluded from cost-of-service ratemaking.  The Hybrid Methodology would not include the TCRA.

The excluded generation assets would consist of TEP’s interest in Navajo Units 1, 2 and 3  and its interest in Four Corners Generating Station Units 4 and 5 (the “Excluded Generation Assets”).  TEP’s share of the generating capacity at Navajo and Four Corners is approximately 278 MW. The Excluded Generation Assets would be dedicated to wholesale market transactions.

Under this methodology, transmission and ancillary service rates would reflect TEP’s OATT rate, and TEP’s service area would be open to direct access retail competition for customers with at least 3 MW of load.

If adopted, TEP’s rate filing indicated that the Hybrid Methodology would result in a projected overall increase of approximately 15% over current rates.

Regulatory Assets

In the Cost-of-Service Methodology, the $788 million TCRA consists of foregone revenues under the rate freeze, along with carrying costs on the accumulated balance.  The foregone revenues are based on the annual retail revenue deficiency of $111 million for the test year ended December 31, 2003, identified by TEP in the 2004 rate review docket.  A separate charge of 1.26 cents/kWh represents the average retail rate TEP believes to be necessary to fully recover the TCRA over an estimated ten year time period.

In each of the three methodologies, TEP is seeking to include the ICRA in rate base to be amortized over four years.  The $14 million ICRA in the Market Methodology represents costs previously authorized by the ACC, while the $47 million ICRA in the Cost-of- Service and Hybrid Methodologies represents the total costs (excluding foregone revenues) incurred by TEP to transition to electric competition.

Purchased Power and Fuel Adjustment Clause

TEP does not currently have in place a PPFAC.  TEP is proposing a PPFAC that would reflect a forward-looking estimate of fuel and purchased power costs.  A PPFAC is included in both the Cost-of-Service and Hybrid Methodologies.

The PPFAC is proposed to be structured as follows:

Forward Component.  This component would be based on the difference between the forecasted fuel and purchased power costs for the following year and the amount recovered through base rates.  For example, forecasts for fuel and purchased power in 2010 would be used to establish the PPFAC Forward Component for 2010 as compared with the base cost of power included in rates.

True-Up Component. This component would reflect the difference between actual fuel and purchase power costs with the amount TEP collected through both base rates and the PPFAC rate in a given year.  If actual costs were above (below) what was collected, the True-Up Component would be charged (credited) to the PPFAC rate for the subsequent year.

TEP’s proposal assumes the Base Cost of Fuel and Purchased Power for 2009 is based on forward market conditions for 2009, resulting in a PPFAC rate for 2009 of zero.  The PPFAC mechanism would be used to set the PPFAC for 2010 and subsequent years.
 

In the Cost-of-Service Methodology, TEP would credit 90% of short-term wholesale revenues against fuel and purchased power costs.  In the Hybrid Methodology, TEP would credit 100% of short-term wholesale revenues against these costs.

FERC Proceeding

TEP is a party to a proceeding pending at FERC involving the interpretation of the 1982 Power Exchange and Transmission Agreement (1982 Agreement) between TEP and El Paso Electric (El Paso).  The dispute relates to TEP’s ability to use existing rights for the transmission of power from Luna to TEP’s system.    On September 6, 2007, a FERC ALJ issued an initial decision, subject to full FERC review, that supports TEP’s position.   

As part of this proceeding, TEP has requested that FERC order El Paso to refund transmission charges paid by TEP during the pendency of this dispute proceeding. These refunds include $3.5 million paid to El Paso in 2006, $3 million paid to El Paso in 2007, as well as any additional disputed transmission purchased prior to FERC issuing its final order.  TEP expects FERC to issue its final order in 2008.

Market Prices

As a participant in the Western U.S. wholesale power markets, TEP is directly and indirectly affected by changes in market conditions.  The average annual market price for around-the-clock energy based on the Dow Jones Palo Verde Index was lower in 2007 than in 2006, and the average annual price for natural gas based on the Permian Index increased in 2007 compared with last year.  We cannot predict whether changes in various factors that influence demand and supply will cause prices to change during 2008.

Avg. Market Price for Around-the-Clock Energy - $/MWh
2007
2006
2005
Quarter ended December 31
$ 52
$ 48
$ 78
Year ended December 31
  47
   50
   59
       
Avg. Market Price for Natural Gas - $/MMBtu
2007
2006
2005
Quarter ended December 31
$6.06
$5.58
$9.67
Year ended December 31
  6.11
 6.05
 7.17

Short-term and spot power purchase prices are also closely correlated to natural gas prices.  Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years.  TEP currently has approximately 25% of this exposure hedged for the summer peak period of 2008 (June – September) at a weighted average price of $7.45 per MMBtu.  TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.

Market prices may also affect TEP’s wholesale revenues.  TEP commits to future sales of energy as part of its ongoing efforts to hedge its excess generation based on projected generation capability, forward prices and generation costs.  For  2008, TEP has sold forward approximately 287,000 MWh at an average price of $56 per MWh.

Coal Supply

We expect TEP's total coal-related fuel expense across all of its plants to increase by $18 million in 2008, compared with 2007.  Excluding the $8 million of settlement benefits and year-end adjustments related to mining costs San Juan recognized in the fourth quarter of 2007, general cost pressures are expected to increase total coal-related fuel expense by $10 million, or 5% in 2008.

Generating Plant Operating Performance

In February 2008, Springerville Unit 1 incurred a partial collapse of one of four scrubber modules.  Structural inspection is proceeding on the seven remaining scrubber modules on Springerville Units 1 and 2 to determine both the short and long-term repairs required for continued reliable operation.  The inspections are expected to be completed in March 2008.  TEP may incur up to $10 million of capital and operating costs in 2008 to repair the scrubber modules, some portion of which will be covered by insurance.  During the module repair process, the output from Springerville Units 1 and 2 could be reduced by 10 to 15 MW for each unit.  The duration of the repair process depends on the outcome of the inspection.
 
 
Emission Allowances

TEP has SO2 Emission Allowances in excess of what is required to operate its generating units.  The excess results primarily from a higher removal rate of SO2 emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations.  From time to time, TEP will sell a portion of its excess SO2 Emission Allowances.  The table below summarizes sales made since 2005.

 
Delivery
 
Allowances Sold
Pre-tax Gain
(millions)
2005
15,000
$13
2006
10,000
    7
2007
22,000
  15

TEP expects to have approximately 14,000 excess SO2 Emission Allowances through 2009.  Existing regulations call for changes to the EPA SO2 Emissions Allowances allocation beginning in 2010.  As a result, beginning in 2010, TEP’s SO2 Emissions Allowances allocations will slightly decrease.  In addition, TEP expects the market for SO2 Emissions Allowances to change and their value to decline.

Springerville Units 3 and 4

TEP operates Springerville Unit 3 on behalf of Tri-State and receives annual pre-tax benefits in the form of rental payments and other fees and cost savings.  TEP recorded pre-tax benefits of $13 million in 2007 and $4 million in 2006 related to Springerville Unit 3.

Springerville Unit 4 is under construction and expected to be completed by the end of 2009.  TEP will operate Springerville Unit 4 on behalf of SRP and expects to receive annual pre-tax benefits of approximately $8 million in the form of rental payments and other fees and cost savings.

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

During 2008, TEP expects to generate sufficient internal cash flows to fund a portion of its construction expenditures as well as its operating activities, required debt maturities and dividends to UniSource Energy.  Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load.  As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to fund its business activities.

The table below shows the cash available to TEP after capital expenditures, scheduled debt payments and payments on capital lease obligations:

 
2007
2006
2005
 
-Millions of Dollars-
Net Cash Flows – Operating Activities (GAAP)
$   264
$   227
$   243
Amounts from Statements of Cash Flows:
    
Less: Capital Expenditures
     (163)
    (156)
     (150)
Net Cash Flows after Capital Expenditures (non-GAAP)*
     101
      71
       93
Amounts from Statements of Cash Flows:
  
Less: Retirement of Capital Lease Obligations
      (71)
     (61)
       (53)
Plus: Proceeds from Investment in Lease Debt
      28
     22
       14
Net Cash Flows after Capital Expenditures and
Required Payments on Debt and Capital Lease
Obligations (non-GAAP)*
$     58
$    32
$    54


 
2007
2006
2005
Net Cash Flows – Operating Activities (GAAP)
$ 264
$ 227
$ 243
Net Cash Flows – Investing Activities (GAAP)
  (137)
  (182)
  (129)
Net Cash Flows – Financing Activities (GAAP)
  (120)
    (79)
  (174)
Net Cash Flows after Capital Expenditures (non-GAAP)*
  101
    71
    93
Net Cash Flows after Capital Expenditures and
Required Payments on Debt and Capital Lease
Obligations (non-GAAP)*
 
 
   58
 
 
    32
 
 
    54

* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows - Operating Activities, which is determined in accordance with GAAP as a measure of liquidity.  We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments provide useful information to investors as measures of liquidity and our ability to fund our capital requirements, make required payments on debt and capital lease obligations, and pay dividends to UniSource Energy.

Liquidity Outlook

As a result of growing capital expenditures, TEP may use its revolving credit facility on a more frequent basis.  Other funding sources to meet the capital requirements from TEP’s strong customer growth could include the issuance of long-term debt as well as capital contributions from UniSource Energy.  The need for external funding sources is partially dependent on the outcome of TEP’s rate proceedings.

In August 2008, $138 million of TEP mortgage bonds with a coupon of 7.5% will mature.  TEP expects to refinance the maturing debt with a new debt issuance prior to August 2008.

Operating Activities

In 2007, net cash flows from operating activities increased by $37 million compared with the same period in 2006.

In 2007, net cash flows were impacted by:

 
·
an $11 million decrease in cash receipts from electric retail and wholesale sales, net of fuel and purchased energy costs, due primarily to higher coal-related fuel expense and power purchases made during peak summer demand periods;

 
·
a $10 million increase in proceeds from the sale of excess SO2 emission allowances;

 
·
a $6 million decrease in total interest paid due to lower capital lease obligation balances, lower long-term debt balances and lower annual fees under the TEP Credit agreement that was entered into in May 2005 and amended in August 2006;

 
·
a $22 million increase in other cash receipts due primarily to payments from Tri-State for fees and the reimbursement of operating costs related to Springerville Unit 3;

 
·
a $46 million decrease in income taxes paid due to lower taxable income and payments made last year for amended tax returns; offset by

 
·
a $23 million increase in O&M costs due primarily to operating costs for Springerville Unit 3, which are reimbursed to TEP and recorded as Cash Receipts from Operation Springerville Unit 3, and higher generating plant maintenance costs;

 
·
a $7 million increase in taxes other than income taxes; and

 
·
a $5 million increase in wages paid.

Investing Activities

Net cash used for investing activities was $45 million lower in 2007 compared with 2006 primarily due to:
 

 
·
a $6 million increase in proceeds from investments in Springerville Lease Debt;

 
·
a $6 million increase in capital expenditures related to TEP’s share of the construction costs of
Luna and growth and maintenance of TEP’s electric system; and

 
·
in 2006, TEP’s purchase of a 14% equity interest in Springerville Unit 1 Lease, which represents approximately 53 MW of capacity.

Capital Expenditures

TEP’s forecasted capital expenditures are summarized below:

Category
2008
2009
2010
2011
2012
 
-Millions of Dollars-
Transmission, Distribution and Other Facilities
$183
$157
$219
$165
$171
Generation Facilities
    64
   76
    58
  119
   48
Environmental
    60
   16
      7
    11
     4
   Total
$307
$249
$284
$295
$223

Capital expenditures for TEP for 2008 through 2011 are expected to be $1.1 billion, or 20% higher than reported in 2007.  This increase is the result of several factors including: higher material and construction costs; the need to increase high-voltage transmission capacity into TEP’s service territory; the reinforcement and expansion of transmission and distribution facilities; environmental upgrades to generating facilities; and customer growth.

These estimated expenditures include costs for TEP to comply with current federal and state environmental regulations. These estimates do not include the costs to construct the proposed Tucson to Nogales, Arizona transmission line.   All of these estimates are subject to continuing review and adjustment.  Actual construction expenditures may be different from these estimates due to changes in business conditions, construction schedules, environmental requirements, and changes to TEP’s business arising from retail competition.  TEP plans to fund these expenditures through internally generated cash flow.

Tucson to Nogales Transmission Line

If all regulatory approvals are received, the future costs to construct the transmission line from Tucson to Nogales, Arizona are expected to be approximately $95 million. Through December 31, 2007, approximately $11 million in land acquisition, engineering and environmental expenses have been incurred on this project.  If the required approvals are not received, TEP may be required to expense a portion of the costs that have been capitalized related to the project, propose alternative methods to the ACC for improving reliability and spend additional amounts to implement such alternatives.  See Item 1. Business, Tucson Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.

In addition to TEP’s forecasted capital expenditures for construction, TEP’s other capital requirements include its required debt maturities and capital lease obligations.  See Note 7 of Notes to Consolidated Financial Statements – Debt, Credit Facilities, and Capital Lease Obligations.

Investments in Springerville Lease Debt and Equity

At December 31, 2007, TEP had $153 million of investments in lease debt and equity on its balance sheet.  The yields on TEP’s investments in Springerville Lease Debt, at the date of purchase, range from 8.9% to 12.7%.  The table below provides a summary of the investment balances in lease debt.

 
Lease Debt Investment Balance
 
Leased Asset
December 31, 2007
December 31, 2006
 
- In Millions -
Investments in Lease Debt:
    
  Springerville Unit 1
$  71
$   81
  Springerville Coal Handling Facilities
    34
    52
Total Investment in Lease Debt
$105
$133

 
TEP’s 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.

See Note 7 of Notes to Consolidated Financial Statements – Debt, Credit Facilities and Capital Lease Obligations

Financing Activities

Net cash used for financing activities was $41 million higher in 2007 compared with 2006.  The following factors contributed to the increase:

2007 included:

 
·
a $20 million net repayment under the TEP Revolving Credit Facility compared with $30 million in net borrowings in 2006; and

 
·
a $10 million increase in scheduled payments made on capital lease obligations; offset by

 
·
a $9 million decrease in dividends paid to UniSource Energy; and

 
·
an $18 million capital contribution from UniSource Energy;

At December 31, 2007, there were $10 million in outstanding borrowings under the TEP Revolving Credit Facility.

TEP Credit Agreement

The TEP Credit Agreement consists of a $150 million revolving credit facility and a $341 million letter of credit facility which supports $329 million of tax-exempt variable rate bonds.  The TEP Credit Agreement matures in 2011 and is secured by $491 million of Mortgage Bonds.  At December 31, 2007, there was $10 million outstanding under the Revolving Credit Facility at an interest rate of 7.25%.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings.  Letter of credit fees are 0.55% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.55% per annum.  TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.55% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leaseback agreements.  The TEP Credit Agreement also requires TEP to meet a minimum cash coverage ratio and a maximum leverage ratio.  If TEP complies with the terms of the TEP Credit Agreement, it may pay dividends to UniSource Energy.  As of December 31, 2007, TEP was in compliance with the terms of the TEP Credit Agreement.

If an event of default occurs, the TEP Credit Agreement may become immediately due and payable.  An event of default includes failure to make required payments under the TEP Credit Agreement; change in control, as defined; failure of TEP or certain subsidiaries to make payments or default on debt greater than $20 million; or certain bankruptcy events at TEP or certain subsidiaries.

Springerville Common Facilities Leases

In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station.  TEP refinanced the lease debt totaling $68 million in June 2006.  Interest is payable at LIBOR plus 1.5% through June 2009. The spread over LIBOR increases by 0.125% in June 2009 and every three years thereafter to 2% by June 2018.

In June 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt.  This swap has the effect of fixing the interest rate portion of rent at 7.27% on a portion of the principal balance, which was $36 million at December 31, 2007.

The LIBOR rate in effect on December 31, 2007 was 5.19%, and 5.63% on December 31, 2006, which resulted in a total interest rate on the lease debt of 6.69% at December 31, 2007, and 7.13% at December 31, 2006.
 

Inter-Company Note from UniSource Energy

In March 2005, UniSource Energy repaid to TEP a debt obligation in the principal amount of $95 million plus accrued interest of $11 million.  TEP used the proceeds of the May 2005 contribution to redeem or repurchase certain of its existing debt through tender offers and redemptions.  See Bond Repurchases and Redemptions, below.

Capital Contribution from UniSource Energy

In December 2007, UniSource Energy made an $18 million capital contribution to TEP and a $110 million contribution in May 2005.  TEP used the proceeds of the May 2005 contribution to redeem or repurchase certain of its existing debt through tender offers and redemptions.  See Bond Repurchases and Redemptions, below.

Bond Repurchases and Redemptions

TEP made a sinking fund payment of $1 million on its 6.1% IDBs in January 2005.  In March 2005, TEP redeemed at par the remaining $31 million of its 6.1% IDBs due in 2008, as well as the remaining $21 million of its 7.5% 1941 Mortgage IDBs due in 2006.

In May 2005, TEP used the proceeds from the repayment of the note from UniSource Energy and the capital contribution from UniSource Energy to purchase $147 million of its 1997 Pima Series B and $74 million of its 1997 Pima Series C fixed-rate tax-exempt bonds (Repurchased Bonds) at a price of $101.50 per $100 principal amount.  In May 2005, TEP redeemed at par the remaining $4 million of bonds outstanding under those series.  TEP did not cancel the bonds, which remain outstanding under their respective indentures.  The bonds are not reflected as debt on our balance sheet.  In February 2008, TEP received approval from the Industrial Development Authority of Pima County to issue refunding IDBs, the proceeds of which would be used to redeem the $221 million of  Unsecured IDBs held by TEP.

Mortgage Indenture

The Mortgage 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 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.

TEP’s Credit Agreement, which totals $491 million and is secured by Mortgage Bonds, limits the amount of mortgage bonds that may be outstanding to no more than $840 million.  At December 31, 2007, TEP had a total of $629 million in outstanding Mortgage Bonds, consisting of $491 million in bonds securing the TEP Credit Agreement, and $138 million in bonds securing the 7.50% Collateral Trust Bonds due in 2008.  Although the Mortgage would allow TEP to issue additional bonds, the limit imposed by the TEP Credit Agreement is more restrictive and is currently the governing limitation.

Tax-Exempt Local Furnishing Bonds

TEP has financed a substantial portion of utility plant assets with industrial development revenue bonds issued by the Industrial Development Authorities of Pima County and Apache County.  The interest on these bonds is excluded from gross income of the bondholder for federal tax purposes.  This exclusion is allowed because the facilities qualify as “facilities for the local furnishing of electric energy” as defined by the Internal Revenue Code.  These bonds are sometimes referred to as “tax-exempt local furnishing bonds.”  To qualify for this exclusion, the facilities must be part of a system providing electric service to customers within not more than two contiguous counties.  TEP provides electric service to retail customers in the City of Tucson and certain other portions of Pima County, Arizona and to Fort Huachuca in contiguous Cochise County, Arizona.

TEP has financed the following facilities, in whole or in part, with the proceeds of tax-exempt local furnishing bonds:  Springerville Unit 2, Sundt Unit 4, a dedicated 345-kV transmission line from Springerville Unit 2 to TEP’s retail service area (the Express Line), and a portion of TEP’s local transmission and distribution system in the Tucson metropolitan area.  As of December 31, 2007, TEP had approximately $359 million of tax-exempt local furnishing bonds outstanding.  Approximately $257 million in principal amount of such bonds financed Springerville Unit 2 and the Express Line.  In addition, approximately $31 million of remaining lease debt related to the Sundt Unit 4 lease obligation was issued as tax-exempt local furnishing bonds.
 

Various events might cause TEP to have to redeem or defease some or all of these bonds:

 
·
formation of an RTO or ISO;
 
·
asset divestiture;
 
·
changes in tax laws; or
 
·
changes in system operations.

TEP believes that its qualification as a local furnishing system should not be lost so long as (1) the RTO or ISO would not change the operation of the Express Line or the transmission facilities within TEP’s local service area, (2) the RTO or ISO allows pricing of transmission service such that the benefits of tax-exempt financing continue to accrue to retail customers, and (3) energy produced by Springerville Unit 2 and TEP’s local generating units continues to be consumed in TEP’s local service area.  However, there is no assurance that such qualification can be maintained.  Any redemption or defeasance of these bonds would likely require the issuance and sale of higher cost taxable debt securities in the same or a greater amount.

Capital Lease Obligations

At December 31, 2007, TEP had $589 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.

 
 
Leased Asset
 
Capital Lease Obligation Balance
at December 31, 2007
 
 
Expiration
 
- In Millions -
  
Springerville Unit 1
$346
2015
Springerville Coal Handling Facilities
    99
2015
Springerville Common Facilities
  107
2020
Sundt Unit 4
    36
2011
Other Leases
     1
2008
Total Capital Lease Obligations
$589
  

Except for TEP’s 14% equity ownership in the Springerville Unit 1 Leases and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases.  TEP may renew the leases or purchase the leased assets at such time.  The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, while the purchase price option is fixed for the Springerville Coal Handling Facilities and Common Facilities.  TEP’s capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.  See UniSource Energy, Contractual Obligations, footnote (3), for more information about the fixed purchase price amounts.
 

Contractual Obligations

The following chart displays TEP’s contractual obligations as of December 31, 2007 by maturity and by type of obligation.

TEP’s Contractual Obligations
- Millions of Dollars -
  
Payment Due in Years
       Ending December 31,
  
2008
    
2009
    
2010
    
2011
    
2012
    
2013
and after
    
 
Other
    
Total
  
Long Term Debt
                                                
     Principal
   $ 138     $ -     $ -     $ 329     $ -     $ 355     $ -     $ 822  
     Interest
     43       31       32       29       22       345       -       502  
Capital Lease Obligations:
                                                                
     Springerville Unit 1
     82       30       57       83       85       231       -       568  
     Springerville Coal Handling
     18       15       17       19       23       56       -       148  
     Sundt Unit 4
     12       13       14       -       -       -       -       39  
     Springerville Common
     5       5       5       5       10       135       -       165  
Operating Leases
     1       1       1       -       -       -       -       3  
Purchase Obligations:
                                                                
     Coal and Rail Transportation
     87       78       78       44       37       216       -       540  
     Purchase Power
     8       16       -       -       -       -       -       24  
     Transmission
     2       2       2       2       1       7       -       16  
     Gas
     28       13       4       -       -       -       -       45  
Other Long-Term Liabilities:
                                                                
     Pension & Other Post
        Retirement Obligations
     13       5       5       6       6       31       -       66  
     San Juan Pollution Control
        Equipment
     58       15       -       -       -       -       -       73  
     Acquisition of Springerville
        Coal Handling and Common
        Facilities
     -       -       -       -       -       226         -       226  
     Unrecognized Tax Benefits
     -       -       -       -       -       -       12       12  
 Total Contractual Cash
        Obligations
   $ 495     $ 224     $ 215     $ 517     $ 184     $ 1,602     $ 12     $ 3,249  

See UniSource Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, above, for a description of these obligations.

We have no other commercial commitments to report.

We have reviewed our contractual obligations and provide the following additional information:

 
·
TEP’s Credit Agreement contains pricing for its Revolving Credit Facility based on TEP’s credit ratings.  A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings.

 
·
TEP’s Credit Agreement contains certain financial and other restrictive covenants, including interest coverage and leverage tests.  Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding.  At December 31, 2007, 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 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, 2007, TEP has not been required to post such credit enhancement.

 
Dividends on Common Stock

TEP declared and paid dividends to UniSource Energy of $53 million in 2007, $62 million in 2006, and $46 million in 2005.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants.  As of December 31, 2007, 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 to pay dividends from current year earnings.

UNS GAS

RESULTS OF OPERATIONS

UniSource Energy formed two operating companies, UNS Gas and UNS Electric, to acquire the Arizona electric and gas assets from Citizens in 2003, as well as an intermediate holding company, UES, to hold the common stock of UNS Gas and UNS Electric.

UNS Gas reported net income of $4 million in 2007, $4 million in 2006, and $5 million in 2005.  We expect operations at UNS Gas to vary with the seasons, with peak energy usage occurring in the winter months.

As of December 31, 2007, UNS Gas had approximately 146,000 retail customers.  Average customer growth in 2007 of approximately 2% was lower than in previous years due to general economic conditions.  The table below shows UNS Gas’ therm sales and revenues for 2007, 2006 and 2005.

 
Sales
Revenues
 
2007
2006
 2005
2007
2006
 2005
 
-Millions of Therms-
-Millions of Dollars-
Retail Therm Sales:
            
   Residential
71
70
69
$ 90
$ 96
$ 79
   Commercial
31
30
29
34
38
29
   Industrial
2
3
3
2
3
2
   Public Authorities
8
7
7
7
8
7
Total Retail Therm Sales
112
110
108
133
145
117
   Transport
25
23
27
3
3
3
   Negotiated Sales Program (NSP)
 
19
 
17
 
21
 
13
 
12
 
16
Total Therm Sales
156
150
156
$ 149
$ 160
$ 136

Through a Negotiated Sales Program (NSP) approved by the ACC, UNS Gas supplies natural gas to some of its large transportation customers.  Approximately one half of the margin earned on these NSP sales is retained by UNS Gas while the remainder benefits retail customers through a credit to the Purchased Gas Adjustor (PGA) mechanism which reduces the gas commodity price.  See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.
 

The table below provides summary financial information for UNS Gas.

 
2007
2006
   2005
 
          -Millions of Dollars-
Gas Revenues
$ 149
$ 160
$ 136
Other Revenues
2
2
2
     Total Operating Revenues
151
162
138
Purchased Energy Expense
102
114
91
Other Operations and Maintenance Expense
27
25
23
Depreciation and Amortization
7
7
7
Taxes other than Income Taxes
3
3
3
     Total Other Operating Expenses
139
149
124
          Operating Income
12
13
14
Total Other Income
2
1
-
Total Interest Expense
7
7
6
Income Tax Expense
3
3
3
           Net Income
$   4
$   4
$   5

Retail therm sales were 2% higher in 2007 compared with 2006, due primarily to customer growth and cold weather during the fourth quarter.  Despite an increase in therm sales, retail revenues were lower compared with the same period last year due to a lower PGA surcharge.  In December 2007, UNS Gas implemented a rate increase of approximately 4% or a $5 million annual increase in revenues.   See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.

FACTORS AFFECTING RESULTS OF OPERATIONS

Rates

2007 Rate Order

In November 2007, the ACC issued a final order in the UNS Gas rate case, approving a $5 million, or 4% base rate increase.  New rates went into effect in December 2007. UNS Gas filed its general rate case in July 2006 requesting a $9 million, or 7% base rate increases (over test year revenues) to recover the costs related to serving its growing customer base.  UNS Gas also received modifications to its PGA mechanism to help address problems posed by volatile gas prices.  Below is a table that summarizes UNS Gas’ request and the ACC order:

 
Test year – December 31, 2005
Requested
by UNS Gas
 
ACC Order
Original cost rate base
$162 million
$154 million
Revenue deficiency
$9 million
$5 million
Total rate increase (over test year revenues)
7%
4%
Cost of debt
6.60%
6.60%
Cost of equity
11.00%
10.00%
Hypothetical capital structure
50% equity / 50% debt
50% equity / 50% debt
Weighted average cost of capital
8.80%
8.30%

Energy Cost Adjustment Mechanism

UNS Gas’ retail rates include a PGA mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor.  The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportation recovered through base rates is deferred and recovered or repaid to customers through the PGA mechanism.

The current PGA mechanism has two components, the PGA factor and the PGA surcharge or credit.  The PGA factor is a mechanism that compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period.  The ACC Order increased the annual cap on the maximum increase in the PGA factor from $0.10 per therm to $0.15 per therm in a twelve month period.  In addition, the ACC Order set the base cost of gas at zero, so that the entire cost of gas will be reflected in the PGA factor.  Prior to the ACC Order, the base cost of gas was $0.40 per therm.
 

At any time UNS Gas’ 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 so that the ACC can determine how the over-collected balance should be returned to customers.  On December 31, 2007, the PGA bank balance was over-collected by $3 million on a billed to customers basis ($13 million on an accrual (GAAP) basis).

In September 2007, the ACC approved a 4 cent per therm PGA credit, effective October 2007 through April 2008.  Based on current projections of gas prices, UNS Gas believes that the credit amount will allow it to timely recover its gas costs and still provide rate relief to its customers.  Changes in the market price for gas, sales volumes and surcharge amount could significantly change the PGA bank balance in the future.

 2008 General Rate Case Filing

Due to increases in capital and operating costs related to providing safe and reliable service to customers of UNS Gas, the rates approved by the ACC in 2007 are inadequate for UNS Gas to recover its costs and earn a reasonable rate of return on its investments.

On February 21, 2008, UNS Gas filed a general rate case.  Below is a table that summarizes UNS Gas’ request:

Test year ended
September 30, 2007
Fair value rate base
$236 million
Original cost rate base
$173 million
Revenue deficiency
$10 million
Total rate increase (over test year revenues)
7%
Cost of debt
6.6%
Cost of equity
11.0%
Hypothetical capital structure
50% equity / 50% debt
Weighted average cost of capital
8.8%
Rate of return on fair value rate base
7.3%
Rate of return on original cost rate base
9.9%

UNS Gas proposed a rate of return of 7.3% be applied to its test year fair value rate base of $236 million.  This methodology is different from the approach the ACC used in UNS Gas’ 2007 rate order.  UNS Gas believes that applying a rate of return of 7.3% to its fair value rate base would give UNS Gas an opportunity to earn its proposed return on equity of 11.0%.  UNS Gas’ proposed fair value rate base methodology accounts for approximately $3 million of the $10 million revenue deficiency.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas’ capital requirements consist primarily of capital expenditures.  In 2007, capital expenditures were $23 million.  UNS Gas expects internal cash flows to fund its future operating activities and a large portion of its construction expenditures. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements.  Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contribution from UniSource Energy.  The rate increase approved by the ACC in November 2007 covers some, but not all, of UNS Gas’ higher costs and capital investments.  UNS Gas may need to rely more heavily on external funding sources for capital expenditures until it receives a decision in the rate case filed in February 2008.
 

Operating Cash Flow and Capital Expenditures

The table below provides summary information for operating cash flow and capital expenditures:

 
2007
2006
2005
 
-Millions of Dollars-
Net Cash Flows – Operating Activities
$ 28
$ 32
$ 14
Capital Expenditures
   23
   23
   23

Forecasted capital expenditures for UNS Gas are as follows:

 
2008
2009
2010
2011
2012
 
- Millions of Dollars -
UNS Gas
$26
$24
$21
$24
$25

UNS Gas/UNS Electric Revolver

The UNS Gas/UNS Electric Revolver is a $60 million unsecured revolving credit facility which matures in August 2011.  Either borrower may borrow up to a maximum of $45 million so long as the combined amount borrowed does not exceed $60 million.

UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver.  UES guarantees the obligations of both UNS Gas and UNS Electric.

UNS Gas and UNS Electric have the option of paying interest on borrowings at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.  Letter of credit fees are 1.0% per annum.

The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, mergers and sales of assets; it also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower.  As of December 31, 2007, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.

If an event of default occurs, the UNS Gas/UNS Electric Revolver may become immediately due and payable.  An event of default includes failure to make required payments under the UNS Gas/UNS Electric Revolver, certain change in control transactions, certain bankruptcy events of UNS Gas or UNS Electric, or failure of UES, UNS Gas or UNS Electric to make payments or default on debt greater than $4 million.

UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures, or to issue letters of credit to provide credit enhancement for its natural gas procurement and hedging activities. As of February 26, 2008, UNS Gas had $10 million in outstanding letters of credit under the UNS Gas/UNS Electric Revolver.

Senior Unsecured Notes

UNS Gas has $100 million of senior unsecured notes outstanding consisting of $50 million of 6.23% Notes due in 2011 and $50 million of 6.23% Notes due in 2015 that are guaranteed by UES. The note purchase agreement for UNS Gas restricts transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness, and also contains a minimum net worth test.  As of December 31, 2007, UNS Gas was in compliance with the terms of its note purchase agreement.

UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends.  However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $7 million in short-term debt.
 

Contractual Obligations

UNS Gas Supply Contracts

UNS Gas has a natural gas supply and management agreement with BP Energy Company (BP).  Under the contract, BP manages UNS Gas’ existing supply and transportation contracts and its incremental requirements.    UNS Gas has given BP notice of its intent to terminate this agreement.  Beginning September 2008, UNS Gas will directly manage its gas supply and transportation contracts. Prices for incremental gas will vary based upon the market prices for the period during which the gas is delivered.

UNS Gas hedges its gas supply prices by entering into fixed price forward contracts and financial swaps at various times during the year to provide more stable prices to its customers.  These purchases are made up to three years in advance with the goal of hedging at least 45% of the expected monthly gas consumption with fixed prices prior to entering into the month.  UNS Gas hedged approximately 55% of its expected monthly consumption for the 2007/2008 winter season (November through March).  Additionally, UNS Gas has approximately 35% of its expected gas consumption hedged for April through October 2008, and 25% hedged for the period November 2008 through March 2009.

UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its load requirements.

UNS Gas currently has a transportation agreement with EPNG to serve its Northern and Southern Arizona service territories.  This agreement has specific contract volumes in each month and specific receipt point rights from the available supply basins (San Juan and Permian).  The average daily capacity rights of UNS Gas is approximately 655,000 therms per day, with an average of 1,095,000 therms per day in the winter season (November through March).

EPNG filed a rate case in 2005 with new, higher rates effective in January 2006, subject to refund.  The rate case participants reached a negotiated settlement and filed an agreement with FERC on December 6, 2006.  FERC issued an order approving the settlement in August 2007.  UNS Gas’ contract with EPNG expires in August 2011, and includes rights of first refusal thereafter for UNS Gas on the capacity at tariff rates.

UNS Gas has capacity rights of 250,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline.  The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman, Arizona, and also delivers gas to UNS Gas’ facilities serving the Griffith Power Plant in Mohave County.  The current contract with Transwestern expired in February 2007.  UNS Gas entered into a new firm transportation contract with Transwestern through February 2012, and includes rights of first refusal thereafter for UNS Gas on the capacity at tariff rates.  The new capacity rights under this agreement are: 250,000 therms per day October through April; 15,000 therms per day in May; and 10,000 therms per day June through September.

UNS Gas signed a separate transportation agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line.  The 15-year agreement will begin in late 2008, when construction of that pipeline is expected to be complete.  The average daily capacity right of UNS Gas will be 126,100 therms per day, with an average of 221,900 therms per day in the winter season (November through March).

Transwestern filed a general rate case with FERC in September 2006 and revised rates went into effect on April 1, 2007.  The new rates will result in an annual decrease in UNSE’s transportation costs on the Transwestern pipeline system of less than $1 million.  Transwestern is expected to file a new general rate case in 2010 or 2011.

The aggregate annual minimum transportation charges are expected to be approximately $9 million and $5 million for the EPNG and Transwestern contracts, respectively.  These costs are passed through to our customers via the PGA.

UNS Gas conducts certain of its gas procurement and risk management activities under certain 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, 2007, UNS Gas had posted $10 million in such credit enhancements.
 

Dividends on Common Stock

The note purchase agreement for UNS Gas contains restrictions on dividends.  UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test.  See Senior Unsecured Notes, above.  It is unlikely that UNS Gas will pay dividends in the next few years due to expected cash requirements for capital expenditures.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $5 million in 2007, and $5 million in 2006 and 2005.  Similar to TEP’s operations, we expect UNS Electric’s operations to be seasonal in nature, with peak energy demand occurring in the summer months.

As of December 31, 2007, UNS Electric had approximately 90,000 retail customers.  Approximately customer growth of 3% in 2007 was lower than in previous years due to general economic conditions.  Retail kWh sales were 4% higher in 2007 due to customer growth and warmer summer weather than 2006. The table below shows UNS Electric’s kWh sales and revenues for 2007, 2006 and 2005.

 
Sales
Revenues
 
2007
2006
2005
2007
2006
2005
 
-Millions of kWh-
-Millions of Dollars-
Electric Retail Sales:
            
Residential
    854
   804
   745
$   86
$   81
$   75
Commercial
    627
   613
   591
     64
     61
     60
Industrial
    199
   191
  182
     15
     15
     13
Other
       2
      3
      3
      -
       1
       1
Total Electric Retail Sales
1,682
1,611
1,521
$ 165
$ 158
$ 149

The table below provides summary financial information for UNS Electric.

 
2007
2006
2005
 
-Millions of Dollars-
Electric Revenues
$165
$158
$149
Other Revenues
     4
     2
     1
     Total Operating Revenues
  169
  160
  150
Purchased Energy Expense
  111
  106
  100
Other Operations and Maintenance Expense
    30
    26
    23
Depreciation and Amortization
    13
    11
    10
Taxes other than Income Taxes
     3
     4
     4
     Total Other Operating Expenses
  157
  147
  137
          Operating Income
   12
   13
   13
Total Other Income
    2
     1
    -
Total Interest Expense
    6
     5
    5
Income Tax Expense
    3
     4
    3
           Net Income
$   5
$    5
$    5


FACTORS AFFECTING RESULTS OF OPERATIONS

 
Competition

As required by the ACC order approving UniSource Energy’s acquisition of the Citizens’ Arizona gas and electric assets, in 2003 UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003.  The plan is subject to review and approval by the ACC, which has not yet considered the plan.  As a result of the court decisions concerning the ACC’s Rules, we are unable to predict when and how the ACC will address this plan.  See Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, above for information regarding the Arizona Court of Appeals decision.
 
 
Rates

Energy Cost Adjustment Mechanism

UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under or over recovery of costs.  The ACC has approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.

General Rate Case Filing

UNS Electric’s retail rates were last adjusted in August 2003.  As a result of increased growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Electric to recover its costs and earn a reasonable rate of return on its investment.  In December 2006, UNS Electric filed a general rate case.  Below is a table that summarizes UNS Electric’s request:

Test year
12 months ended June 30, 2006
Original cost rate base
$141 million
Revenue deficiency
$8.5 million
Total rate increase (over test year revenues)
5.5%
Cost of long-term debt
8.2%
Cost of equity
11.8%
Actual capital structure
49% equity / 51% debt
Weighted average cost of capital
9.9%

UNS Electric also requested the ACC to approve the acquisition of the 90 MW BMGS combustion turbine project under development by UED and to include the cost of the project in rate base effective June 1, 2008.   The cost of BMGS is expected to be $60 million to $65 million.

In June 2007, ACC Staff filed testimony that indicated a revenue deficiency for UNS Electric of approximately $4 million; RUCO’s testimony indicated a revenue deficiency of approximately $1 million.  Neither ACC Staff nor RUCO supported UNS Electric’s rate base proposal for BMGS.

UNS Electric also requested that a new PPFAC mechanism take effect beginning June 1, 2008, immediately following the expiration of the current power supply agreement with PWMT, that would utilize a forward looking projection of gas and purchased power costs. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Rates, for more information.

UNS Electric’s rate case hearings before the ALJ concluded in October 2007.  UNS Electric expects the ACC to rule on its rate case in the first half of 2008.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric’s capital requirements consist primarily of capital expenditures.  In 2007, capital expenditures were $38 million.  UNS Electric expects internal cash flows to fund its future operating activities and a portion of its construction expenditures. Sources of funding future capital expenditures could include draws on the revolving credit facility, additional credit lines, the issuance of long-term debt, or capital contributions from UniSource Energy.   The need for external funding sources is partially dependent on the outcome of UNS Electric’s general rate case that was filed in December 2006.

UniSource Energy made capital contributions to UNS Electric of $10 million in both 2007 and 2006.

In August 2008, $60 million of unsecured bonds with a coupon of 7.61% will mature.  UNS Electric expects to refinance the maturing debt with a new debt issuance prior to August 2008.
 

Operating Cash Flow and Capital Expenditures

The table below provides summary information for operating cash flow and capital expenditures.

 
2007
2006
2005
 
-Millions of Dollars-
Net Cash Flows – Operating Activities
$ 22
$ 14
$ 21
Capital Expenditures
   38
   39
   30

To improve the reliability of service in Santa Cruz County, UNS Electric completed a 20 MW gas-fired combustion turbine at the Valencia site in 2006, and plans to upgrade its existing 115 kV transmission line over time. The turbine improves reliability while the approval and permitting process for the 345 kV Tucson to Nogales transmission line continues.  See Item 1. Business, TEP Electric Utility Operations, Transmission Access, Tucson to Nogales Transmission Line.

Forecasted capital expenditures for UNS Electric are as follows:

 
2008
2009
2010
2011
2012
 
- Millions of Dollars -
UNS Electric
$45
$40
$33
$41
$40

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 26, 2008, UNS Electric had $30 million outstanding under the UNS Gas/UNS Electric Revolver.

Senior Unsecured Notes

UNS Electric has $60 million of 7.61% senior unsecured notes outstanding due in August 2008 that are guaranteed by UES. The note purchase agreements for UNS Electric contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, liens to secure indebtedness, restricted payments, incurrence of indebtedness, and minimum net worth.  As of December 31, 2007, UNS Electric was in compliance with the terms of its note purchase agreement.

UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends.  However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.

Contractual Obligations

UNS Electric Power Supply and Transmission Contracts

UNS Electric has a full requirements power supply agreement with Pinnacle West Marketing and Trading (PWMT), which expires in May 2008.  The agreement obligates PWMT to supply all of UNS Electric’s power requirements at a fixed price per MWh.  Payments under the contract are usage based, with no fixed customer or demand charges.  UNS Electric is in the process of securing replacement energy resources when its supply contract ends with PWMT in 2008.

During 2006 and 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $58 million in 2008, $67 million in 2009, $39 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices at the date of the contracts.
 

UNS Electric’s power purchase contracts and risk management activities are subject to master agreements whereby UNS Electric may be required to post margin due to changes in contract values or if there has been a material change in creditworthiness.  As of December 31, 2007, UNS Electric had not been required to post such credit enhancement.

UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines.  UNS Electric’s transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 2017 and 2011.  Under the terms of the agreements, UNS Electric’s aggregated minimum fixed transmission charges are expected to be $12 million in 2007 through 2011.  UNS Electric made payments under these contracts of $7 million in 2007 and $8 million in 2006.

Dividends on Common Stock

The note purchase agreement for UNS Electric contains restrictions on dividends.  UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test.  See Senior Unsecured Notes, above.  It is unlikely that UNS Electric will pay dividends in the next few years due to expected cash requirements for capital expenditures.

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.

 
2007
2006
2005
 
- Millions of Dollars -
   
UniSource Energy Parent Company
$   (5)
$   (6)
$   (6)
MEH
    1
    -
    (1)
UED
    -
    -
    -
Total Other Loss From Continuing Operations
$   (4)
$   (7)
$   (7)
Discontinued Operations – Net of Tax
    -
    (2)
     (5)
Total Other Net Loss
$   (4)
$   (9)
$  (12)

UniSource Energy Parent Company

UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes, the UniSource Credit Agreement and in 2005, a note payable from UniSource Energy to TEP, which was repaid in March 2005.

UED

In 2006, UED purchased two electric generating turbines for $17 million.  The turbines are part of the 90 MW BMGS, currently under construction in Kingman, Arizona, and, pending ACC approval, expected to provide energy to UNS Electric.  Construction of BMGS is estimated to be completed in May 2008.  UED is financing the BMGS project with borrowings from UniSource Energy under an inter-company note payable.  At December 31, 2007, there was $46 million outstanding and interest is payable quarterly at LIBOR plus 1.25%.  The cost of BMGS is expected to be $60 million to $65 million.  Total capital expenditures for BMGS were $26 million in 2007.

In 2005, UED had no significant operations.

Discontinued Operations – Global Solar

Global Solar recorded losses $2 million in 2006 and $5 million in 2005. On March 31, 2006, Millennium completed the sale of its interest in Global Solar.  In these financial statements, UniSource Energy accounts for Global Solar as a discontinued operation and recognizes 100% of Global Solar’s losses.
 

FACTORS AFFECTING RESULTS OF OPERATIONS

Millennium Investments

MEG settled its remaining outstanding positions in December 2007, and no further activities are anticipated.

Nations Energy Corporation (Nations Energy), a wholly-owned subsidiary of Millennium, has been inactive since 2001.  As of December 31, 2007, and December 31, 2006, Nations Energy had a deferred tax asset of $3 million related to investment losses that has not been reflected on UniSource Energy’s consolidated income tax return.

Millennium is in the process of exiting its remaining investments.  At December 31, 2007, the book value of Millennium’s investments was $28 million.

LIQUIDITY AND CAPITAL RESOURCES

Millennium made a $5 million dividend payment to UniSource Energy in February 2007 and a $10 million dividend payment to UniSource Energy in April 2007.

In 2006, Millennium funded $2 million to Haddington under an existing commitment.  In 2005, Haddington sold one of its investments and Millennium received a $6 million distribution related to the sale.  Millennium’s remaining commitment is $1 million to Valley Ventures.

In 2006, Millennium received the remaining payment of $5 million on a note receivable from a subsidiary of Mirant Corporation and, in 2005, received a payment of $4 million.

In 2005, Millennium received a $4 million payment from its investment in Carboelectrica Sabinas, S. de R.L. de C.V., (Sabinas) a Mexican limited liability company.  The $4 million payment was treated as the return of capital and the book value of the investment in Sabinas was reduced to approximately $14 million.  Millennium owns 50% of Sabinas.  A $2 million payment due to Millennium in June 2006 was cancelled in exchange for payment by Mimosa, an affiliate of Sabinas, for up to $2 million to obtain an evaluation of the interest in coal reserves and associated gas held by Mimosa.  This evaluation is being performed under Millennium’s direction, primarily to determine the impact of current regulatory changes in Mexico on the value of the Sabinas investment.  We expect the evaluation to be completed in the first half of 2008.  Upon completion of the evaluation, Millennium will consider its right to sell its interest in Sabinas to an AHMSA affiliate for $20 million.

CRITICAL ACCOUNTING POLICIES

In preparing financial statements under Generally Accepted Accounting Principles (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions.   UniSource Energy and TEP consider Critical Accounting Policies to be those that could result in materially different financial statement results if our assumptions regarding application of accounting principles were different.  UniSource Energy and TEP describe their Critical Accounting Policies below.  Other significant accounting policies and recently issued accounting standards are discussed in Note 1 of Notes to Consolidated Financial Statements – Nature of Operations and Summary of Significant Accounting Estimates.

Accounting for Rate Regulation

TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP.   However, sometimes these principles, such as the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), require special accounting treatment for regulated companies to show the effect of regulation.  For example, in setting TEP, UNS Gas and UNS Electric’s retail rates, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that these expenses be charged to customers in the future.  In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until TEP, UNS Gas and UNS Electric are allowed to charge their customers.  TEP, UNS Gas and UNS Electric then amortize these items as expense to the income statement as these charges are recovered from customers.  Similarly, certain revenue items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement as rates to customers are reduced.
 

The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:
 
·
an independent regulator sets rates;
 
·
the regulator sets the rates to recover the specific enterprise’s costs of delivering service; and
 
·
the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

TEP

Upon approval by the ACC of a settlement agreement (Settlement Agreement) in November 1999, TEP discontinued application of FAS 71 for its generation operations.  TEP continues to apply FAS 71 to its cost-based rate regulated operations, which include the transmission and distribution portions of its business.

TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $10 million at December 31, 2007.  Regulatory assets of $44 million are not presently included in the rate base and consequently are not earning a return on investment.  These regulatory assets are being recovered through the cost of service or are authorized to be collected in future base rates.  TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $118 million at December 31, 2006.

TEP regularly assesses whether it can continue to apply FAS 71 to its cost-based rate regulated operations.  If TEP stopped applying FAS 71 to its remaining regulated operations, it would write off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at December 31, 2007, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $6 million.  While regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if it stopped applying FAS 71 unless a regulatory order limited its ability to recover the cost of its regulatory assets.

UNS Gas and UNS Electric

UNS Gas's regulatory liabilities, net of regulatory assets, totaled $29 million at December 31, 2007 compared with regulatory liabilities, net of regulatory assets of $13 million at December 31, 2006.  UNS Electric’s regulatory liabilities, net of regulatory assets, totaled $19 million at December 31, 2007 and $12 million at December 31, 2005.  UNS Electric has $2 million of regulatory assets that are not included in rate base.  UNS Gas has $1 million of regulatory assets that are not included in rate base.  UNS Gas and UNS Electric regularly assess whether they can continue to apply FAS 71 to their cost-based rate regulated operations.  If UNS Gas and UNS Electric stopped applying FAS 71 to their regulated operations, they would write off the related balances of regulatory assets as an expense and regulatory liabilities as income on their income statements. Based on the balances of regulatory liabilities and assets at December 31, 2007, if UNS Gas and UNS Electric had stopped applying FAS 71 to their regulated operations, UNS Gas would record an extraordinary after-tax gain of $11 million and UNS Electric would record an extraordinary after-tax gain of $17 million.  UNS Gas and UNS Electric’s cash flows would not be affected if they stopped applying FAS 71 unless a regulatory order limited their ability to recover the cost of their regulatory assets.
 
Accounting for Asset Retirement Obligations

FAS 143, issued by the FASB, requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred.  A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.  A legal obligation can also be associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event.  We are required to record a conditional asset retirement obligation at its estimated fair value if that fair value can be reasonably estimated.  When the liability is initially recorded, the entity should capitalize a cost by increasing the carrying amount of the related long-lived asset.  Over time, the liability is adjusted to its present value by recognizing accretion expense as an operating expense in the income statement each period, and the capitalized cost is depreciated over the useful life of the related asset.  Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount.

TEP

In 2005, TEP implemented FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47).  The implementation of FIN 47 required TEP to update an existing inventory, originally created for the
 
 
implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated.  The ability to reasonably estimate conditional asset retirement obligations was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of TEP’s conditional asset retirement obligations.  In determining whether its conditional asset retirement obligations could be reasonably estimated, management considered TEP’s past practices, industry practices, management’s intent and the estimated economic life of the assets.  The fair value of the conditional asset retirement obligations were then estimated using an expected present value technique.  Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have a material effect on the liability recorded by TEP at December 31, 2007 as well as the associated cumulative effect of the change in accounting principle recorded.  The liabilities associated with conditional asset retirement obligations will be adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimates of undiscounted cash flows.  These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Income.  For more information regarding the implementation, see Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies.

Prior to implementing FAS 143, costs for final removal of all owned generation facilities were accrued as an additional component of depreciation expense.  Under FAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost.  As of December 31, 2007, TEP had a liability of $5 million associated with its final asset retirement obligations.

TEP has identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations.  The land on which these stations reside is leased from the Navajo Nation.  The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases.  TEP also has certain environmental obligations at the San Juan Generating Station.  TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities and settle the San Juan environmental obligations will be approximately $40 million at the date of retirement.  No other legal obligations to retire generation plant assets were identified.

In 2004, TEP, Phelps Dodge Energy Services, LLC and PNM Resources, Inc. each purchased from Duke Energy North America, LLC a one-third interest in a limited liability company which owns the natural gas-fired Luna Energy Facility (Luna) in Southern New Mexico.  Luna is a 570-MW combined cycle plant and was placed into commercial operation in April 2006.  See Item 1. – Business, Future Generating Resources – TEP.  The new owners assumed asset retirement obligations to remove certain piping and evaporation ponds and to restore the ground to its original condition.  TEP has estimated its share to settle the obligations will be approximately $2 million at the date of retirement.

TEP has various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses.  TEP operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation.  As a result, TEP is not recognizing the costs of final removal of the transmission and distribution lines in the financial statements.  As of December 31, 2007, TEP had accrued $87 million for the net cost of removal for the interim retirements from its transmission, distribution and general plant.  As of December 31, 2006, TEP had accrued $80 million for these removal costs.  The amount is recorded as a regulatory liability.

Amounts recorded under FAS 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and the credit-adjusted risk-free interest rates to be used to discount future liabilities.  Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations.

If TEP retires any asset at the end of its useful life, without a legal obligation to do so, it will record retirement costs at that time as incurred or accrued.  TEP does not believe that the implementation of FAS 143 will result in any change in retail rates since all matters relating to the rate-making treatment of TEP’s generating assets have been determined pursuant to the Settlement Agreement.
 

UNS Gas and UNS Electric

UNS Gas and UNS Electric have various transmission and distribution lines that operate under land leases and rights-of-way that contain end dates and restorative clauses.  UNS Gas and UNS Electric operate their transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation.  As a result, UNS Gas and UNS Electric are not recognizing the cost of final removal of the transmission and distribution lines in the financial statements.

For the net cost of removal for interim retirements from transmission, distribution and general plant, UNS Gas accrued $17 million as of December 31, 2007 and $4 million as of December 31, 2006.  UNS Electric accrued $2 million as of December 31, 2007 and $2 million as of December 31, 2006.  The amounts are recorded as regulatory liabilities.

Pension and Other Postretirement Benefit Plan Assumptions

We record plan assets, obligations, and expenses related to pension and other postretirement benefit plans based on actuarial valuations, which include key assumptions on discount rates, expected returns on plan assets, compensation increases and health care cost trend rates.  These actuarial assumptions are reviewed annually and modified as appropriate.  The effect of modifications is generally recorded or amortized over future periods.  We believe that the assumptions used in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries.

TEP

As a result of adopting FAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, in December 2006, TEP was required to recognize the underfunded status of its defined benefit pension and other postretirement plans as a liability.  The underfunded status is measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated postretirement benefit obligation for other postretirement benefit plans.  We expect volatility in the liability recognized in the balance sheet in future years as the funded status of our plans can change significantly due to discount rate changes and investment and actuarial experience.  The adjustment required to recognize the pension liability on adoption of this statement resulted in (i) recognition of a regulatory asset of $32 million representing a reasonable appropriation of the actuarial losses and prior service costs of TEP’s pension plans that are probable of recovery in rates by its regulated operations in future periods and (ii) an adjustment to accumulated other comprehensive loss of $17 million for TEP’s unregulated operations.  We recorded the required increase in our other postretirement benefit obligation as an adjustment to accumulated other comprehensive loss of $8 million as the ACC allows TEP, UNS Gas and UNS Electric to recover other postretirement costs through rates only as benefit payments are made.  Changes in the funded status of our plans due to discount rate changes and investment and actuarial experience were recognized as adjustments to regulatory assets and other comprehensive income.  As of December 31, 2007, $10 million and $15 million are included in accumulated other comprehensive income and regulatory assets, respectively, for underfunded pension liabilities.  The amount remaining in accumulated other comprehensive income for our other postretirement benefit plan is $6 million at December 31, 2007.

FAS 158 further requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet effective for years ended December 31, 2008.  On January 1, 2008, TEP recorded a reduction to retained earnings of less than $1 million to move the measurement date from December 1 to December 31 for all of its pension and other postretirement plans.

TEP discounted its future pension plan obligations at between 6.6% and 6.7% at December 31, 2007 and 5.9% at December 31, 2006.  TEP discounted its other postretirement plan obligations at a rate of 6.5% at December 31, 2007, and 5.6% at December 31, 2006.  TEP determines the discount rate annually based on the rates currently available on high-quality, non-callable, long-term bonds.  TEP looks to bonds that receive one of the two highest ratings given by a recognized rating agency whose future cash flows match the timing and amount of expected future benefit payments.  For TEP’s pension plans, a 25-basis point decrease in the discount rate would increase the projected benefit obligation (PBO) by approximately $7 million and the 2008 plan expense by less than $0.5 million.  A similar increase in the discount rate would decrease the PBO by approximately $7 million and the 2008 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 $4 million.  A 25-basis point change in the discount rate would impact plan expense by less than $0.5 million.
 

TEP calculates the market-related value of plan assets using the fair value of plan assets on the measurement date.  TEP assumed that its plans’ assets would generate a long-term rate of return of 8.3% at December 31, 2007 and 8.3% at December 31, 2006.  In establishing its assumption as to the expected return on plan assets, TEP reviews the plans’ asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the plans’ actuary that includes both historical performance analysis and forward looking views of the financial markets.  Pension expense decreases as the expected rate of return on plan assets increases.  A 25-basis point change in the expected return on plan assets would impact pension expense in 2008 by less than $1 million.

TEP used an initial health care cost trend rate of 8% in valuing its postretirement benefit obligation at December 31, 2007.  This rate reflects both market conditions and the plan’s experience.  Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans.  A 1% increase in assumed health care cost trend rates would increase the postretirement benefit obligation by approximately $4 million and the related plan expense in 2008 by less than $1 million.  A similar decrease in assumed health care cost trend rates would decrease the postretirement benefit obligation by approximately $4 million and the related plan expense in 2008 by less than $1 million.

TEP will record pension expense of approximately $6 million and other postretirement benefit expense of $5 million ratably through 2008.  TEP will make required pension plan contributions of $9 million in 2008.  TEP’s other postretirement benefit plan is not funded.  TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $4 million in 2008.

UNS Gas and UNS Electric

UNS Gas and UNS Electric discounted their future pension plan obligations using a rate of 6.8% at December 31, 2007 and 5.9% at December 31, 2006.  For UNS Gas and UNS Electric’s pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and 2008 pension expense by less than $0.5 million.  UNS Gas and UNS Electric will record pension expense of $1 million in 2008.  UNS Gas and UNS Electric will make a pension plan contribution of $1 million in 2008.

UNS Gas and UNS Electric discounted its other postretirement plan obligations using a rate of 6.5% at December 31, 2007, compared with 5.6% at December 31, 2006.  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 $0.5 million in 2008.

Accounting for Derivative Instruments, Trading Activities and Hedging Activities

A derivative financial instrument or other contract derives its value from another investment or designated benchmark. TEP enters into forward contracts to purchase or sell a specified amount of capacity or energy at a specified price over a given period of time, typically for one month, three months, or one year, within established limits to take advantage of favorable market opportunities.  In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods).  TEP enters into forward sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost.  A portion of TEP’s forward contracts are considered to be normal purchases and sales and, therefore, are not required to be marked-to-market.  However, some of these forward contracts are considered to be derivatives, which TEP marks-to-market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month.  However, some of these forward contracts which are derivatives satisfy the requirements for cash flow hedge accounting and the unrealized gains and losses are recorded in Other Comprehensive Income, a component of Common Stock Equity, rather than being reflected in the income statement.  Derivative financial instruments can be accounted for under multiple methods depending upon facts and circumstances, which can lead to variability in earnings.

TEP has agreements to purchase power that are priced using spot market gas prices.  These contracts meet the definition of normal purchases and are not required to be marked-to-market.  In an effort to minimize price risk on these purchases, TEP enters into commodity price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.  The spot market price in the swap agreements is tied to the same index as the purchases under the natural gas supply and purchased power contracts.  These swap agreements, which expire during the summer months through 2009, were entered into with the goal of locking in
 
 
fixed prices on at least 45% and not more than 80% of TEP’s expected summer monthly gas risk prior to entering into the month.  The swap agreements are marked-to-market on a monthly basis; however, since the agreements satisfy the requirements for cash flow hedge accounting, the unrealized gains and losses are recorded in Other Comprehensive Income rather than being reflected in the income statement.

In June 2006, TEP entered into an interest rate swap in order to reduce the risk associated with unfavorable changes in variable interest rate payments related to changes in LIBOR.  The swap has the effect of converting approximately $36 million of variable rate lease payments for the Springerville Common Lease to a fixed rate.  The swap is designated as a cash flow hedge.  The fair value of the interest rate swap is derived from models based on well recognized financial principles, which provide a reasonable approximation of the fair value of the swap as of the valuation date.  Other models can be used to estimate the fair value of the swap and these models, which may use different assumptions or methods, may yield different results.  At December 31, 2007, the fair value of the swap is a liability of $3 million.

TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.

UNS Gas has a natural gas supply and management agreement under which it purchases substantially all of its gas requirements at market prices from BP Energy Company (BP).  However, the contract terms allow UNS Gas to lock in fixed prices on a portion of its gas purchases by entering into fixed price forward contracts with BP at various times during the year.  This enables UNS Gas to provide more stable prices to its customers.  These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% and not more than 80% of the expected monthly gas consumption prior to entering into the month.   These forward contracts, as well as the main gas supply contract, meet the definition of normal purchases and therefore are not required to be marked-to-market.  In February 2008, UNS Gas gave BP notice of its intension to terminate this agreement.  Beginning in September 2008, UNS Gas will directly manage its gas supply and transportation contracts.

In December 2007, UNS Gas entered into a financial gas swap to further assist in achieving price stabilization.  This contract expires in January 2011.  Since this agreement satisfies the requirements for cash flow hedge accounting, any unrealized gains and losses are recorded in Other Comprehensive Income rather than being reflected in the income statement.

UNS Electric presently has a full requirements power supply agreement that enables it to meet its load.  The agreement expires May 31, 2008 and UNS Electric is in the process of replacing this energy resource.  In order to reduce exposure to energy price risk resulting from the procurement of power, UNS Electric has entered into forward power purchase contracts for specified amounts of energy at specified prices over a given period of time, within established limits.  UNS Electric’s forward power purchase contracts meet the definition of a derivative and are marked-to-market by recording unrealized gains or losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month.  In December 2006, the ACC issued an order allowing UNS Electric to record the unrealized net gains or losses as a regulatory asset or regulatory liability.

MEG, a wholly-owned subsidiary of Millennium, entered into swap agreements, options and forward contracts relating to Emission Allowances.  MEG marked its trading contracts to market by recording unrealized gains and losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month.  MEG closed out of all of its transactions in December 2007 and no future transactions are planned.

The market prices used to determine fair values for TEP, UNS Electric and UNS Gas’ derivative instruments at December 31, 2007, are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value.  For TEP’s forward power sales contracts, a 10% decrease in market prices would result in a decrease in unrealized net losses of $1 million, while a 10% increase in market prices would result in an increase in unrealized net losses of $1 million.  For TEP’s forward power purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains of $3 million, while a 10% increase in market prices would result in an increase in unrealized net gains of $3 million.  For TEP’s forward power sales contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $1 million increase in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $1 million decrease in unrealized gains reported in Other Comprehensive Income.  For TEP’s gas swap agreements, a 10% decrease in market prices would result in a $4 million increase in unrealized net losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $4 million
 
 
decrease in unrealized net losses reported in Other Comprehensive Income.  For UNS Electric’s forward power purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $18 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $18 million.  For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net losses reported as a regulatory liability of $2 million, while a 10% increase in market prices would result in an increase in unrealized net losses reported as a regulatory liability of $2 million.  For UNS Gas’ forward gas purchase contracts a 10% decrease in market prices would result in a $1 million decrease in unrealized net gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $1 million increase in unrealized net gains reported in Other Comprehensive Income.

Because of the complexity of derivatives, the FASB established a Derivatives Implementation Group (DIG).  To date, the DIG has issued more than 100 interpretations to provide guidance in applying Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133).  As the DIG or the FASB continues to issue interpretations, TEP, UNS Gas and UNS Electric may change the conclusions they have reached and, as a result, the accounting treatment and financial statement impact could change in the future.

See Market Risks – Commodity Price Risk in Item 7A.

Unbilled Revenue – TEP, UNS Gas and UNS Electric

TEP’s, UNS Gas’s and UNS Electric’s retail revenues include an estimate of MWhs/therms delivered but unbilled 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 MWhs/therms delivered to the MWhs/therms billed to TEP, UNS Gas and UNS Electric retail customers.  The excess of estimated MWhs/therms delivered over MWhs/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 bill rates for each customer class.  Due to the seasonal fluctuations of TEP’s actual load, the unbilled revenue amount increases during the spring and summer months and decreases during the fall and winter months.  The unbilled revenue amount for UNS Gas sales increases during the fall and winter months and decreases during the spring and summer months, whereas, the unbilled revenue amount for UNS Electric sales increases during the spring and summer months and decreases during the fall and winter months.

Plant Asset Depreciable Lives – TEP, UNS Gas and UNS Electric

We calculate depreciation expense based on our estimate of the useful lives of our plant assets.  The estimated useful lives, and resulting depreciation rates used to calculate depreciation expense for the transmission and distribution businesses of TEP, UNS Gas and UNS Electric have been approved by the ACC in prior rate decisions.  Depreciation rates for transmission and distribution cannot be changed without ACC approval.

The estimated remaining useful lives of TEP’s generating facilities are based on management’s best estimate of the economic life of the units.  These estimates are based on engineering estimates, economic analysis, and statistical analysis of TEP’s past experience in maintaining the stations.  Our generation assets are currently depreciated over periods ranging from 23 to 70 years from the original in-service dates.

During the second quarter of 2005, a study requested by the participants in the San Juan Generating Station was completed which indicated San Juan’s economic useful life had changed from previous estimates.  As a result of the study and other analysis performed, TEP lengthened the estimated useful life of San Juan from 40 to 60 years beginning April 1, 2005.  TEP’s annual depreciation expense related to San Juan decreased by $6 million as a result.

Deferred Tax Valuation

We record deferred tax liabilities for amounts that will increase income taxes on future tax returns.  We record deferred tax assets for amounts that could be used to reduce income taxes on future tax returns.  We record a valuation allowance, or reserve, for the deferred tax asset amount that we may not be able to use on future tax returns.  We estimate the valuation allowance based on our interpretation of the tax rules, prior tax audits, tax planning strategies, scheduled reversal of deferred tax liabilities, and projected future taxable income.
 

At December 31, 2007 and December 31, 2006; TEP had no valuation allowance.  At December 31, 2005, UniSource Energy had a valuation allowance of $7 million relating to net operating loss (NOL) carryforward amounts.  The $7 million valuation allowance balance at December 31, 2005, relates to losses generated by the Millennium entities.  As a result of the sale of Global Solar, the NOL and related valuation allowance were removed from the UniSource Energy consolidated balance sheet.  See Note 6 of Notes to Consolidated Financial Statements.
 
As of December 31, 2007 and December 31, 2006, UniSource Energy’s deferred income tax assets include $7 million related to unregulated investment losses of Millennium.  These losses have not been reflected on UniSource Energy’s consolidated income tax returns.  If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the foreseeable future, UniSource Energy would be required to write off these deferred tax assets.
 
NEW ACCOUNTING PRONOUNCEMENTS

The FASB recently issued the following Statements of Financial Accounting Standards (FAS), FASB Interpretations (FIN), FASB Staff Positions (FSP), and Emerging Issues Task Force Issues (EITF):
 

 
·
SEC Staff Accounting Bulletin (SAB No. 110), issued December 2007, expresses the views of the SEC regarding the use of a simplified method in developing an estimate of expected term for "plain vanilla" share options in accordance with FAS Statement No. 123 (revised 2004).  The SEC Staff believes that it may be appropriate to use the simplified method in the following circumstances: (1) there is insufficient historical data to use as a basis for measuring expected term, or (2) there have been significant changes to the terms of the Company's share option grants or the types of employees that receive share option grants, or (3) there have been significant structural changes to the company.  The guidance is applicable to share option grants after December 31, 2007, and we are assessing whether it is appropriate for us to use the simplified method for future share option granrts.

 
 
·
FAS 160, Accounting and Reporting of Noncontrolling Interests in Consolidated Financial Statements, issued December 2007, will change the accounting and reporting for minority interests, requiring such amounts to be classified as a component of equity, and will also change the accounting for transactions with minority-interest holders. The standard will be applicable for fiscal years beginning on or after December 15, 2008 and generally on a prospective basis.  Early adoption is prohibited and business combinations with acquisition dates prior to the effective date will not be adjusted upon application.  We do not expect this pronouncement to have a material impact on our financial statements.

 
·
FAS 141(R) Business Combinations - a replacement of FASB Statement No. 141, issued December 2007, requires companies to record acquisitions at fair value.  FAS 141(R) changes the definition of a business and a business combination and is generally expected to increase the number of transactions that will need to be accounted for at fair value.  The standard will be applicable for fiscal years beginning on or after December 15, 2008 and generally on a prospective basis.  Early adoption is prohibited and business combinations with acquisition dates prior to the effective date will not be adjusted upon application.  We do not expect this pronouncement to have a material impact on our financial statements.

 
·
FSP FASB Interpretation (FIN) 39-1, issued April 2007, allows entities that are party to a master netting arrangement to offset the receivable or payable recognized upon payment or receipt of cash collateral against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement.  Upon adoption of FSP FIN 39-1, an entity is required to make an accounting policy decision to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements.  FSP FIN 39-1 became effective effective January 1, 2008.  We will continue to present cash collateral and derivatives assets and liabilities separately in our financial statements.

 
·
FAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, issued February 2007, provides companies with the option at specified election dates, to measure certain financial assets and liabilities and other items at fair value with changes in fair value recognized in earnings as those changes occur.  FAS 159 also establishes disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elects the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each item.  We have not elected fair value accounting for any of our eligible financial instruments.

 
·
FAS 157, Fair Value Measurement, issued September 2006, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  FAS 157 clarifies that the exchange price is the price in the principal market in which the reporting entity would transact for the asset or liability.  The adoption of FAS 157 on January 1, 2008 had no impact on our financial statements. We will begin disclosing inputs to develop fair value measurements and the effect of any of our assumptions on earnings or net assets for the quarter ending March 31, 2008.
 
 
·
The Pension Protection Act of 2006 (Pension Act) became effective January 1, 2008.  The new law affects the manner in which many companies, including UniSource Energy and TEP, administer their pension plans and provides for certain minimum funding requirements.  The Pension Act resulted in no additional funding requirements as for the company.

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, which 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 other parts of this report:

1.
The resolution of pending retail rate case proceedings and the resulting rate structures.

2.
Demand conditions in our retail service areas, including economic conditions, weather conditions, rate structures, demographic patterns, competing energy alternatives and the status of retail competition.

3.
Supply and demand conditions in wholesale energy markets, including volatility in market prices and illiquidity in markets, are affected by a variety of factors, which include the availability of generating capacity in the Western U.S., including hydroelectric resources, weather, natural gas prices, the extent of utility restructuring in various states, transmission constraints, environmental regulations and cost of compliance, FERC regulation of wholesale energy markets, and economic conditions in the Western U.S.

4.
Changes affecting our cost of providing electric and gas service including changes in fuel costs, generating unit operating performance, scheduled and unscheduled plant outages, interest rates, tax laws, environmental laws, and the general rate of inflation.

5.
Ability to obtain financing through debt and/or equity issuance, which can be affected by various factors, including interest rate fluctuations and capital market conditions.

6.
The creditworthiness of the entities with which we transact business or have transacted business.

7.
Changes in accounting principles or the application of such principles to our businesses.

8.
Changes in the depreciable lives of our assets.

9.
Unanticipated changes in future liabilities relating to employee benefit plans due to changes in market values of retirement plan assets and health care costs.

10.
The outcome of any ongoing or future litigation.

 
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 the 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.

Interest Rate Risk

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations.  At December 31, 2007 and 2006, TEP’s debt included $329 million of tax-exempt variable rate debt.  The average interest rate on TEP’s variable rate debt (excluding letter of credit fees) was 3.64 % in 2007 and 3.47% in 2006.  At December 31, 2007 and 2006, TEP’s debt also included variable rate lease debt totaling $67 million, and $68 million respectively, related to its Springerville Common Facilities Leases.  The notes underlying the leases mature in June 2017 and January 2020.  Interest is payable at LIBOR plus 1.5% through June 2009.  The spread over LIBOR increases by 0.125% in June 2009, and every three years thereafter to 2% by June 2018.   The interest rate in effect on the lease debt was 6.69% at December 31, 2007, and 7.13% at December 31, 2006.  A 1% increase (decrease) in average interest rates would result in a decrease (increase) in TEP’s pre-tax income by approximately $4 million.

A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the floating rate lease debt.  In June 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt.  This swap has the effect of fixing the interest rate portion of rent at 7.27% on a portion of the principal balance, which was $36 million at December 31, 2007.

Marketable Securities Risk

TEP is exposed to fluctuations in the return on its marketable securities, which is comprised of investments in debt securities.  At December 31, 2007 and 2006, TEP had marketable debt securities with an estimated fair value of $109 million and $139 million, respectively.  At December 31, 2007 and 2006, the fair value exceeded the carrying value by $4 million and $6 million, respectively.  These debt securities represent TEP’s investments in lease debt underlying certain of TEP’s capital lease obligations.  Changes in the fair value of such debt securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity.

Commodity Price Risk

We are exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances.

TEP

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 under FAS 133.  TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered.  From time to time, however, TEP enters into forward contracts that meet the definition of a derivative under FAS 133.  When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other Southwestern U.S. trading hubs.  TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market.

To adjust the value of its derivative forward power sales and purchases, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:

 
2007
2006
2005
 
- In Millions-
Unrealized Gain (Loss)
$  -
$ 8
$  (1)

TEP also reported the following net unrealized gains and losses on forward power sales and purchases in Wholesale Sales.

 
2007
2006
2005
 
- In Millions-
Unrealized Gain (Loss)
$  -
$  1
$  (1)

Natural Gas

TEP is also subject to commodity price risk from changes in the price of natural gas.  In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units.  Some of these purchased power contracts are price indexed to natural gas prices.  Short-term and spot power purchase prices are also closely correlated to natural gas prices.  Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed purchase power and spot market purchases with fixed price contracts for a maximum of three years.  TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.

In 2007, the average market price of natural gas was $6.11 per MMBtu, or 1% higher than 2006.  The table below summarizes TEP’s gas generation output and purchased power for 2007, 2006 and 2005.

 
2007
2006
2005
2007
2006
2005
 
-Millions of MWhs-
% of Total Resources
Gas-Fired Generation
1,088
   850
  368
  8%
   6%
  3%
Purchased Power
2,047
1,680
1,639
 15%
  12%
13%
 
 
To adjust the value of its derivative gas swap contracts, classified as cash flow hedges, to fair value in Other Comprehensive Income, TEP recorded the following net unrealized gains and losses:

 
2007
2006
2005
 
- In Millions-
Unrealized Gain (Loss)
$  (6)
$  (18)
$  18

The chart below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts.

 
Unrealized Gain (Loss) of TEP’s
Hedging and Trading Activities
 
- Millions of Dollars -
Source of Fair Value At Dec. 31, 2007
Maturity 0 – 6
months
Maturity 6 – 12
months
Maturity
over 1 yr.
Total
Unrealized
Gain (Loss)
Prices actively quoted
$       -
$        -
$       -
$         -
Prices based on models and other valuation methods
         -
      (1)
        -
       (1)
Total
$       -
$     (1)
$       -
$      (1)

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of an unfavorable change in market prices on the fair value of its derivative forward contracts.  Unrealized gains and losses related to TEP’s derivative contracts that are not cash flow hedges are reported on the income statement.  Unrealized gains and losses related to derivative contracts that are cash flow hedges are reported in Other Comprehensive Income; the unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded. The chart below summarizes the change in unrealized gains or losses if market prices increase or decrease by 10%.

 
- Millions of Dollars -
Change in Market Price As of December 31, 2007
10% Increase
10% Decrease
Non-Cash Flow Hedges
    
    Forward power sales and purchase contracts
 $    1
$   (1)
    Gas swap agreements
       -
     -
 
 
 
Cash Flow Hedges
 
 
   Forward power sales and purchase contracts
 $   (1)
$    1
   Gas swap agreements
      4
     (4)

Coal

TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants.

In 2003, TEP amended and extended the long-term coal supply contract for Springerville Units 1 and 2 through 2020 and expects coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives.  During the extension period from 2011 through 2020, the coal price will be determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling.  Based on current coal market conditions, this range would be from $24 to $30 per ton.  TEP estimates its future minimum annual payments under this contract to be $45 million through 2010, the initial contract expiration date, and $14 million from 2011 through 2020.  TEP’s coal transportation contract at Springerville runs through June of 2011.  TEP estimates minimum annual payments under this contract to be $13 million through 2010 and $7 million in 2011.

In December 2006, TEP entered into agreements for the purchase and transportation of coal to Sundt Unit 4 through December 2008.  The total amount paid under these agreements depends on the number of tons of coal purchased and transported.   In 2007, TEP’s total coal-related fuel expense across all of its plants increased by $12 million, or 6% compared with 2006.
 

The long-term rail contract for Sundt Unit 4 is in effect until the earliest of 2015, the remaining life of Sundt Unit 4 or the life of the coal mine.  This rail contract requires TEP to transport at least 75,000 tons of coal per year through 2015 at an estimated annual cost of $2 million or to make a minimum payment of $1 million.

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo and San Juan, where coal supplies are under long-term contracts administered by the operating agents.  In 2003, the Four Corners coal contract was extended through July 2016.  This contract requires TEP to purchase minimum amounts of coal at an estimated annual cost of $6 million.  TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations.

The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an estimated average annual cost of $21 million for the next five years.  See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UniSource Energy Consolidated, Contractual Obligations and Note 5 of Notes to Consolidated Financial Statements – Commitments and Contingencies, TEP Commitments, Purchase and Transportation Commitments.

UNS Gas

UNS Gas is subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its customers.  This risk is mitigated through the PGA mechanism which provides an adjustment to UNS Gas’ retail rates to recover the actual costs of gas and transportation.  UNS Gas further reduces this risk by purchasing forward fixed price contracts 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.

For UNS Gas’ forward gas purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $1 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $1 million.

UNS Electric

UNS Electric is not exposed to commodity price risk for its current purchases of electricity as it has a fixed price full-requirements supply agreement with PWMT and a PPFAC mechanism which fully recovers the costs incurred under such contract on a timely basis.  This supply agreement with PWMT expires in May 2008 and UNS Electric is in the process of replacing this energy resource.

During 2006 and 2007, UNS Electric entered into various power supply agreements for periods of one to five years beginning in June 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric estimates its future minimum payments under these contracts to be $58 million in 2008, $67 million in 2009, $39 million in 2010, $15 million in 2011, $8 million in 2012, and $8 million thereafter based on natural gas prices at the date of the contracts.

Because a portion of the costs under these contracts will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under these new contracts on a timely basis.

For UNS Electric’s forward power purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $18 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $18 million.

In 2007, UNS Electric began hedging a portion of its natural gas exposure from gas-indexed purchase power agreements that begin in June 2008 with fixed price contracts.  In addition, UNS Electric began hedging a portion of its anticipated natural gas exposure from plant fuel for the period June 2008 and beyond.  UNS Electric currently has approximately 32% of this aggregate summer exposure hedged for the summer of 2008.  UNS Electric will obtain its remaining gas and purchased power needs through a combination of additional forward purchases and purchases in the short-term and spot markets.

For UNS Electric’s forward gas purchase contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability of $2 million, while a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability of $2 million.
 

MEG

MEG was in the business of trading Emission Allowances and related instruments until December 2007 when it settled its remaining positions. No further activities are anticipated.

MEG marked its trading positions to market on a daily basis using actively quoted prices obtained from brokers and options pricing models.  As of December 31, 2007, MEG had no trading assets or liabilities on its balance sheet.  At December 31, 2006, the fair value of MEG’s trading assets combined with Emission Allowances it held in escrow was $11 million.  The fair value of MEG’s trading liabilities was $5 million at December 31, 2006.  For 2007, MEG reflected a $3 million unrealized loss and a $2 million realized gain on its income statement, compared with an unrealized gain of $10 million and a realized loss of $10 million in 2006.

Credit Risk

UniSource Energy is exposed to credit risk in its energy-related marketing and trading activities related to potential nonperformance by counterparties.  We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using 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 other credit enhancements.

As of December 31, 2007, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $20 million.  Approximately $3 million of TEP’s exposure is to non-investment grade companies.  TEP had one counterparty with an exposure of greater than 10% of its total credit exposure, totaling approximately $3 million.

TEP maintains a margin account with a broker to support certain risk management and trading activities.  At December 31, 2007, TEP had approximately $1 million in that margin account.  At December 31, 2007, TEP had no other credit enhancements posted with counterparties, nor did TEP 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, 2007, UNS Gas had purchased under fixed price contracts approximately 31% of the expected monthly consumption for the 2008/2009 winter season (November through March) and approximately 19% of its expected consumption for the 2009/2010 winter season.  At December 31, 2007, UNS Gas had less than $1 million in mark-to-market credit exposure under its supply and hedging contracts.  As of December 31, 2007, UNS Gas had provided $10 million in letters of credit as credit enhancements.

UNS Electric has begun to enter into energy purchase agreements to replace the full requirements contract it has with PWMT that expires in May 2008, 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 would be exposed to credit risk under those contracts.  At December 31, 2007, UNS Electric had approximately $7 million in credit exposure under such contracts.  All of UNS Electric’s credit exposure is to investment grade counterparties and is concentrated with four of its counterparties.  As of December 31, 2007, UNS Electric had not posted any credit enhancement 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 Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 

Management assessed the effectiveness of the UniSource Energy Corporation’s internal control over financial reporting as of December 31, 2007.  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, 2007, UniSource Energy Corporation’s internal control over financial reporting was effective.

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, 2007.  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, 2007, Tucson Electric Power Company’s internal control over financial reporting was effective.

This annual report does not include an attestation report of Tucson Electric Power Company’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by Tucson Electric Power Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit Tucson Electric Power Company to provide only management’s report in this annual report.


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, 2007 and December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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.

As described in Note 10 to the consolidated financial statements, the company changed the manner in which it accounts for income taxes as a result of implementing FIN 48, Accounting for Uncertainty in Income Taxes— an interpretation of FASB Statement No. 109 as of January 1, 2007.

As described in Note 11 to the consolidated financial statements, the company changed the manner in which it accounts for pension and post-retirement obligations as a result of implementing Financial Accounting Standards Board Standard No. 158 as of December 31, 2006.

As described in Note 1 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No.47 as of December 31, 2005.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/ Pricewaterhouse Coopers LLP
Chicago, Illinois
February 26, 2008

 
Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of
Tucson Electric Power Company:

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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.
 

As described in Note 10 to the consolidated financial statements, the company changed the manner in which it accounts for income taxes as a result of implementing FIN 48, Accounting for Uncertainty in Income Taxes— an interpretation of FASB Statement No. 109 as of January 1, 2007.

As described in Note 11 to the consolidated financial statements, the company changed the manner in which it accounts for pension and post-retirement obligations as a result of implementing Financial Accounting Standards Board Standard No. 158 as of December 31, 2006.

As described in Note 1 to the consolidated financial statements, the company changed the manner in which it accounts for asset retirement costs as a result of implementing Financial Accounting Standards Board Interpretation No. 47 as of December 31, 2005.
 
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 26, 2008

 
UNISOURCE ENERGY CORPORATION
                  
CONSOLIDATED STATEMENTS OF INCOME
                  
   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
- Thousands of Dollars -
  
   
  (Except Per Share Amounts)
  
Operating Revenues
                  
  Electric Retail Sales
   $ 976,795     $ 932,307     $ 895,411  
  Electric Wholesale Sales
     196,233       179,266       178,667  
  Gas Revenue
     148,597       159,598       135,909  
  Other Revenues
     59,748       36,970       14,069  
    Total Operating Revenues
     1,381,373       1,308,141       1,224,056  
                         
Operating Expenses
                        
  Fuel
     291,238       257,515       226,278  
  Purchased Energy
     352,898       320,788       324,351  
  Other Operations and Maintenance
     258,176       247,069       215,600  
  Depreciation and Amortization
     140,638       130,502       132,577  
  Amortization of Transition Recovery Asset
     77,681       65,985       56,418  
  Taxes Other Than Income Taxes
     47,837       46,136       47,328  
    Total Operating Expenses
     1,168,468       1,067,995       1,002,552  
      Operating Income
     212,905       240,146       221,504  
                         
Other Income (Deductions)
                        
  Interest Income
     18,828       19,210       19,838  
  Other Income
     7,622       7,453       10,985  
  Other Expense
     (4,380 )     (1,887 )     (2,155 )
    Total Other Income (Deductions)
     22,070       24,776       28,668  
                         
Interest Expense
                        
  Long-Term Debt
     73,095       75,039       76,762  
  Interest on Capital Leases
     64,499       72,586       79,098  
  Loss on Extinguishment of Debt
     -       1,080       5,261  
  Other Interest Expense
     5,480       7,922       3,153  
  Interest Capitalized
     (5,551 )     (4,884 )     (3,978 )
    Total Interest Expense
     137,523       151,743       160,296  
                         
Income Before Income Taxes, Discontinued Operations, and Cumulative
Effect of Accounting Change
     97,452       113,179       89,876  
  Income Tax Expense
     39,079       43,936       37,623  
                         
Income Before Discontinued Operations and Cumulative Effect of Accounting Change
     58,373       69,243       52,253  
                         
Discontinued Operations - Net of Tax
     -       (1,796 )     (5,483 )
Cumulative Effect of Accounting Change - Net of Tax
     -       -       (626 )
                         
Net Income
   $ 58,373     $ 67,447     $ 46,144  
                         
Weighted-average Shares of Common Stock Outstanding (000)
     35,486       35,264       34,798  
                         
Basic Earnings per Share
                        
  Income Before Discontinued Operations and Cumulative Effect of Accounting Change
   $ 1.64     $ 1.96     $ 1.51  
  Discontinued Operations - Net of Tax
     -     $ (0.05 )   $ (0.16 )
  Cumulative Effect of Accounting Change - Net of Tax
     -       -     $ (0.02 )
  Net Income
   $ 1.64     $ 1.91     $ 1.33  
                         
Diluted Earnings per Share
                        
  Income Before Discontinued Operations and Cumulative Effect of Accounting Change
   $ 1.57     $ 1.85     $ 1.44  
  Discontinued Operations - Net of Tax
     -     $ (0.05 )   $ (0.14 )
  Cumulative Effect of Accounting Change - Net of Tax
     -       -     $ (0.02 )
  Net Income
   $ 1.57     $ 1.80     $ 1.28  
                         
Dividends Declared per Share
   $ 0.90     $ 0.84     $ 0.76  
                         
See Notes to Consolidated Financial Statements.
                        
 
 
UNISOURCE ENERGY CORPORATION
                  
CONSOLIDATED STATEMENTS OF CASH FLOWS
                  
   
  Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
  - Thousands of Dollars -
  
                   
Cash Flows from Operating Activities
                  
  Cash Receipts from Electric Retail Sales
   $ 1,061,994     $ 1,008,071     $ 975,378  
  Cash Receipts from Electric Wholesale Sales
     301,616       254,322       227,095  
  Cash Receipts from Gas Sales
     165,678       173,243       145,281  
  Cash Receipts from Operating Springerville Unit 3
     38,887       16,659       -  
  Sale of Excess Emission Allowances
     14,861       7,254       15,354  
  Other Cash Receipts
     11,774       8,823       9,107  
  MEG Cash Receipts from Trading Activity
     2,829       2,704       72,441  
  Interest Received
     19,197       22,231       23,194  
  Performance Deposits Received
     12,549       15,307       41,157  
  Income Tax Refunds Received
     1,016       553       1,484  
  Purchased Energy Costs Paid
     (450,197 )     (383,943 )     (369,218 )
  Fuel Costs Paid
     (283,439 )     (244,690 )     (223,672 )
  Payment of Other Operations and Maintenance Costs
     (158,057 )     (137,941 )     (130,108 )
  Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized
     (151,074 )     (144,526 )     (140,013 )
  Wages Paid, Net of Amounts Capitalized
     (106,097 )     (100,368 )     (93,220 )
  Interest Paid, Net of Amounts Capitalized
     (68,446 )     (67,006 )     (72,481 )
  Capital Lease Interest Paid
     (54,315 )     (63,644 )     (67,707 )
  Income Taxes Paid
     (20,923 )     (66,070 )     (10,147 )
  Performance Deposits Payments
     (7,900 )     (9,617 )     (36,455 )
  Excess Tax Benefit from Stock Option Exercises
     (541 )     (1,501 )     (2,527 )
  MEG Cash Payments for Trading Activity
     (1,704 )     (812 )     (79,990 )
  Other Cash Payments
     (4,942 )     (3,680 )     (4,919 )
  Net Cash Used by Operating Activities of Discontinued Operations
     -       (2,710 )     (6,151 )
    Net Cash Flows - Operating Activities
     322,766       282,659       273,883  
                         
Cash Flows from Investing Activities
                        
  Capital Expenditures
     (245,366 )     (238,261 )     (203,362 )
  Proceeds from Investment in Lease Debt and Equity
     27,732       22,158       13,646  
  Other Proceeds from Investing Activities
     4,475       3,263       8,848  
  Return of Investment from Millennium
     12       4,835       15,236  
  Investments in and Loans to Equity Investees
     (845 )     (4,518 )     (4,870 )
  Other Payments for Investing Activities
     (3,413 )     (1,487 )     -  
  Sale of Subsidiary
     -       16,000       -  
  Payments for Investment in Lease Debt and Equity
     -       (48,025 )     -  
  Net Cash Used by Investing Activities of Discontinued Operations
     -       (46 )     (66 )
    Net Cash Flows - Investing Activities
     (217,405 )     (246,081 )     (170,568 )
                         
Cash Flows from Financing Activities
                        
  Proceeds from Borrowings Under Revolving Credit Facilities
     205,000       194,000       45,000  
  Repayments of Borrowings Under Revolving Credit Facilities
     (218,000 )     (126,000 )     (40,000 )
  Proceeds from Issuance of Long-Term Debt
     -       30,000       240,000  
  Repayment of Long-Term Debt
     (6,000 )     (93,250 )     (285,516 )
  Payments of Capital Lease Obligations
     (71,549 )     (61,197 )     (52,907 )
  Common Stock Dividends Paid
     (31,784 )     (29,499 )     (26,339 )
  Payment of Debt Issue Costs
     (465 )     (2,092 )     (12,431 )
  Proceeds from Stock Options Exercised
     1,980       4,861       10,691  
  Excess Tax Benefit from Stock Option Exercises
     541       1,501       2,527  
  Other Proceeds from Financing Activities
     8,210       11,509       11,906  
  Other Payments for Financing Activities
     (7,162 )     (6,849 )     (5,595 )
    Net Cash Flows - Financing Activities
     (119,229 )     (77,016 )     (112,664 )
                         
Net (Decrease) in Cash and Cash Equivalents
     (13,868 )     (40,438 )     (9,349 )
Cash and Cash Equivalents, Beginning of Year
     104,241       144,679       154,028  
Cash and Cash Equivalents, End of Year
   $ 90,373     $ 104,241     $ 144,679  
                         
See Note 16 for supplemental cash flow information.
                        
                         
See Notes to Consolidated Financial Statements.
                        
 
 
UNISOURCE ENERGY CORPORATION
            
CONSOLIDATED BALANCE SHEETS
            
             
   
December 31,
  
   
2007
    
2006
  
ASSETS
  
- Thousands of Dollars -
Utility Plant
            
  Plant in Service
   $ 3,565,735     $ 3,410,638  
  Utility Plant under Capital Leases
     702,337       702,337  
  Construction Work in Progress
     195,105       135,431  
    Total Utility Plant
     4,463,177       4,248,406  
  Less Accumulated Depreciation and Amortization
     (1,534,424 )     (1,492,842 )
  Less Accumulated Amortization of Capital Lease Assets
     (521,458 )     (495,944 )
    Total Utility Plant - Net
     2,407,295       2,259,620  
                 
Investments and Other Property
                
  Investments in Lease Debt and Equity
     152,544       181,222  
  Other
     70,677       66,194  
    Total Investments and Other Property
     223,221       247,416  
                 
Current Assets
                
  Cash and Cash Equivalents
     90,373       104,241  
  Trade Accounts Receivable
     114,201       124,789  
  Unbilled Accounts Receivable
     62,101       58,499  
  Allowance for Doubtful Accounts
     (18,446 )     (16,859 )
  Materials and Fuel Inventory
     82,433       73,628  
  Trading Assets
     5,489       26,387  
  Current Regulatory Assets
     10,262       9,549  
  Deferred Income Taxes - Current
     60,055       57,912  
  Interest Receivable - Current
     9,450       7,782  
  Other
     14,322       9,982  
    Total Current Assets
     430,240       455,910  
                 
Regulatory and Other Assets
                
  Transition Recovery Regulatory Asset
     23,944       101,626  
  Income Taxes Recoverable Through Future Revenues - Regulatory Asset
     30,009       34,749  
  Other Regulatory Assets
     37,313       54,848  
  Other Assets
     33,694       33,240  
    Total Regulatory and Other Assets
     124,960       224,463  
                 
Total Assets
   $ 3,185,716     $ 3,187,409  
                 
See Notes to Consolidated Financial Statements.
                
                 
(Consolidated Balance Sheets Continued)
  
 
 
UNISOURCE ENERGY CORPORATION
            
CONSOLIDATED BALANCE SHEETS
            
             
   
December 31,
  
   
2007
    
2006
  
CAPITALIZATION AND OTHER LIABILITIES
  
- Thousands of Dollars -
  
Capitalization
            
  Common Stock Equity
   $ 690,075     $ 654,149  
  Capital Lease Obligations, net of Current Obligations
     530,973       588,771  
  Long-Term Debt, net of Current Maturities
     993,870       1,171,170  
    Total Capitalization
     2,214,918       2,414,090  
                 
Current Liabilities
                
  Current Obligations under Capital Leases
     58,599       59,090  
  Borrowing under Revolving Credit Facilities
     10,000       50,000  
  Current Maturities of Long-Term Debt
     204,300       6,000  
  Accounts Payable
     122,687       102,829  
  Income Taxes Payable
     156       16,429  
  Interest Accrued
     48,091       52,392  
  Trading Liabilities - Derivative Instruments
     3,193       16,537  
  Accrued Taxes Other than Income Taxes
     36,775       35,431  
  Accrued Employee Expenses
     24,585       22,886  
  Customer Deposits
     21,425       19,767  
  Current Regulatory Liabilities
     16,520       10,707  
  Other
     1,350       3,852  
    Total Current Liabilities
     547,681       395,920  
                 
Deferred Credits and Other Liabilities
                
  Deferred Income Taxes - Noncurrent
     149,730       126,883  
  Regulatory Liability - Net Cost of Removal for Interim Retirements
     106,695       85,394  
  Other Regulatory Liabilities
     15,721       9,609  
  Pension and Other Post-Retirement Benefits
     76,407       105,085  
  Customer Advances for Construction
     28,798       27,396  
  Other
     45,766       23,032  
    Total Deferred Credits and Other Liabilities
     423,117       377,399  
                 
Commitments and Contingencies (Note 6)
                
                 
Total Capitalization and Other Liabilities
   $ 3,185,716     $ 3,187,409  
                 
See Notes to Consolidated Financial Statements.
                
                 
(Consolidated Balance Sheets Concluded)
  
 
 
UNISOURCE ENERGY CORPORATION
                        
CONSOLIDATED STATEMENTS OF CAPITALIZATION
                    
               
December 31,
  
               
2007
    
2006
  
COMMON STOCK EQUITY
              
- Thousands of Dollars -
  
                         
  Common Stock-No Par Value
               $ 702,368     $ 697,426  
   
2007
    
2006
                  
    Shares Authorized
    
75,000,000
      
75,000,000
                  
    Shares Outstanding
    
35,314,730
      
35,189,645
                  
  Accumulated Deficit
                     (628 )     (27,913 )
  Accumulated Other Comprehensive Loss
                     (11,665 )     (15,364 )
           Total Common Stock Equity
                     690,075       654,149  
                                 
PREFERRED STOCK
                                
  No Par Value, 1,000,000 Shares Authorized, None Outstanding
               -       -  
                                 
CAPITAL LEASE OBLIGATIONS
                                
  Springerville Unit 1
                     345,800       381,446  
  Springerville Coal Handling Facilities
                     99,175       112,177  
  Springerville Common Facilities
                     107,630       106,837  
  Sundt Unit 4
                     36,034       46,140  
  Other
                     933       1,261  
        Total Capital Lease Obligations
                     589,572       647,861  
        Less Current Maturities
                     (58,599 )     (59,090 )
          Total Long-Term Capital Lease Obligations
                     530,973       588,771  
                                 
LONG-TERM DEBT
                                
                Issue
  
Maturity
    
Interest Rate
                  
  UniSource Energy:
                                
    Convertible Senior Notes
  
2035
      
4.50%
       150,000       150,000  
    Credit Agreement*
  
2011
    
Variable
       41,000       27,000  
  Tucson Electric Power Company:
                                
    Variable Rate IDBs
  
2011
    
Variable**
       328,600       328,600  
    Collateral Trust Bonds
  
2008
      
7.50%
       138,300       138,300  
    Unsecured IDBs
    
2020 - 2033
    
5.85% to 7.13%
       354,270       354,270  
  UNS Gas and UNS Electric:
                                
    Senior Unsecured Notes
    
2008 - 2015
    
6.23% to 7.61%
       160,000       160,000  
    Credit Agreement
  
2011
    
Variable
       26,000       19,000  
        Total Stated Principal Amount
                     1,198,170       1,177,170  
        Less Current Maturities
                     (204,300 )     (6,000 )
          Total Long-Term Debt
                     993,870       1,171,170  
                                 
Total Capitalization
                   $ 2,214,918     $ 2,414,090  
                                 
 
*At December 31, 2006, UniSource Energy had an additional $20 million outstanding under the Revolving Credit Facility included in Current Liabilities.

** TEP’s Variable Rate industrial development bonds (IDBs) are backed by letters of credit (LOCs) issued pursuant to TEP’s Credit Agreement which expires in August 2011.  Although the Variable Rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.  Weighted average interest rates on this variable rate tax-exempt debt ranged from 3.11% to 3.95% during 2007, 2.95% to 3.96% during 2006 and 1.52% to 3.55% during 2005, and the average interest rate on such debt was 3.64% in 2007, 3.47% in 2006 and 2.48% in 2005.
 
See Notes to Consolidated Financial Statements.
 
 
UNISOURCE ENERGY CORPORATION
                              
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
  
                               
                     
Accumulated
        
   
Common
                
Other
    
Total
  
   
Shares
    
Common
    
Accumulated
    
Comprehensive
    
Stockholders'
  
   
Outstanding*
    
Stock
    
Deficit
    
Loss
    
Equity
  
   
- In Thousands -
  
                               
Balances at December 31, 2004
     34,255     $ 677,119       $    (85,666 )     $       (10,735 )   $ 580,718  
                                         
Comprehensive Income:
                                        
2005 Net Income
     -       -       46,144       -       46,144  
 
                                        
Minimum Pension Liability Adjustment
(net of $1,378 income taxes)
     -       -       -       (2,101 )     (2,101 )
 
                                        
Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)
     -       -       -       9,918       9,918  
 
                                        
Reclassification of Unrealized Gains on Cash Flow Hedges to Net Income
(net of $2,403 income taxes)
     -       -       -       (3,665 )     (3,665 )
                                         
Total Comprehensive Income
                                     50,296  
                                         
Dividends Declared
     -       -       (26,339 )     -       (26,339 )
Shares Issued under Stock Compensation Plans
     36       -       -       -       -  
Shares Distributed by Deferred Compensation Trust
     -       1       -       -       1  
Shares Issued for Stock Options
     583       9,411       -       -       9,411  
Tax Benefit Realized from Stock Options Exercised
     -       2,527       -       -       2,527  
Other
     -       127       -       -       127  
                                         
Balances at December 31, 2005
     34,874       689,185       (65,861 )     (6,583 )     616,741  
                                         
Comprehensive Income:
                                        
2006 Net Income
     -       -       67,447       -       67,447  
 
                                        
Minimum Pension Liability Adjustment
(net of $8,915 income taxes)
     -       -       -       13,597       13,597  
 
                                        
Unrealized Loss on Cash Flow Hedges
(net of $4,897 income taxes)
     -       -       -       (7,469 )     (7,469 )
                                         
Reclassification of Unrealized Gains on Cash Flow Hedges to Net Income
(net of $77 income taxes)
     -       -       -       (117 )     (117 )
                                         
Total Comprehensive Income
                                     73,458  
 
                                        
Adjustment to Initially Recognize the Funded Status of Employee Benefit Plans
(net of $9,698 income taxes)
     -       -       -       (14,792 )     (14,792 )
                                         
Dividends Declared
     -       -       (29,499 )     -       (29,499 )
Shares Issued under Stock Compensation Plans
     11       -       -       -       -  
Shares Issued for Stock Options
     305       4,859       -       -       4,859  
Tax Benefit Realized from Stock Options Exercised
     -       1,501       -       -       1,501  
Other
     -       1,881       -       -       1,881  
                                         
Balances at December 31, 2006
     35,190       697,426       (27,913 )     (15,364 )     654,149  
                                         
Implementation of FIN 48
                     696               696  
                                         
Comprehensive Income:
                                        
2007 Net Income
     -       -       58,373       -       58,373  
                                         
Decrease in Pension and Other Post-Retirement Benefit Liabilities
(net of $3,929 income taxes)
     -       -       -       5,993       5,993  
 
                                        
Unrealized Loss on Cash Flow Hedges
(net of $2,500 income taxes)
     -       -       -       (3,813 )     (3,813 )
                                         
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income
(net of $996 income taxes)
     -       -       -       1,519       1,519  
                                         
Total Comprehensive Income
                                     62,072  
                                         
Dividends Declared
     -       -       (31,784 )     -       (31,784 )
Shares Issued under Stock Compensation Plans
     5       -       -       -       -  
Shares Issued for Stock Options
     120       1,980       -       -       1,980  
Tax Benefit Realized from Stock Options Exercised
     -       540       -       -       540  
Other
     -       2,422       -       -       2,422  
                                         
Balances at December 31, 2007
     35,315     $ 702,368       $         (628 )     $       (11,665 )   $ 690,075  
                                         
* UniSource Energy has 75 million authorized shares of Common Stock.
                  
                                         
We describe limitations on our ability to pay dividends in Note 9.
                          
                                         
See Notes to Consolidated Financial Statements.
                                  
 
 
TUCSON ELECTRIC POWER COMPANY
                  
CONSOLIDATED STATEMENTS OF INCOME
                  
   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
  - Thousands of Dollars -
  
Operating Revenues
                  
  Electric Retail Sales
   $ 811,649     $ 774,470     $ 746,876  
  Electric Wholesale Sales
     195,999       179,022       178,428  
  Other Revenues
     62,855       35,502       12,166  
    Total Operating Revenues
     1,070,503       988,994       937,470  
                         
Operating Expenses
                        
  Fuel
     291,238       257,515       226,278  
  Purchased Power
     140,498       100,090       132,883  
  Other Operations and Maintenance
     211,851       198,573       168,056  
  Depreciation and Amortization
     119,811       112,346       114,704  
  Amortization of Transition Recovery Asset
     77,681       65,985       56,418  
  Taxes Other Than Income Taxes
     40,366       38,834       39,790  
    Total Operating Expenses
     881,445       773,343       738,129  
      Operating Income
     189,058       215,651       199,341  
                         
Other Income (Deductions)
                        
  Interest Income
     16,072       16,429       18,884  
  Interest Income - Note Receivable from UniSource Energy
     -       -       1,684  
  Other Income
     3,665       7,147       4,182  
  Other Expense
     (3,296 )     (3,029 )     (1,685 )
    Total Other Income (Deductions)
     16,441       20,547       23,065  
                         
Interest Expense
                        
  Long-Term Debt
     50,230       51,422       56,243  
  Interest on Capital Leases
     64,477       72,556       79,064  
  Loss on Extinguishment of Debt
     -       685       5,261  
  Other Interest Expense
     4,538       6,436       2,597  
  Interest Capitalized
     (2,744 )     (4,124 )     (3,559 )
    Total Interest Expense
     116,501       126,975       139,606  
                         
Income Before Income Taxes and Cumulative Effect of Accounting Change
     88,998       109,223       82,800  
  Income Tax Expense
     35,542       42,478       33,907  
                         
Income Before Cumulative Effect of Accounting Change
     53,456       66,745       48,893  
Cumulative Effect of Accounting Change - Net of Tax
     -       -       (626 )
                         
Net Income
   $ 53,456     $ 66,745     $ 48,267  
                         
See Notes to Consolidated Financial Statements.
                        
 
 
TUCSON ELECTRIC POWER COMPANY
                  
CONSOLIDATED STATEMENTS OF CASH FLOWS
                  
   
  Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
  - Thousands of Dollars -
  
                   
Cash Flows from Operating Activities
                  
  Cash Receipts from Electric Retail Sales
   $ 883,885     $ 840,601     $ 815,624  
  Cash Receipts from Electric Wholesale Sales
     301,616       254,322       227,031  
  Cash Receipts from Operating Springerville Unit 3
     38,887       16,659       -  
  Interest Received
     16,284       18,808       21,073  
  Sale of Excess Emission Allowances
     16,975       7,254       15,354  
  Other Cash Receipts
     7,931       6,579       3,696  
  Interest Received from UniSource Energy
     -       -       11,013  
  Income Tax Refunds Received
     -       -       713  
  Fuel Costs Paid
     (283,440 )     (244,632 )     (223,672 )
  Purchased Power Costs Paid
     (245,439 )     (182,626 )     (179,682 )
  Payment of Other Operations and Maintenance Costs
     (144,753 )     (121,744 )     (111,112 )
  Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized
     (116,641 )     (109,952 )     (105,741 )
  Wages Paid, Net of Amounts Capitalized
     (82,661 )     (77,627 )     (74,627 )
  Capital Lease Interest Paid
     (54,293 )     (63,615 )     (67,673 )
  Interest Paid, Net of Amounts Capitalized
     (47,050 )     (44,100 )     (56,341 )
  Income Taxes Paid
     (23,609 )     (70,457 )     (28,900 )
  Other Cash Payments
     (3,580 )     (2,242 )     (3,743 )
    Net Cash Flows - Operating Activities
     264,112       227,228       243,013  
                         
Cash Flows from Investing Activities
                        
  Capital Expenditures
     (162,539 )     (156,180 )     (149,906 )
  Proceeds from Investments in Lease Debt and Equity
     27,732       22,158       13,646  
  Payments for Investments in Lease Debt and Equity
     -       (48,025 )     -  
  Other Proceeds from Investing Activities
     650       1,085       7,355  
  Other Payments for Investing Activities
     (2,968 )     (1,004 )     -  
    Net Cash Flows - Investing Activities
     (137,125 )     (181,966 )     (128,905 )
                         
Cash Flows from Financing Activities
                        
  Proceeds from Borrowings Under Revolving Credit Facility
     160,000       135,000       40,000  
  Repayments of Borrowings Under Revolving Credit Facility
     (180,000 )     (105,000 )     (40,000 )
  Dividends Paid to UniSource Energy
     (53,000 )     (62,000 )     (46,000 )
  Payments of Capital Lease Obligations
     (71,464 )     (61,111 )     (52,826 )
  Equity Investment from UniSource Energy
     18,000       -       110,000  
  Other Proceeds from Financing Activities
     7,795       16,852       8,297  
  Proceeds from Repayment of UniSource Energy Note
     -       -       95,393  
  Repayments of Long-Term Debt
     -       -       (281,766 )
  Payment of Debt Issue Costs
     (451 )     (1,631 )     (5,235 )
  Other Payments for Financing Activities
     (968 )     (1,094 )     (1,745 )
    Net Cash Flows - Financing Activities
     (120,088 )     (78,984 )     (173,882 )
                         
Net Increase (Decrease) in Cash and Cash Equivalents
     6,899       (33,722 )     (59,774 )
Cash and Cash Equivalents, Beginning of Year
     19,711       53,433       113,207  
Cash and Cash Equivalents, End of Year
   $ 26,610     $ 19,711     $ 53,433  
                         
See Note 16 for supplemental cash flow information.
                        
                         
See Notes to Consolidated Financial Statements.
                        
 
 
TUCSON ELECTRIC POWER COMPANY
            
CONSOLIDATED BALANCE SHEETS
            
             
   
December 31,
  
   
2007
    
2006
  
ASSETS
  
- Thousands of Dollars -
  
Utility Plant
            
  Plant in Service
   $ 3,143,823     $ 3,035,494  
  Utility Plant under Capital Leases
     701,631       701,631  
  Construction Work in Progress
     123,833       92,125  
    Total Utility Plant
     3,969,287       3,829,250  
  Less Accumulated Depreciation and Amortization
     (1,490,724 )     (1,446,229 )
  Less Accumulated Amortization of Capital Lease Assets
     (521,057 )     (495,634 )
    Total Utility Plant - Net
     1,957,506       1,887,387  
                 
Investments and Other Property
                
  Investments in Lease Debt and Equity
     152,544       181,222  
  Other
     35,460       30,161  
    Total Investments and Other Property
     188,004       211,383  
                 
Current Assets
                
  Cash and Cash Equivalents
     26,610       19,711  
  Trade Accounts Receivable
     90,747       97,512  
  Unbilled Accounts Receivable
     35,941       35,115  
  Allowance for Doubtful Accounts
     (16,538 )     (16,303 )
  Intercompany Accounts Receivable
     8,740       16,329  
  Materials and Fuel Inventory
     72,732       63,629  
  Income Taxes Receivable
     8,070       -  
  Current Regulatory Assets
     9,554       9,549  
  Deferred Income Taxes - Current
     59,157       57,151  
  Interest Receivable - Current
     9,383       7,782  
  Trading Assets
     2,036       15,447  
  Other
     13,062       8,833  
    Total Current Assets
     319,494       314,755  
                 
Regulatory and Other Assets
                
  Transition Recovery Regulatory Asset
     23,945       101,626  
  Income Taxes Recoverable Through Future Revenues - Regulatory Asset
     30,009       34,749  
  Other Regulatory Assets
     34,123       51,594  
  Other Assets
     19,955       21,569  
    Total Regulatory and Other Assets
     108,032       209,538  
                 
Total Assets
   $ 2,573,036     $ 2,623,063  
                 
See Notes to Consolidated Financial Statements.
                
                 
(Consolidated Balance Sheets Continued)
  
 
 
TUCSON ELECTRIC POWER COMPANY
            
CONSOLIDATED BALANCE SHEETS
            
             
   
December 31,
  
   
2007
    
2006
  
CAPITALIZATION AND OTHER LIABILITIES
  
- Thousands of Dollars -
  
Capitalization
            
  Common Stock Equity
   $ 577,349     $ 554,714  
  Capital Lease Obligations net of Current Obligations
     530,714       588,424  
  Long-Term Debt net of Current Maturities
     682,870       821,170  
    Total Capitalization
     1,790,933       1,964,308  
                 
Current Liabilities
                
  Current Obligations under Capital Leases
     58,502       58,999  
  Current Maturities of Long Term Debt
     138,300       -  
  Borrowing Under Revolving Credit Facility
     10,000       30,000  
  Accounts Payable
     87,599       69,019  
  Intercompany Accounts Payable
     4,512       10,743  
  Income Taxes Payable
     -       8,409  
  Interest Accrued
     41,394       45,613  
  Accrued Taxes Other than Income Taxes
     28,690       27,227  
  Accrued Employee Expenses
     22,557       21,102  
  Trading Liabilities
     2,460       11,163  
  Other
     15,533       14,278  
    Total Current Liabilities
     409,547       296,553  
                 
Deferred Credits and Other Liabilities
                
  Deferred Income Taxes - Noncurrent
     163,834       155,253  
  Regulatory Liability - Net Cost of Removal for Interim Retirements
     87,311       79,876  
  Pension and Other Post-Retirement Benefits
     72,755       99,832  
  Other
     48,656       27,241  
    Total Deferred Credits and Other Liabilities
     372,556       362,202  
                 
Commitments and Contingencies (Note 5)
                
                 
Total Capitalization and Other Liabilities
   $ 2,573,036     $ 2,623,063  
                 
See Notes to Consolidated Financial Statements.
                
                 
(Consolidated Balance Sheets Concluded)
  
 
 
TUCSON ELECTRIC POWER COMPANY
                        
CONSOLIDATED STATEMENTS OF CAPITALIZATION
                    
               
December 31,
  
               
2007
    
2006
  
COMMON STOCK EQUITY
              
- Thousands of Dollars -
  
                         
  Common Stock-No Par Value
               $ 813,971     $ 795,971  
   
2007
    
2006
                  
    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
                     (218,488 )     (219,640 )
  Accumulated Other Comprehensive Loss
                     (11,777 )     (15,260 )
           Total Common Stock Equity
                     577,349       554,714  
                                 
PREFERRED STOCK
                                
No Par Value, 1,000,000 Shares Authorized, None Outstanding
               -       -  
                                 
CAPITAL LEASE OBLIGATIONS
                                
  Springerville Unit 1
                     345,800       381,446  
  Springerville Coal Handling Facilities
                     99,175       112,177  
  Springerville Common Facilities
                     107,630       106,837  
  Sundt Unit 4
                     36,034       46,140  
  Other Leases
                     577       823  
        Total Capital Lease Obligations
                     589,216       647,423  
        Less Current Maturities
                     (58,502 )     (58,999 )
          Total Long-Term Capital Lease Obligations
                     530,714       588,424  
                                 
LONG-TERM DEBT
                                
                Issue
  
Maturity
    
Interest Rate
                  
  Variable Rate IDBs
  
2011
    
Variable*
       328,600       328,600  
  Collateral Trust Bonds
  
2008
      
7.50%
       138,300       138,300  
  Unsecured IDBs
    
2020 - 2033
    
5.85% to 7.13%
       354,270       354,270  
        Total Stated Principal Amount
                     821,170       821,170  
        Less Current Maturities
                     (138,300 )     -  
          Total Long-Term Debt
                     682,870       821,170  
                                 
Total Capitalization
                   $ 1,790,933     $ 1,964,308  
 
* TEP’s Variable Rate industrial development bonds (IDBs) are backed by letters of credit (LOCs) issued pursuant to TEP’s Credit Agreement which expires in August 2011.  Although the Variable Rate IDBs mature between 2018 and 2022, the above maturity reflects a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.  Weighted average interest rates on this variable rate tax-exempt debt ranged from 3.11% to 3.95% during 2007, 2.95% to 3.96% during 2006, and 1.52% to 3.55% during 2005 and the average interest rate on such debt was 3.64% in 2007, 3.47% in 2006 and 2.48% in 2005.

See Notes to Consolidated Financial Statements.
 
 
TUCSON ELECTRIC POWER COMPANY
                              
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME
  
                               
                     
Accumulated
 
  
         
Capital
          
Other
    
Total
  
   
Common
    
Stock
    
Accumulated
    
Comprehensive
    
Stockholder's
  
   
Stock
    
Expense
    
Deficit
    
Loss
    
Equity
  
   
- Thousands of Dollars -
  
                               
Balances at December 31, 2004
   $ 658,254     $ (6,357 )     $   (226,652 )     $       (10,735 )   $ 414,510  
                                         
Comprehensive Income:
                                        
2005 Net Income
     -       -       48,267       -       48,267  
                                         
Minimum Pension Liability Adjustment
(net of $1,378 income taxes)
     -       -       -       (2,101 )     (2,101 )
                                         
Unrealized Gain on Cash Flow Hedges
(net of $6,503 income taxes)
     -       -       -       9,918       9,918  
                                       
Reclassification of Unrealized Gains on Cash Flow Hedges to Net Income
(net of $2,403 income taxes)
     -       -       -       (3,665 )     (3,665 )
                                         
Total Comprehensive Income
                                     52,419  
                                         
Dividends Paid
     -       -       (46,000 )     -       (46,000 )
Capital Contribution from UniSource Energy
     137,717       -       -       -       137,717  
                                         
Balances at December 31, 2005
     795,971       (6,357 )     (224,385 )     (6,583 )     558,646  
                                         
Comprehensive Income:
                                        
2006 Net Income
     -       -       66,745       -       66,745  
 
                                        
Minimum Pension Liability Adjustment
(net of $8,915 income taxes)
     -       -       -       13,597       13,597  
 
                                        
Unrealized Loss on Cash Flow Hedges
(net of $4,897 income taxes)
     -       -       -       (7,469 )     (7,469 )
                                         
 Reclassification of Unrealized Gains on Cash Flow Hedges to Net Income
(net of $77 income taxes)
     -       -       -       (117 )     (117 )
                                         
Total Comprehensive Income
                                     72,756  
                                         
Adjustment to Initially Recognize the Funded Status of Employee Benefit Plans
(net of $9,630 income taxes)
     -       -       -       (14,688 )     (14,688 )
                                         
Dividends Paid
     -       -       (62,000 )     -       (62,000 )
                                         
Balances at December 31, 2006
     795,971       (6,357 )     (219,640 )     (15,260 )     554,714  
                                         
Implementation of FIN 48
                     696               696  
                                         
Comprehensive Income:
                                        
2007 Net Income
     -       -       53,456       -       53,456  
                                         
Decrease in Pension and Other Post-Retirement Benefit Liabilities
(net of $3,820 income taxes)
     -       -       -       5,826       5,826  
                                         
Unrealized Loss on Cash Flow Hedges
(net of $2,532 income taxes)
     -       -       -       (3,862 )     (3,862 )
 
                                        
Reclassification of Unrealized Losses on Cash Flow Hedges to Net Income
(net of $996 income taxes)
     -       -       -       1,519       1,519  
                                         
Total Comprehensive Income
                                     56,939  
                                         
Capital Contribution from UniSource Energy
     18,000       -       -       -       18,000  
Dividends Paid
     -       -       (53,000 )     -       (53,000 )
                                         
Balances at December 31, 2007
   $ 813,971     $ (6,357 )     $   (218,488 )     $       (11,777 )   $ 577,349  
                                         
We describe limitations on TEP's ability to pay dividends in Note 9.
                          
                                         
See Notes to Consolidated Financial Statements.
                                  
 
 
NOTE 1.  NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

UniSource Energy Corporation (UniSource Energy) is a holding company that has no significant operations of its own.  Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities.  UniSource Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium) and UniSource Energy Development Company (UED).

TEP, a regulated public utility, is UniSource Energy’s largest operating subsidiary and represented approximately 81% of UniSource Energy’s assets as of December 31, 2007.  TEP generates, transmits and distributes electricity to approximately 397,000 retail electric customers in a 1,155 square mile area in Southern Arizona.  TEP also sells electricity to other utilities and power marketing entities primarily located in the Western U.S.  In addition, TEP operates Springerville Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State).

UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric).  UNS Gas is a gas distribution company with 146,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in Northern Arizona, as well as Santa Cruz County in South Central Arizona.  UNS Electric is an electric transmission and distribution company with approximately 90,000 retail customers in Mohave and Santa Cruz counties.

Millennium invests in unregulated energy related businesses.  On March 31, 2006, UniSource Energy completed the sale of all of the capital stock of Global Solar, Inc. (Global Solar), Millennium’s largest subsidiary, to a third party.  We present Global Solar’s assets, liabilities and related operations throughout this report as discontinued operations.  See Note 15.

UED facilitated the expansion of the Springerville Generating Station and is currently developing the Black Mountain Generating Station (BMGS), a 90 MW gas turbine project in Northern Arizona that, subject to ACC approval, is expected to provide energy to UNS Electric.

We conduct our business in three primary business segments – TEP, UNS Gas and UNS Electric.

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

BASIS OF PRESENTATION

We account for our investments in subsidiaries using the consolidation method when we hold a majority of a subsidiary’s voting stock and we can exercise control over the subsidiary. The accounts of the subsidiary and parent are combined, and intercompany balances and transactions are eliminated.  Intercompany profits on transactions between regulated entities are not eliminated.

We use the equity method to report corporate joint ventures, partnerships, and affiliated company investments when we can demonstrate the ability to exercise significant influence over the operating and financial policies of an investee company.  Equity method investments appear on a single line item on the balance sheet and net income (loss) from the entity is reflected in Other Income on the income statements.

The equity investments at December 31, 2007 were:

Investee
% Owned
   
UniSource Energy
  
Carboelectrica Sabinas, S. de R.L. de C.V.
50.0%
Haddington Energy Partners II, LP
31.6%
Valley Ventures III, LP
15.0%
   
TEP
  
Inncom International, Inc.
16.7%

 
USE OF ACCOUNTING ESTIMATES

We make estimates and assumptions to prepare financial statements under accounting principles generally accepted in the U.S. (GAAP).  These estimates and assumptions affect:

 
·
A portion of the reported amounts of assets and liabilities at the dates of the financial statements;
 
·
Our disclosures about contingent assets and liabilities at the dates of the financial statements; and
 
·
A portion of revenues and expenses reported during the periods.

Because these estimates involve judgments, the actual amounts may differ from the estimates.

ACCOUNTING FOR RATE REGULATION

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) regulate portions of TEP’s, UNS Gas’ and UNS Electric’s utility accounting practices and rates.  The ACC authorizes certain rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.  The FERC regulates TEP’s and UNS Electric’s rates for wholesale power sales and transmission services.

We apply the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71) to the transmission and distribution portion of our business.  In accordance with FAS 71, regulatory assets and liabilities are recorded in the consolidated balance sheets.  Regulatory assets are the deferral of costs expected to be recovered in future customer rates and regulatory liabilities represent current recovery of expected future costs.

The conditions a regulated company must satisfy to apply the accounting policies and practices of FAS 71 include:

 
·
an independent regulator sets rates;
 
·
the regulator sets the rates to recover the specific enterprise’s costs of providing service; and
 
·
the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

We evaluate our regulatory assets each period and believe recovery of these is probable.  We have received or requested return on certain regulatory assets for which we are currently recovering or seeking recovery through rates.  If we were required to terminate application of FAS 71 for all of our regulated operations, we would have to record an extraordinary gain (loss) in the income statement to remove all of the regulatory assets and liabilities in the balance sheet at that time.  See Note 2.

CASH AND CASH EQUIVALENTS

We define Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with an original maturity of three months or less.

RESTRICTED CASH

Restricted cash represents cash deposits that have withdrawal restrictions, or are set aside for a specific use and not available for general current operations.  Cash deposits that are restricted for a period of less than one year, or that are restricted as to use but are available to meet specific current operational requirements, are classified on the balance sheet as Other Current Assets.  Balances that are restricted as to withdrawal for more than one year or are designated for a purpose other than current operations are classified on the balance sheet as Investments and Other Property, Other.  Restricted cash includes cash on deposit in support of our self-insured medical and worker’s compensation plans, amounts on deposit for credit enhancement with counterparties and deposits to meet contractual and regulatory requirements.  The corresponding cash receipts and payments are reflected in the statement of cash flows as investing activities.

UTILITY PLANT

TEP, UNS Gas and UNS Electric report utility plant at cost.  Costs included in utility plant are:

 
·
Material and labor,
 
·
Contractor services,
 
·
Construction overhead (where applicable), and
 
 
 
·
An Allowance for Funds Used During Construction (AFUDC) or capitalized interest during construction.

TEP, UNS Gas and UNS Electric charge the cost of repairs and minor replacements to the appropriate operating expense accounts. Costs to replace major units of property are included in utility plant.   The cost of planned major maintenance activities, including scheduled overhauls at TEP’s generation plants, is recorded as the costs are actually incurred.  Replacement of capital equipment included in plant maintenance activities is capitalized to utility plant.  All other plant maintenance costs are expensed as incurred.

When a unit of regulated property is retired the original cost less any salvage value is credited or charged to accumulated depreciation.  Interim retirements of unregulated generation plant, together with the cost of removal less salvage, are charged to accumulated depreciation.  Gains and losses resulting from the final retirement of unregulated properties are credited or charged to the income statement and the corresponding cost and accumulated depreciation is removed from the balance sheet.

AFUDC and Capitalized Interest

In accordance with the uniform system of accounts prescribed by regulatory authorities, AFUDC, which reflects the net cost of borrowed or other funds used during construction, is capitalized as part of the cost of regulated utility plant.  The interest capitalized that relates to debt reduces Other Interest Expense on the income statement.  The interest capitalized that relates to equity funds is recorded as Other Income.

The interest capitalized for TEP’s unregulated generation-related construction projects is included as a reduction of Other Interest Expense.
 
 
TEP
 
2007
2006
2005
Average AFUDC on regulated T&D construction expenditures
10.05%
8.59%
8.20%
AFUDC - Debt (in millions)
$2
$1
$1
AFUDC - Equity (in millions)
$1
$1
$1
Average capitalized interest rate on unregulated generation-related construction expenditures
 
5.73%
 
5.72%
 
4.78%
Capitalized interest (in millions)
$1
$3
$3
 
 
 
UNS Gas
 
2007
2006
2005
Average AFUDC on regulated construction expenditures
8.12%
8.29%
7.83%
AFUDC - Debt (in millions)
$0.3
$0.1
$0.2
AFUDC - Equity (in millions)
$0.3
$0.1
$0.2

 
 
UNS Electric
 
2007
2006
2005
Average AFUDC on regulated construction expenditures
13.51%
10.93%
9.03%
AFUDC - Debt (in millions)
$0.7
$0.5
$0.2
AFUDC - Equity (in millions)
$0.4
$0.5
$0.2

Depreciation

TEP, UNS Gas and UNS Electric compute depreciation for owned utility plant on a straight-line basis at rates based on the economic lives of the assets. See Note 6.  The ACC approves depreciation rates for all utility plant except TEP’s deregulated generation assets.  The depreciable lives for TEP’s deregulated generation plant are based on remaining useful lives.  The depreciable lives for TEP’s regulated transmission, distribution, general and intangible plant are based on average useful lives and reflect estimated removal costs, net of estimated salvage value for interim retirements.  We have summarized the average annual depreciation rates for all utility plants below.
 
 
Year
TEP
UNS Gas
UNS Electric
2007
3.35%
3.28%
4.60%
2006
3.21%
3.05%
4.52%
2005
3.45%
2.93%
4.04%

Computer Software Costs

TEP, UNS Gas and UNS Electric capitalize costs incurred to purchase computer software and amortize those costs over the estimated economic life of the product.  If the software is no longer useful, we immediately charge capitalized computer software costs to expense.  TEP amortized capitalized computer software costs of $9 million in 2007, $7 million in 2006, and $8 million in 2005.

TEP Utility Plant under Capital Leases

TEP financed the following generation assets with capital leases:

 
·
Springerville Common Facilities,
 
·
Springerville Unit 1,
 
·
Springerville Coal Handling Facilities, and
 
·
Sundt Unit 4.

The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases.  The lease terms are described in TEP Capital Lease Obligations in Note 7.

   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
Lease Expense:
                  
Interest Expense on Capital Leases
   $ 64     $ 72     $ 79  
Amortization of Capital Lease Assets – Included in:
                        
Operating Expenses – Fuel
     4       4       5  
Operating Expenses – Depreciation and Amortization
     21       22       23  
Total Lease Expense
   $ 89     $ 98     $ 107  

ASSET RETIREMENT OBLIGATIONS

Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143) requires entities to record the estimated present value of a liability for a legal obligation to retire an asset in the future.  FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), requires entities to record the estimated present value of a liability for a legal obligation to perform asset retirement activity even if the timing and (or) method of settlement depends on a future event that may or may not be within the control of the entity.

TEP records a liability for the estimated present value of a conditional asset retirement obligation related to its unregulated generation assets as follows:

 
·
when it is able to reasonably estimate the fair value of any future obligation to retire as a result of an existing or enacted law, statute, ordinance or contract; or
 
·
if it can reasonably estimate the fair value.

When the liability is initially recorded at net present value, TEP capitalizes the cost by increasing the carrying amount of the related long-lived asset.  Over time, TEP adjusts the liability to its present value by recognizing accretion expense as an operating expense each period, and the capitalized cost is depreciated over the useful life of the related asset.  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, UNS Gas and UNS Electric continue to record cost of removal for their regulated transmission and distribution assets through depreciation rates and recover those amounts in rates charged to their customers.  There are no legal obligations associated with these assets.  TEP, UNS Gas and UNS Electric have recorded their
 
 
obligation for estimated costs of removal as regulatory liabilities for their regulated transmission and distribution property.  See Note 2.

Cumulative Effect of Accounting Change

In 2005, TEP implemented FIN 47.  The implementation of FIN 47 required TEP to update an existing inventory, originally created for the implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated.   Upon implementation of FIN 47, TEP recorded an asset retirement obligation of $16 million at its net present value of $3 million, increased depreciable assets by an immaterial amount for asset retirement costs and recognized the cumulative effect of accounting change as a loss of less than $1 million after tax.


EVALUATION OF ASSETS FOR IMPAIRMENT

TEP, UNS Gas and UNS Electric evaluate their Utility Plant and other long-lived assets for impairment whenever events or circumstances indicate that the value of the assets may be impaired.  If the fair value of the asset, determined based on the undiscounted expected future cash flows, is less than the carrying value of the asset, an impairment charge would be recorded.

Millennium evaluates its investments for impairment at the end of each quarter.  If the decline in fair value is judged to be other-than-temporary, an impairment loss would be recorded.

INVESTMENTS IN LEASE DEBT

TEP’s investments in lease debt are considered to be held-to-maturity investments because TEP has the ability and intent to hold until maturity.  TEP records these investments at amortized costs and recognizes interest income.  TEP presents these investments in Investments in Lease Debt on the balance sheet and classifies them as investing activities on its cash flow statements.

AMORTIZATION OF DEBT ISSUANCE COSTS

We defer costs related to the issuance of debt and amortize on a straight-line basis over the life of the debt.  These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting and regulatory fees and printing costs.

TEP and UNS recognize gains and losses on reacquired debt, including unamortized debt issuance costs, associated with their unregulated operations, as incurred.  TEP, UNS Gas and UNS Electric defer and amortize the gains and losses on reacquired debt associated with their regulated operations to interest expense over the remaining life of the original debt.

UTILITY OPERATING REVENUES

TEP, UNS Gas and UNS Electric record utility operating revenues when services are provided or commodities are delivered to customers.  Operating revenues include unbilled revenues which are earned (service has been provided) but not billed by the end of an accounting period.

Amounts delivered are determined through systematic monthly 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 calculated based on daily generation or purchased volumes, estimated customer usage by class, estimated line losses and estimated average customer 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, and changes in the composition of customer classes.

TEP revenue and purchase power costs from settled energy contracts that are not physically delivered are reported on a net basis in Electric Wholesale Sales.  The corresponding cash receipts and payments are recorded in the statement of cash flows as Cash Receipts from Electric Wholesale Sales and Purchased Energy Costs Paid, respectively.
 
 
We record an Allowance for Doubtful Accounts to reduce accounts receivable for revenue amounts that are estimated to be uncollectible.  TEP, UNS Gas and UNS Electric establish an allowance for doubtful accounts based on historical collection experience and any specific customer collection issues that are identified.  TEP’s Allowance for Doubtful Accounts was $16 million at December 31, 2007 and at December 31, 2006.  UNS Gas and UNS Electric’s combined Allowance for Doubtful Accounts was $2 million at December 31, 2007 and less than $1 million at December 31, 2006.

FUEL AND PURCHASED ENERGY COSTS

TEP

TEP records fuel inventory, primarily coal, at weighted average cost.  TEP uses full absorption costing, under which, all handling and procurement costs are included in the cost of the inventory.  Examples of these costs include direct material, direct labor, overhead costs and transportation costs.  See Purchase and Transportation Commitments in Note 5.

UNS Gas

UNS Gas defers differences between gas purchase costs and the recovery of such costs in revenues under a Purchased Gas Adjustor (PGA) mechanism.  The PGA mechanism addresses the volatility of natural gas prices and allows UNS Gas to recover its commodity costs through a price adjustor.  UNS Gas may change the PGA charge monthly based on an ACC approved mechanism that compares the twelve-month rolling average gas cost to the base cost of gas, subject to limitations on how much the price per therm may change in a twelve-month period.  The difference between the actual cost of UNS Gas’ gas supplies and transportation contracts and that currently allowed by the ACC is deferred and recovered or repaid through the PGA mechanism.  When under or over recovery trigger points are met, UNS Gas may request a PGA surcharge or surcredit with the goal of collecting or returning the amount deferred from or to customers over a twelve-month period.  See Note 2.

UNS Electric

UNS Electric defers differences between purchased energy costs and the recovery of such costs in revenues.  Future billings are adjusted for such deferrals through the use of a Purchased Power and Fuel Adjustment Clause (PPFAC) approved by the ACC.  The PPFAC allows for a revenue surcharge or surcredit (that adjusts the customer’s base rate for delivered purchased power) to collect or return under- or over- recovery of costs.

INCOME TAXES

GAAP requires us to report some of our assets and liabilities differently for our financial statements than we do for income tax purposes.  We reflect the tax effects of these differences as deferred income tax assets or liabilities in our balance sheets.  We measure these deferred tax assets and liabilities using current income tax rates.  Federal and state income tax credits are accounted for as a reduction of income tax expense in the year in which the credit arises.

GAAP requires that regulated enterprises that apply FAS 71 record a deferred income tax liability for tax benefits that are flowed through to a customer when temporary differences arise.   A regulatory asset is established for the future increases in taxes payable and is recovered from customers through future rates as temporary differences reverse.  TEP became fully normalized in 1990 and temporary differences, arising after that point in time, do not flow through to ratepayers. The balance in the regulatory asset for Income Taxes Recoverable Through Future Revenues relates to flow through years prior to 1990.  See Note 2.

We allocate income taxes to the subsidiaries based on their taxable income and deductions as reported in the consolidated tax return filings.

UniSource Energy and TEP record interest on unrecognized tax benefits or liabilities as either Interest Income or Interest Expense in the income statements.  No penalties were incurred.
 
TAXES OTHER THAN INCOME TAXES

TEP, UNS Gas and UNS Electric act as conduits or collection agents for excise tax (sales tax) as well as franchise fees and regulatory assessments.  They record liabilities payable to governmental agencies when they charge their customers for these amounts.  Neither the amounts charged nor payable are reflected in the income statement.

 
EMISSION ALLOWANCES

The Environmental Protection Agency (EPA) issues emission allowances to qualifying utilities based on past operational history.  Each allowance permits emission of one ton of sulfur dioxide (SO2) in its vintage year or a subsequent year.  TEP receives an allotment of these allowances annually, but UNS Electric does not receive any since it has no coal-fired generation.  When issued from the EPA, these allowances have no book value for accounting purposes but may be sold if TEP does not need them for operations.  TEP also may purchase additional allowances if needed.  The gains from sales of excess allowances are reflected as a reduction of Other Operations and Maintenance expense on TEP’s income statement when title passes.

DERIVATIVE FINANCIAL INSTRUMENTS

TEP, UNS Gas and UNS Electric use derivative financial instruments including forward power sales and purchases and gas swaps to manage exposure to energy price risk.
 
On the date the company enters into a derivative contract, we apply one of the following accounting treatments:

 
·
Cash Flow Hedges are used to hedge the changes in cash flows that are to be received or paid in connection with future purchases or sales.  These contracts include gas swap agreements and forward power contracts to hedge the cash flow risk associated with TEP’s summer load requirements and its forecasted excess generation.  The effective portion of the changes in the market prices of cash flow hedges are recorded as unrealized gains and losses in Other Comprehensive Income and the ineffective portion is recognized in earnings.

 
·
Mark-to-Market transactions include (1) non-trading hedges that did not qualify for cash flow hedge accounting treatment or did not qualify for normal scope exception or  (2) trading derivatives which are contracts entered into to reduce our exposure to energy and commodity prices.  These contracts are subject to specified risk parameters established and monitored by UniSource Energy’s Risk Management Committee.  Unrealized gains and losses resulting from changes in the market prices of mark-to-market transactions are recorded on the same line in the income statement as the hedged transaction.

 
·
Normal Purchase and Sale transactions are derivative contracts entered into to support the current load forecast and entered into with a counterparty with load serving requirements or generating capacity.  These contracts are not required to be marked-to-market and are accounted for on an accrual basis.

We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in the cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. 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. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, we will carry the derivative at its fair value on the balance sheet, recognizing changes in the fair value in current-period earnings.  In order to determine the correct balance sheet classification of derivative instruments that extend beyond one year, we bifurcate all derivatives into their current and long-term portions.

In December 2006, the ACC granted UNS Electric an accounting order to record the unrealized gains and losses as a regulatory asset or a regulatory liability rather than as a component of OCI or in the income statement.  As these contracts settle, the actual costs of the power purchased are charged to the PPFAC.

TEP entered into an interest rate swap to reduce the cash flow risk associated with unfavorable changes in the variable interest rate on the Springerville Common Lease.  Changes in the market price of the interest rate swap are recorded in Other Comprehensive Income.

MEG entered into swap agreements, options and forward contracts relating to Emission Allowances.  MEG records these derivative instruments at fair value with changes in market prices recorded in earnings.  All of  MEG’s forward contracts were settled in December 2007.

Although TEP’s and MEG’s gains and losses on trading activities are recorded on a net basis in the income statement, we report the related cash receipts and cash payments separately in the statement of cash flows.
 
 
See Note 4.

SHARE-BASED COMPENSATION

Effective January 1, 2005, we prospectively adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment (FAS 123(R)).  Before January 1, 2005, we accounted for our share-based compensation under the principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), and related interpretations and applied the disclosure only guidance in Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.  Our share-based compensation plans are described more fully in Note 12.
Our stock options were granted with an exercise price equal to the market value of the stock at the date of the grant.  Accordingly, before January 1, 2005, under the provisions of APB 25, no compensation expense was recorded for these awards.  However, compensation expense was recognized for restricted stock, stock unit and performance share awards over the performance/vesting period.  Beginning January 1, 2005, under the provisions of FAS 123(R), we began recognizing compensation expense over the vesting period for the fair value of the new stock options granted.

NEW ACCOUNTING STANDARDS

 
·
SEC Staff Accounting Bulletin (SAB No. 110), issued December 2007, expresses the views of the SEC regarding the use of a simplified method in developing an estimate of expected term for “plain vanilla” share options in accordance with FAS Statement No. 123 (revised 2004).  The SEC Staff believes that it may be appropriate to use the simplified method in the following circumstances: (1) there is insufficient historical data to use as a basis for measuring expected term, or (2) there have been significant changes to the terms of its share option grants or the types of employees that receive share option grants, or (3) there have been significant structural changes to the company.   The guidance is applicable to share option grants after December 31, 2007, and we are assessing whether it is appropriate for us to use the simplified method for future share option grants.

 
·
FAS 160, Accounting and Reporting of Noncontrolling Interests in Consolidated Financial Statements, issued December 2007, will change the accounting and reporting for minority interests, requiring such amounts to be classified as a component of equity, and will also change the accounting for transactions with minority-interest holders. The standard will be applicable for fiscal years beginning on or after December 15, 2008 on a prospective basis.  Early adoption is prohibited and business combinations with acquisition dates prior to the effective date will not be adjusted upon application.  We do not expect this pronouncement to have a material impact on our financial statements.

 
·
FAS 141(R) Business Combinations - a replacement of FAS No. 141, issued December 2007, requires companies to record acquisitions at fair value.  FAS 141(R) changes the definition of a business and a business combination and is generally expected to increase the number of transactions that will need to be accounted for at fair value.  The standard will be applicable for fiscal years beginning on or after December 15, 2008 and generally on a prospective basis.  Early adoption is prohibited and business combinations with acquisition dates prior to the effective date will not be adjusted upon application.  We do not expect this pronouncement to have a material impact on our financial statements.

 
·
FSP FASB Interpretation (FIN) 39-1, issued April 2007, allows entities that are party to a master netting arrangement to offset the receivable or payable recognized upon payment or receipt of cash collateral against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement.  Upon adoption of FSP FIN 39-1, an entity is required to make an accounting policy decision to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements.  FSP FIN 39-1 became effective January 1, 2008.  We will continue to present cash collateral and derivatives assets and liabilities separately in our financial statements.

 
·
FAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, issued February 2007, provides companies with the option of measuring certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur.  FAS 159 also establishes disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elects the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each item.  We have not elected fair value accounting for any of our eligible financial instruments.
 
 
 
·
FAS 157, Fair Value Measurement, issued September 2006, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  FAS 157 clarifies that the exchange price is the price in the principal market in which the reporting entity would transact for the asset or liability.  The implementation of FAS 157 on January 1, 2008 had no impact on our financial statements.  We will begin disclosing inputs to develop fair value measurements and the effect of any of our assumptions on earnings or net assets for the quarter ending March 31, 2008.

 
·
The Pension Protection Act of 2006 (Pension Act) became effective January 1, 2008.  The new law affects the manner in which many companies, including UniSource Energy and TEP, administer their pension plans.  The Pension Act resulted in no additional funding requirements for TEP, UNS Gas or UNS Electric.

RECLASSIFICATIONS

To be comparable with the 2007 presentation, TEP reclassified, from Purchased Energy to Electric Wholesale Sales, $9 million of purchase power costs in 2006 relating to settled energy contracts that were not physically delivered.  This reclassification had no effect on Net Income.  No reclassification was made to the 2005 reported amounts.

NOTE 2.  REGULATORY MATTERS

TEP RATES AND REGULATION

Upon approval of the TEP Settlement Agreement in 1999, TEP discontinued regulatory accounting under FAS 71 for its generation operations.  TEP continues to report its transmission and distribution operations under FAS 71.

TEP Settlement Agreement

In 1999, the ACC approved the Rules for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.

The Rules and the Settlement Agreement established:

 
·
a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure;
 
·
the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (Fixed CTC);
 
·
capped rates for TEP retail customers through 2008;
 
·
an ACC interim review of TEP retail rates in 2004;
 
·
unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services;
 
·
a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers;
 
·
access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs); and
 
·
transmission and distribution services would remain subject to regulation on a cost of service basis.

We believe that the Settlement Agreement contemplates that the price TEP charges its retail customers for generation be market-based and its retail customers should begin paying the market rate for generation services beginning on January 1, 2009.

In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC.  While TEP’s filing did not propose any change in retail rates, the filing, with a test year ended December 31, 2003, showed that TEP was experiencing a revenue deficiency of $111 million, reflecting the need for an increase in retail rates of 16%.

TEP Rate Proposal Filing

In April 2006, the ACC ordered that a procedure be established to allow for a review of:
 
 
 
·
the TEP Settlement Agreement and its effect on how TEP’s rates for generation services will be determined after December 31, 2008;
 
·
TEP’s proposed amendments to the TEP Settlement Agreement; and
 
·
Demand-Side Management (DSM), Renewable Energy Standards Tariffs (REST), and Time of use Tariffs (TOU).

In July 2007, as required by the ACC, TEP filed the following rate proposal methodologies to establish new retail rates for TEP beginning in January 2009:

    (1)
Market-based generation and cost of service for transmission and distribution, showing a revenue deficiency of $172 million, reflecting an overall increase of approximately 22% over current retail rates.
    (2)
Cost-of-service for generation, transmission and distribution showing a revenue deficiency of $181 million, reflecting an overall increase of approximately 23% over current retail rates.
    (3)
Hybrid methodology with cost of service for generation, transmission and distribution. However, certain generation assets would be excluded from cost of service, showing a revenue deficiency of $117 million, reflecting an overall increase of approximately 15% over current retail rates.

Based on the TEP Settlement Agreement, TEP believes it is entitled to charge market-based generation service rates starting in 2009.

The ACC ordered that the Rate Case hearing for TEP start in May 2008.

Transition Recovery Asset

TEP’s Transition Recovery Asset consists of generation-related regulatory assets and a portion of TEP’s generation plant asset costs.  Transition costs being recovered through the Fixed CTC include: (1) the Transition Recovery Regulatory Asset; (2) a small portion of generation-related plant assets included in Plant in Service on the balance sheet; and (3) excess capacity deferrals related to operating and capital costs associated with Springerville Unit 2 which were amortized as an off-balance sheet regulatory asset through 2003.  These transition costs were amortized as follows:
 
   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
Amortization of Transition Costs Being Recovered through the Fixed CTC:
  
Transition Costs Being Recovered through the Fixed CTC, beginning of year
   $ 112     $ 185     $ 247  
Amortization of Transition Recovery Asset Recorded on the Income Statement
     (78 )     (66 )     (56 )
Amortization of Generation-Related Plant Assets
     (8 )     (7 )     (6 )
Transition Costs Being Recovered through the Fixed CTC, end of year
   $ 26     $ 112     $ 185  

TEP amortized the portion of the Transition Recovery Regulatory Asset that is recorded on the balance sheet as follows:

   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
               
Transition Recovery Regulatory Asset, beginning of year
   $ 102     $ 168     $ 224  
Amortization of Transition Recovery Asset Recorded on the Income Statement
     (78 )     (66 )     (56 )
Transition Recovery Regulatory Asset, end of year
   $ 24     $ 102     $ 168  
 
 
The remaining transition costs being recovered through the Fixed CTC differ from the Transition Recovery Asset recorded on the balance sheet as follows:

   
December 31,
  
   
2007
    
2006
  
   
-Millions of Dollars-
  
Transition Costs Being Recovered through the Fixed CTC, end of year
   $ 26     $ 112  
Unamortized Generation-Related Plant Assets
     (2 )     (10 )
Transition Recovery Asset, end of year
   $ 24     $ 102  

TEP will amortize the remaining Transition Recovery Asset balance as costs are recovered through rates until TEP has recovered $450 million of transition costs.  It is expected that by May 31, 2008, the TRA will be amortized to zero.

In May 2007, the ACC ordered that TEP’s current Standard Offer rates shall remain at their current level, including continued collection of the Fixed Competition Transition Charge (Fixed CTC) ($0.009 per kWh), until the effective date of a final order in the rate proposal proceeding.  The incremental income collected as a result of retaining the “true up” revenue after it would otherwise terminate shall accrue interest and shall be recorded as deferred revenue.  The treatment of the deferred revenue will be determined when the TEP rate case is finalized.

Other Regulatory Assets and Liabilities

In addition to the Transition Recovery Asset related to TEP’s generation assets, TEP recovers the following regulatory assets and liabilities through TEP’s transmission and distribution businesses:
 
 
December 31,
 
2007
  
2006
                                                                         
-Millions of Dollars-
 Current Regulatory Assets          
    Property Tax Deferrals
 $ 9     $ 9
    Self-Insured Medical Deferrals
   1       1
Total Current Regulatory Assets
   10       10
Income Taxes Recoverable through Future Revenues
   30       35
Other Regulatory Assets
          
Pension Asset related to Regulated T&D
   15       32
Deregulation Costs
   13       13
Rate Case Costs
   1       -
   Unamortized Loss on Reacquired Debt related to Regulated T&D
   6       7
Total Other Regulatory Assets
 $ 35     $ 52
Other Regulatory Liabilities
          
Net Cost of Removal for Interim Retirements related to Regulated T&D
 $ 87     $ 80

Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

 
·
Property Tax, Self-Insured Medical Deferrals are recorded based on historical ratemaking treatment allowing TEP to recover property taxes and self-insured medical costs.  While these assets do not earn a return, they are fully recovered in rates over an approximate one-year period.
 
·
Income Taxes Recoverable Through Future Revenues, while not included in rate base, are amortized over the life of the assets and included in the ratemaking calculation of income tax.
 
·
Pension Assets were recorded in 2006. Based on past regulatory actions, TEP expects to recover in rates the transmission and distribution portion of the underfunded Salaried and Union pension plans.  TEP does not earn a return on these costs.
 
·
Deregulation costs were incurred to comply with various ACC deregulation orders.  TEP received ACC approval to defer these costs.   The recovery period will be determined in TEP’s next rate case.  TEP does not earn a return on these costs.
 
·
TEP has requested recovery of costs associated with its 2007 rate case filing.  Historically, the ACC has allowed recovery of rate case costs.  The recovery period will be determined when the ACC rules on TEP’s rate case in 2008.  TEP does not earn a return on these costs.
 
 
 
·
Unamortized Loss on Reacquired Debt Costs related to TEP’s regulated business is, in accordance with FERC guidelines, amortized over the remaining life of the related debt instruments.  While the asset is not included in rate base, the amortization, over a period of 21 years, is included in the ratemaking calculation of the cost of debt.  TEP does not earn a return on these costs.

Regulatory liabilities represent items that TEP expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

 
·
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.

Income Statement Impact of Applying FAS 71

The amortization of TEP’s regulatory assets affected TEP’s income statements as follows:

   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
Operating Expenses
                  
Amortization of Transition Recovery Regulated Asset
   $ 78     $ 66     $ 56  
Depreciation related to Net Cost of Removal for Interim Retirements
     7       5       7  
Interest Expense
                        
Long-Term Debt
     1       1       2  
Income Taxes
     5       5       5  
    Total
   $ 91     $ 77     $ 70  

If TEP had not applied FAS 71 in these years, the above amounts would have been reflected in the income statements in prior periods. 

Future Implications of Discontinuing Application of FAS 71

TEP continues to apply FAS 71 to its regulated operations, which include the transmission and distribution portions of its business.  TEP regularly assesses whether it can continue to apply FAS 71 to these operations.  If TEP stopped applying FAS 71 to its remaining regulated operations, it would write-off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement.  Based on the regulatory asset balances, net of regulatory liabilities, at December 31, 2007, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $6 million.  While future regulatory orders and market conditions may affect cash flows, TEP’s cash flows would not be affected if TEP stopped applying FAS 71.

UNS GAS RATES AND REGULATION

2007 Rate Order

In November 2007, the ACC issued a final order in the UNS Gas rate case, approving a $5 million, or 4% base rate increase.  New rates went into effect in December 2007. UNS Gas had requested a $9 million, or 7% base rate increase to recover the costs related to serving its growing customer base.  UNS Gas also received modifications to its PGA mechanism to help address problems posed by volatile gas prices, as discussed below.

As a result of the order allowing $0.3 million of rate case costs, UNS Gas expensed $0.6 million of deferred costs in October 2007.

 
Energy Cost Adjustment Mechanism

UNS Gas’ retail rates include a PGA mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor.  All purchased gas commodity costs, including transportation, increase the PGA bank, a balancing account.  UNS Gas recovers these costs or returns amounts over-collected from/to ratepayers through a PGA mechanism.  The PGA mechanism includes the following two components:

    (1)
The PGA factor, computed monthly, is a mechanism that compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period.  Effective December 2007, the ACC Order increased the annual cap on the maximum increase in the PGA factor from $0.10 per therm to $0.15 per therm in a twelve month period.

    (2)
At any time UNS Gas’ 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 basis, UNS Gas is required to request a PGA surcredit with the goal of returning the over-collected balance to customers over a period deemed appropriate by the ACC.  Prior to December 2007 the designated under-or over-recovery trigger points were $6.2 million and $4.5 million, respectively.

The PGA surcharges in 2006 ranged between $0.05 cents per therm and $0.35 cents per therm.  In 2007, the surcharge was $0.05 cents per therm through April 2007.  In September 2007, the ACC approved a $0.04 cent per therm PGA credit, effective October 2007 through April 2008.

Based on current projections of gas prices, UNS Gas believes that the surcredit amount will still allow it to timely recover its gas costs.   However, changes in the market price for gas, sales volumes and surcharge amount could significantly change the PGA bank balance in the future.

The following table shows the balance of over-recovered purchased gas costs:

   
December 31,
  
   
2007
    
2006
  
   
-Millions of Dollars-
  
(Over) Recovered Purchased Gas Costs – Regulatory Basis as Billed to Customers
   $ (3 )   $ (2 )
Estimated Purchased Gas Costs Recovered through Accrued Unbilled Revenues
     (10 )     (9 )
(Over) Recovered Purchased Gas Costs (PGA) Included as a Current Liability
   $ (13 )   $ (11 )

2008 General Rate Case Filing

In February 2008, UNS Gas filed a general rate case (on a cost of service basis) with the ACC requesting a total increase of 7% to cover a revenue deficiency of $10 million.

Other Regulatory Assets and Liabilities

In addition to the Under(Over) Recovered Purchased Power Costs, UNS Gas has the following Regulatory Assets and Liabilities:
 
 
December 31,
 
2007
  
 2006
 
-Millions of Dollars-
Other Regulatory Assets
              
Pension Assets
   $ 1     $ 1
Other Regulatory Assets
     1       1
Total Other Regulatory Assets
     2       2
Other Regulatory Liabilities
                
Net Cost of Removal for Interim Retirements
   $ 17     $ 4
 
 
Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

 
·
Pension Assets were recorded based on past regulatory actions.  UNS Gas expects to recover in rates the UNS Gas portion of the underfunded pension plan for UNS Gas employees.  UNS Gas does not earn a return on these costs.
 
·
Other Regulatory assets relate primarily to rate case costs and its low income assistance program.  The rate case deferrals were authorized by the ACC and are included in rate base and consequently earn a return. The recovery period is 3 years.

Regulatory liabilities represent items that UNS Gas expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

 
·
Net cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations. These are amounts collected through revenue for the net cost of removal of interim retirements for which removal costs have not yet been expended.   In December 2007, to comply with the November 2007 ACC final order, UNS Gas reclassified $12 million of Net cost of Removal for Interim Retirements from Accumulated Depreciation to Regulatory Liability.

Income Statement Impact of Applying FAS 71

If UNS Gas had not applied FAS 71, net income would have been $9 million higher in 2007 and $11 million higher in 2006 as UNS Gas would have been able to recognize over-recovered gas costs as a credit to the income statement rather than record a regulatory liability.  In 2005, net income would have been $2 million lower had UNS Gas not been able to defer under-recovered gas costs as a regulatory asset.

Future Implications of Discontinuing Application of FAS 71

UNS Gas regulatory liabilities exceeded its regulatory assets by $29 million at December 31, 2007 and $13 million at December 31, 2006. UNS Gas regularly assesses whether it can continue to apply FAS 71.  If UNS Gas stopped applying FAS 71 to its regulated operations, UNS Gas would write-off the related balance of its regulatory assets as an expense and write-off its regulatory liabilities as income on its income statement.  Based on the regulatory asset and liability balances, if UNS Gas had stopped applying FAS 71 to its regulated operations, UNS Gas would have recorded an extraordinary after-tax gain of $17 million at December 31, 2007.  Discontinuing application of FAS 71 would not affect UNS Gas cash flows.


UNS ELECTRIC RATES AND REGULATION

Energy Cost Adjustment Mechanism

UNS Electric’s retail rates include a PPFAC, which allows for a separate surcharge or surcredit to the base rate for delivered purchased power to collect or return under- or over-recovery of costs.  The ACC approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWMT.

General Rate Case Filing

In December 2006, UNS Electric filed a general rate case (on a cost of service basis) with the ACC requesting a total rate increase of 5.5% to cover a revenue deficiency of $9 million.  The increase is necessary because of the growth in UNS Electric’s service territory and the related increase in capital expenditures and operating costs.

UNS Electric expects the ACC to rule on its rate case in early 2008.

UNS Electric also requested that a new PPFAC mechanism would take effect when the current power supply agreement with PWMT expires in May 2008.

 
Regulatory Assets and Liabilities

UNS Electric’s regulatory assets and liabilities were as follows:
 
 
December 31,
 
2007
  
2006
 
 -Millions of Dollars-
 Current Regulatory Assets            
Derivatives
   $ 1     $ -  
                 
Other Regulatory Assets
                
   Rate Case Costs
     1       -  
Pension Assets
     1       1  
Total Other Regulatory Assets
   $ 2     $ 1  
                 
Current Regulatory Liabilities
                
   Derivatives
   $ 3     $ -  
Deferred Environmental Portfolio Surcharge
     -       2  
Other Regulatory Liabilities
                
Over Recovered Purchase Power Costs
     9       6  
   Derivatives
     7       3  
Net Cost of Removal for Interim Retirements
     2       2  
Total Regulatory Liabilities
   $ 21     $ 13  

Regulatory assets are either being collected in rates or are expected to be collected through rates in a future period, as described below:

 
·
Pension Assets were recorded in 2006 as based on past regulatory actions, UNS Electric expects to recover in rates the UNS Electric portion of the underfunded pension plan for UNS Electric employees.  UNS Electric does not earn a return on these costs.
 
·
UNS Electric has requested recovery of costs associated with its 2006 rate case filing.  Historically, the ACC has allowed recovery of rate case costs.  The recovery period will be determined when the ACC rules on UNS Electric’s rate case in 2008.  UNS Electric does not earn a return on these costs.

Regulatory liabilities represent items that UNS Electric expects to pay to customers through billing reductions in future periods or use for the purpose for which they were collected from customers, as described below:

 
·
Deferred Environmental Friendly Portfolio Surcharge represents amounts the ACC has authorized UNS Electric to collect, through customer billings, for environmental improvement projects.  The amounts are deferred until they are spent on their intended use.
 
·
UNS Electric defers differences between purchased energy costs and the recovery of such costs in revenues.  Future billings are adjusted for such deferrals through use of a Purchased Power and Fuel Adjustment Clause (PPFAC) approved by the ACC.  The PPFAC allows for a revenue surcharge or surcredit (that adjusts the customer’s rate for delivered purchased power) to collect or return under-or over-recovery of costs.
 
·
In December 2006, the ACC granted UNS Electric an Accounting Order authorizing regulatory deferral of unrealized gains and losses on derivative forward purchase contracts that are required to be marked-to-market under GAAP.
 
·
Net cost of Removal for Interim Retirements represents an estimate of future asset retirement obligations.

Income Statement Impact of Applying FAS 71

If UNS Electric had not applied FAS 71, net income would have been less than $1 million higher in 2007, $3 million higher in 2006, and $1 million higher in 2005, as UNS Electric would have been able to recognize over-recovered purchased power costs as a credit to the income statement rather than record an increase to regulatory liabilities.
 

Future Implications of Discontinuing Application of FAS 71

UNS Electric regularly assesses whether it can continue to apply FAS 71 to its operations.  If UNS Electric stopped applying FAS 71 to its regulated operations, it would write-off the related balances of its regulatory assets as an expense and would write-off its regulatory liabilities as income on its income statement.  Based on the regulatory asset and liability balances, if UNS Electric had stopped applying FAS 71 to its regulated operations, it would have recorded an extraordinary after-tax gain of $11 million at December 31, 2007.  Discontinuing application of FAS 71 would not affect UNS Electric’s cash flows.


NOTE 3.  SEGMENT AND RELATED INFORMATION

We have three reportable segments that are determined based on the way we organize our operations and evaluate performance:

   (1)
TEP, a vertically integrated electric utility business, is our largest subsidiary.
   (2)
UNS Gas is a regulated gas distribution utility business.
   (3)
UNS Electric is a regulated electric distribution utility business.

The UniSource Energy and UES holding companies, Millennium, and UED are included in All Other.  All Other also includes the discontinued operations of Global Solar.  As discussed in Note 15, at March 31, 2006, Millennium sold all of the common stock of Global Solar and the results of operations of Global Solar are reported as discontinued operations for all periods presented.

Significant revenues and expenses included in All Other include the following:

 
·
In 2006, Millennium recorded an after-tax loss of approximately $2 million related to the discontinued operations and disposal of Global Solar.
 
·
In 2005, Millennium recorded an after-tax gain of $2 million related to a gain on the sale of an investment by one of its investees.  Millennium also recognized an impairment loss of $1 million in 2005 related to the sale of one of its investments in January 2006.

Reconciling adjustments consist of the elimination of intercompany activity and balances:

 
·
Intercompany activity between UNS and UED.
 
·
SES, a Millennium subsidiary, recorded revenue from transactions with TEP, UNS Electric and UNS Gas of $15 million in 2007, $15 million in 2006 and $13 million in 2005.  The related expense is reported in Other Operations and Maintenance expense on the consolidated income statement.  Millennium’s revenue and the related expense are eliminated in UniSource Energy consolidation.
 
·
TEP recorded revenue from providing support services to UNS Gas and UNS Electric of $7 million in 2007, $2 million in 2006 and $2 million in 2005.  UNS Gas’ and Electric’s related expense is reported in Other Operations and Maintenance expense on its income statement.  TEP’s revenue and the related expenses in UNS Gas and UNS Electric are eliminated in UniSource Energy consolidation.
 
·
Other significant reconciling adjustments include the elimination of investments in subsidiaries held by UniSource Energy, the intercompany note between UniSource Energy and TEP, the related interest income and expense on the note and reclassifications of deferred tax assets and liabilities.  UniSource Energy repaid the intercompany note in 2005.  See Note 7.

Our portion of the net income (loss) of the entities in which TEP and Millennium own a voting interest or have the ability to exercise significant influence is shown below in Net Income (Loss) from Equity Method Entities.


We disclose selected financial data for our reportable segments in the following tables:
 
 
Reportable Segments
      
2007
TEP
UNS Gas
UNS Electric
All
Other
Reconciling Adjustments
UniSource Energy
Income Statement
-Millions of Dollars-
Operating Revenues – External
 $ 1,064
 $ 151
 $ 169
 $ (3)
 $    -
  $1,381
Operating Revenues – Intersegment
  7
  -
  -
  15
  (22)
  -
Depreciation and Amortization
  120
  8
  13
  -
  -
  141
Amortization of Transition Recovery     Asset
  78
  -
  -
  -
  -
  78
Interest Income
  16
  1
  -
  2
  -
  19
Interest Expense
  117
  7
  6
  8
  -
  138
Income Tax Expense (Benefit)
  36
  3
  3
  (3)
  -
  39
Net Income (Loss)
  53
  4
  5
  (4)
  -
  58
Cash Flow Statement
            
Net Cash Flows – Operating Activities
  264
  28
  22
  9
  -
  323
Net Cash Flows – Investing Activities –    Capital Expenditures
  (162)
  (23)
  (38)
  (22)
  -
  (245)
Net Cash Flows – Investing Activities –    Investments in and Loans to Equity    Method Entities
  -
  -
  -
  (1)
  -
  (1)
Net Cash Flows – Investing Activities –    Other
  26
  1
  1
  1
  -
  29
Net Cash Flows – Financing Activities
  (120)
  (6)
  12
  (3)
  (2)
  (119)
Balance Sheet
            
Total Assets
  2,573
  276
  226
  1,077
  (966)
  3,186
Investments in Equity Method Entities
  3
  -
  -
  28
  -
      31
 
 
 
Reportable Segments
      
2006
TEP
UNS Gas
UNS Electric
All
Other
Reconciling Adjustments
UniSource Energy
Income Statement
-Millions of Dollars-
Operating Revenues – External
 $ 987
 $ 162
 $ 160
 $ (1)
 $    -
  $1,308
Operating Revenues – Intersegment
  2
  -
  -
  15
  (17)
  -
Depreciation and Amortization
  112
  7
  11
  1
  -
  131
Amortization of Transition Recovery    Asset
  66
  -
  -
  -
  -
  66
Interest Income
  16
  -
  -
  3
  -
  19
Interest Expense
  127
  7
  5
  13
  -
  152
Income Tax Expense (Benefit)
  42
  3
  3
  (4)
  -
  44
Discontinued Operations – Net of Tax
  -
  -
  -
  (2)
  -
  (2)
Net Income (Loss)
  67
  4
  5
  (9)
  -
  67
Cash Flow Statement
            
Net Cash Flows – Operating Activities
  227
  32
  14
  10
  -
  283
Net Cash Flows – Investing Activities –    Capital Expenditures
  (156)
  (23)
  (39)
  (20)
  -
  (238)
Net Cash Flows – Investing Activities –    Investments in and Loans to Equity    Method Entities
  -
  -
  -
  (5)
  -
  (5)
Net Cash Flows – Investing Activities –    Other
  (26)
  -
  -
  23
  -
  (3)
Net Cash Flows – Financing Activities
  (79)
  (4)
  22
  (14)
  (2)
  (77)
Balance Sheet
            
Total Assets
  2,623
  253
  195
  1038
  (922)
  3,187
Investments in Equity Method Entities
  3
  -
  -
27
  -
                     30
 
 
 
Reportable Segments
      
2005
TEP
UNS Gas
UNS Electric
All
Other
Reconciling Adjustments
UniSource Energy
Income Statement
            
Operating Revenues – External
 $ 935
 $ 138
 $ 150
 $ 1
 $    -
 $ 1,224
Operating Revenues – Intersegment
  2
  -
  -
  13
  (15)
  -
Depreciation and Amortization
  115
  7
  10
  1
  -
  133
Amortization of Transition Recovery    Asset
  56
  -
  -
  -
  -
  56
Interest Income
  21
  -
  -
  -
  (1)
  20
Net Loss from Equity Method Entities
  -
  -
  -
  2
  -
  2
Interest Expense
  140
  6
  5
  11
  (2)
  160
Income Tax Expense (Benefit)
  34
  3
  3
  (2)
  -
  38
Discontinued Operations – Net of Tax
  -
  -
  -
  (5)
  -
  (5)
Net Income (Loss)
  48
  5
  5
  (12)
  -
  46
Cash Flow Statement
            
Net Cash Flows – Operating Activities
  243
  14
  21
  (4)
  -
  274
Net Cash Flows – Investing Activities –    Capital Expenditures
  (150)
  (23)
  (30)
  -
  -
  (203)
Net Cash Flows – Investing Activities –    Investments in and Loans to Equity    Method Entities
  -
  -
  -
  (5)
  -
  (5)
Net Cash Flows – Investing Activities –      Other
  21
  -
  -
  17
  -
  38
Net Cash Flows – Financing Activities
  (174)
  15
  8
  39
  (1)
  (113)
Balance Sheet
            
Total Assets
  2,617
  233
  161
  1,043
  (874)
  3,180
Investments in Equity Method Entities
  2
  -
  -
  25
  -
  27

NOTE 4.  ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING ACTIVITIES

TEP INTEREST RATE SWAP

In June 2006, TEP entered into an interest rate swap to reduce the risk of unfavorable changes in variable interest rates related to changes in LIBOR.  The swap has the effect of converting approximately $36 million of variable rate lease payments for the Springerville Common Lease to a fixed rate through January 1, 2020.  The swap is designated as a cash flow hedge for accounting purposes.  Because the changes in interest payments, resulting from changes in LIBOR, were completely offset by the interest rate swap in 2007, there was no ineffectiveness recorded in earnings.

TEP FUEL AND POWER TRANSACTIONS

TEP enters into forward contracts to purchase or sell a specified amount of capacity or energy at a specified price over a given period of time, within established limits to take advantage of favorable market opportunities and reduce exposure to energy price risk resulting from generation and procurement of power.  In general, TEP enters into forward power purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods).  TEP enters into forward power sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost.  In addition, TEP has natural gas supply agreements under which it purchases all of its gas requirements at spot market prices.  In an effort to minimize price risk on these purchases, TEP enters into price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.

The settlement of forward power purchase and sales contracts that do not result in physical delivery are recorded net as a component of Electric Wholesale Sales in TEP’s income statement.  During 2007, approximately $89 million in sales were netted against approximately $90 million in purchases.  During 2006, $79 million in sales were netted against $77 million in purchases and in 2005, $15 million in sales were netted against approximately $16 million in purchases.

The net unrealized gains and losses from TEP’s derivative activities reported in Other Comprehensive Income were as follows:
 
 
   
Years Ended December 31,
  
Cash Flow Hedges – Gain (Loss) on:
  
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
 Forward Power Sales
   $ -     $ 8     $ (1 )
 Gas Price Swaps
     (6 )     (18 )     18  
 Interest Rate Swap
     (1 )     (2 )     -  
      Pre-Tax Unrealized (Loss) Gain on Cash Flow  Hedges
   $ (7 )   $ (12 )   $ 17  
                         
After Tax (Loss) Gain on Cash Flow Hedges Recorded in OCI
   $ (4 )   $ (7 )   $ 10  
                         
Reclassification of Unrealized Loss/(Gain) on Cash Flow    Hedges to Net Income
   $ 2     $ -     $ (4 )

At December 31, 2007, the settlement dates of contracts accounted for as derivatives extended through the fourth quarter of 2010.

TEP concluded, following an assessment at the inception of a hedge transaction and on an ongoing basis that its derivatives, designated as cash flow hedges, have been highly effective in offsetting changes in the cash flows of hedged items and that those derivatives are expected to remain highly effective in future periods.

The net unrealized gains and losses from TEP’s derivative activities reported in earnings were as follows:

   
Years Ended December 31,
  
Mark-to-Market Transactions Gain (Loss):
  
2007
    
2006
    
2005
  
Forward Power Sales Recorded in Wholesale Sales
   $ (8 )   $ 7     $ 1  
Forward Power Purchases Recorded in Wholesale Sales
     8       (6 )     -  
Forward Power Purchases Recorded in Purchased Energy
     -       -       (2 )
      Pre-Tax Gain (Loss) Recorded in Earnings
   $ -     $ 1     $ (1 )
                         

The fair value of TEP’s derivative assets and liabilities were recorded as follows:

   
December 31,
    
December 31,
  
   
2007
    
2006
  
   
Mark-to-Market
    
Cash Flow Hedges
    
Mark-to-Market
    
Cash Flow Hedges
  
   
-Millions of Dollars-
  
Trading Assets
   $ 1     $ 1     $ 9     $ 6  
Trading Liabilities
     (1 )     (2 )     (9 )     (3 )
      Net Current Derivative Assets
   $ -     $ (1 )   $ -     $ 3  
                                 
Other Assets
   $ -     $ -     $ -     $ -  
Other Liabilities
     -       (3 )     -       (3 )
      Net Noncurrent Derivative Assets
   $ -     $ (3 )   $ -     $ (3 )

Amounts presented as Current, are expected to be reclassified into earnings within the next twelve months.

UNS GAS SUPPLY TRANSACTIONS

UNS Gas purchases substantially all of its gas requirements at market prices under a natural gas supply and management agreement with BP Energy Company (BP).  The contract terms allow UNS Gas to lock in fixed prices on a portion of its expected forward gas purchases from BP.  This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% of the expected monthly gas consumption prior to entering into the month.  These forward purchases, as well as the main gas supply contract, meet the definition of normal purchases and therefore are not required to be marked-to-market.   In February 2008, UNS Gas gave BP notice of its intention to terminate this
 
 
agreement.  Beginning in September 2008, UNS Gas will directly manage its gas supply and transportation contracts.

In December 2007, UNS Gas entered into a financial gas swap to assist in achieving price stabilization.  This financial gas swap agreement is designated as a cash flow hedge for accounting purposes.  Accordingly, unrealized gains and losses resulting from the change in fair value are recorded in Other Comprehensive Income.  There were no gains or losses recognized in Net Income related to hedge ineffectiveness. Unrealized gains and losses will be reclassified into earnings when the hedged transactions settle or terminate.

The unrealized gain recorded in Other Comprehensive Income and the fair value of UNS Gas’ derivative asset is less than $0.1 million as of December 31, 2007.  UNS Gas did not have any derivative assets in 2006.

At December 31, 2007, the settlement date of the contract accounted for as a cash flow hedge extended through the first quarter of 2011.

UNS Gas has $0.1 million of net current Derivative Assets that are expected to be reclassified into earnings within the next twelve months.

UNS ELECTRIC POWER SUPPLY TRANSACTIONS

UNS Electric entered into forward contracts, for periods of one to five years, beginning in June 2008, to purchase energy to supply retail customer needs for the period after the full-requirements supply agreement with PWMT expires in May 2008.  Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices.  UNS Electric has hedged a portion of its total natural gas exposure from gas-indexed purchase power agreements that begin in June 2008 with fixed price contracts.  In addition, UNS Electric began hedging a portion of its anticipated natural gas exposure from plant fuel for the period June 2008 and beyond.

The fair value of the derivative assets and liabilities was a $9 million net asset at December 31, 2007 and a $3 million net asset at December 31, 2006.  Effective December 31, 2006, UNS Electric received an accounting order from the ACC which allows UNS Electric to defer the unrealized gains and losses on the balance sheet as a regulatory asset or liability.  UNS Electric recorded net unrealized gains in Deferred Credits and Other Liabilities - Other Regulatory Liabilities of $9 million in 2007 and $3 million in 2006.

At December 31, 2007, the settlement dates of contracts accounted for as derivatives extended through the fourth quarter of 2013.  UNS Electric has $3 million of net current Derivative Assets that are expected to be reclassified into earnings within the next twelve months.

MEG TRADING TRANSACTIONS

MEG, a wholly-owned subsidiary of Millennium, entered into swap agreements, options and forward contracts relating to Emission Allowances.  In December 2007, MEG settled its outstanding trading positions. MEG is not expected to have any further activities and is in the process of being dissolved.

MEG had a net loss from trading activities of less than $1 million in 2007, 2006, and 2005.

MEG had no derivative assets or liabilities at December 31, 2007.  At December 31, 2006, the fair value of MEG’s derivative current assets and current liabilities were $11 million and $5 million, respectively.

CONCENTRATION OF CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations.  TEP, UNS Gas and UNS Electric enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties.  In addition, volatile energy prices can create significant credit exposure from energy market receivables and mark-to-market valuations.  As of December 31, 2007, TEP had total credit exposure of $20 million related to its wholesale marketing and gas hedging activities, of which two counterparties individually composed greater than 10% of the total credit exposure.  As of December 31, 2007, UNS Gas had a total credit exposure related to its forward gas purchase contracts of less than $1 million, primarily related to its relationship with one counterparty.  As of December 31, 2007, UNS Electric had a total credit exposure related to its forward power purchase contracts and gas hedging activities of $7 million, primarily related to its relationship with four counterparties.  TEP, UNS
 
 
Gas and UNS Electric calculated counterparty credit exposure by adding any outstanding receivables (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts.


NOTE 5.  COMMITMENTS AND CONTINGENCIES

TEP COMMITMENTS

Purchase and Transportation Commitments

TEP has several long-term coal purchase and transportation contracts with various expiration dates from 2008 through 2020.  Amounts paid under these contracts depend on the number of tons of coal purchased and transported.  Some of these contracts (i) include a price adjustment clause that will affect the future cost of coal and (ii) require TEP to pay a take-or-pay charge or liquidated damages if certain minimum quantities of coal are not purchased and/or transported.  TEP expects to spend more to meet its fuel requirements than the minimum purchase obligations outlined below.  TEP made payments under these contracts of $203 million in 2007, $184 million in 2006 and $175 million in 2005.

In 2007, TEP entered into power supply agreements for 2008 and 2009 with prices indexed to natural gas prices.  TEP has estimated its minimum payments under these contracts based on natural gas prices at December 31, 2007.

TEP has natural gas transportation agreements with El Paso Natural Gas (EPNG) to fuel Sundt and TEP’s portion of the Luna facility.  The contracts expire in April 2009 and January 2009, respectively.  TEP made payments under these contracts of $6 million in 2007 and $2 million in 2006.

At December 31, 2007, TEP estimates that future minimum payments under the contracts for purchased power, coal, and gas referred to above are as follows:

   
Minimum
  
   
Purchase
  
   
Obligations
  
 
  -Millions of Dollars-
       
2008
   $ 144  
2009
     109  
2010
     84  
2011
     46  
2012
     39  
Total 2008 – 2012
     422  
Thereafter
     223  
Total
   $ 645  

Operating Leases

TEP’s aggregate operating lease expense, which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates, was $2 million in each of the years 2007 and 2006 and $1 million in 2005.  TEP estimates future minimum payments under non-cancelable operating leases will be approximately $1 million per year from 2008 to 2010.

Environmental Regulation

Federal Clean Air Act Amendments

TEP generating facilities are subject to EPA limits on the amount of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions into the atmosphere.   TEP capitalized $7 million in 2007 and $1 million in each of 2006 and 2005 in construction costs to comply with environmental requirements and expects to capitalize $60 million in 2008 and $16 million in 2009, including TEP’s share of new pollution control equipment being installed at San Juan described below.  In addition, TEP recorded operating expenses of $10 million in 2007 and 2006 and $11 million in 2005 related to environmental compliance.  TEP expects environmental expenses to be $11 million in 2008.
 
 
As a result of a 2005 settlement agreement between PNM, environmental activist groups, and the New Mexico Environment Department (PNM Consent Decree), the co-owners of San Juan are installing new pollution control equipment at the generating station to reduce mercury, particulate matter, NOx, and SO2 emissions.  TEP owns 50% of San Juan Units 1 and 2.  The PNM Consent Decree includes stipulated penalties for non-compliance with specified emissions limits at San Juan.  In 2007, TEP’s share of potential stipulated penalties at San Juan was $2 million.  TEP’s share of stipulated penalties in 2006 was less than $0.5 million.  TEP expects its share of stipulated penalties at San Juan to be approximately $1 million in 2008.  The new pollution control equipment is expected to be installed at the generating units that TEP jointly owns in 2008 and early 2009 and is designed to remedy all emission violations.

In 1993, the EPA allocated TEP’s generating units SO2 Emission Allowances based on past operational history.  Beginning in 2000, TEP’s generating units were required to hold Emission Allowances equal to the level of emissions in the compliance year or pay penalties and offset excess emissions in future years.  To date, TEP has had sufficient Emission Allowances to comply with the SO2 regulations.

Mercury Emissions

In 2005, the EPA adopted regulations relating to mercury emissions requiring states to develop rules for implementing federal requirements.  Arizona adopted its mercury emission rules in 2007.  Based on these rules, emission control may be required at Springerville and Sundt by 2013.  TEP does not expect the capital costs to exceed $6 million at these generating stations.  TEP is also monitoring the New Mexico and Navajo Nation mercury emission regulations affecting plants in which TEP has an ownership share. TEP does not anticipate that additional controls will be required at any of these remote generating stations prior to 2015 in order to meet the existing state or federal limits.  As stipulated in the PNM Consent Decree described above, the co-owners of San Juan are installing new pollution control equipment at the generating station to reduce mercury emissions.  Mercury emissions controls for San Juan Units 1 and 2 must be installed by December 31, 2009.

A recent federal court decision may require revisions to the existing mercury emissions regulations.  TEP will continue to review any changes to state and federal regulations required as a result of the recent decision.  TEP will comply with any revised regulations.

Greenhouse Gas Emissions

Based on competing proposals to regulate greenhouse gas emissions by federal, state, and local regulatory bodies and uncertainty in the regulatory process, the scope of such regulations and their affect on our operations cannot be determined.

Regional Haze

The EPA's Regional Haze Rule requires states to develop plans to restore visibility in various areas to their natural conditions by 2064.  State plans could require pollution control upgrades at some of TEP's power plants.  The level of control required, if any, will not be known until the state plans are submitted and approved by the EPA.  State plans are expected to be submitted to the EPA during 2008, and approved by the EPA during 2009.  If required, controls would need to be in place by 2013 or later.

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.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson to Nogales, Arizona.  This project was initiated in response to an order by the ACC to improve reliability to UNS Electric’s retail customers in Nogales, Arizona.

In 2002, the ACC approved the location and construction of the proposed 345-kV line along the Western Corridor route subject to a number of conditions, including obtaining all required permits from state and federal agencies.  TEP is currently seeking approvals for the project from the Department of Energy (DOE), the US Forest Service, the Bureau of Land Management, and the International Boundary and Water Commission.
 
 
The DOE has completed a Final Environmental Impact Statement (EIS) for the project in which it would accept any of the routes in the EIS, but the U.S. Forest Service has indicated the Central route as its preferred alternative, rather than the Western Corridor route.

Based on the alternative proposals and passage of time since it approved the location of the line, the ACC, in January 2005, ordered TEP to review the status of electric service reliability in Nogales, Arizona and the need for the 345-kV line.  The ACC also indicated that it would review any new information regarding the location of the proposed transmission line.  In December 2005, an Administrative Law Judge (ALJ) for the ACC issued a recommended opinion and order reaffirming the ACC’s original position requiring the construction of the Tucson to Nogales transmission line.  After a hearing on the issue, the ACC directed the ALJ to amend the recommendation to direct the Line Siting Committee of the ACC to gather facts related to options for improving service reliability in Nogales, Arizona.

If TEP does not receive the required approvals it may need to expense a portion of the $9 million of costs that have been capitalized related to the project.

TEP Guarantee Home Program

TEP provides incentives to new home builders to construct TEP Guarantee Homes that meet the highest construction and energy-efficiency standards available.  TEP made builder incentive payments averaging $1 million in each of 2007, 2006, and 2005.  TEP expects to make payments under this program totaling $2 million in 2008 and 2009.

UNS GAS COMMITMENTS

UNS Gas has firm transportation agreements with El Paso Natural Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity sufficient to meet its load requirements.  The EPNG contract expires in August 2011, and the Transwestern contracts expire in February 2012, February 2020, and June 2023.  UNS Gas made payments under the EPNG and Transwestern contracts of $13 million in 2007, $10 million in 2006 and $7 million in 2005.
 
UNS Gas purchases substantially all of its gas requirements at market prices under a natural gas supply and management agreement with BP Energy Company (BP).  See Note 4.

At December 31, 2007, UNS Gas estimates its future minimum payments under these contracts to be:
 
   
Minimum
  
   
Purchase
  
   
Obligations
  
 
  -Millions of Dollars-
       
2008
   $ 56  
2009
     38  
2010
     25  
2011
     11  
2012
     3  
Total 2008 – 2012
     133  
Thereafter
     25  
Total
   $ 158  
 
See Note 7 for a description of the UNS Gas and UNS Electric long-term debt.
 
UNS ELECTRIC COMMITMENTS

UNS Electric imports the power it purchases over the Western Area Power Administration’s (WAPA) transmission lines.  UNS Electric’s transmission capacity agreements with WAPA provide for annual rate adjustments and expire in February 2008, June 2011, and May 2017.  UNS Electric made payments under these contracts of $7 million in 2007, $8 million in 2006, and $7 million in 2005.

UNS Electric’s all requirements contract expires in 2008.  During 2006 and 2007, UNS Electric entered into agreements to purchase power beginning in 2008 through 2013.  The contracts are valued based on either fixed prices or indexed to natural gas prices at December 31, 2007.

At December 31, 2007, UNS Electric estimates its future minimum payments under these contracts to be:
 
 
   
Minimum
  
   
Purchase
  
   
Obligations
  
    -Millions of Dollars-
       
2008
   $ 62  
2009
     70  
2010
     42  
2011
     17  
2012
     8  
Total 2008 – 2012
     199  
Thereafter
     8  
Total
   $ 207  

UNS GAS and UNS ELECTRIC OPERATING LEASES

UNS Gas and UNS Electric’s combined operating lease expense which is primarily for office facilities and computer equipment, with varying terms, provisions, and expiration dates was $1 million in each of the years 2007, 2006 and 2005.  UNS Gas and UNS Electric’s estimated future minimum payments under non-cancelable operating leases are approximately $1 million per year from 2008 to 2011 and $2 million thereafter.

MILLENNIUM COMMITMENTS

Millennium has a remaining obligation to fund Valley Ventures III and Valley Ventures III Annex for capital and operations up to an additional $1 million over the next two years.

UED COMMITMENTS

In 2006, UED purchased two electric generating turbines for $17 million.  The turbines are part of a 90 MW BMGS power project currently under construction in Kingman, Arizona in UNS Electric’s service area.  Construction began during the third quarter of 2007 with an estimated completion date of May 2008.  Including installation and refurbishment of the turbines, the total cost of the project for UED is expected to be between $60 million and $65 million, of which $15 million to $20 million remains to be paid as construction proceeds to completion.

UED believes it will fully recover its costs through the sale of BMGS to UNS Electric or to a third party or through the sale of the output of BMGS in the wholesale energy market.

TEP CONTINGENCIES

Claims Related to San Juan Coal Company

San Juan Coal Company, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine.  Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine.  These gas producers allege that San Juan Coal Company’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover.  San Juan Coal Company has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant shutting down the well.  These settlements, however, do not resolve all potential claims by gas producers in the underground mine area.  TEP cannot estimate the outcome of any future claims by these gas producers on the cost of coal at San Juan.

Litigation and Claims Related to Navajo Generating Station

In 2004, Peabody Western Coal Company (Peabody), the coal supplier to the Navajo Generating Station, filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs and breach of the coal supply agreement. Because TEP owns 7.5% of the Navajo Generating Station, its share of the current claimed damages would be approximately $35 million.  TEP believes these claims are without merit and intends to continue to contest them.  TEP has not recorded a liability for these amounts.
 
 
Postretirement and Pension Benefit Costs at Navajo Generating Station

Peabody contends that the Navajo Generating Station participants are responsible under the coal supply agreements for postretirement benefit costs payable to the coal supplier’s employees.  In 1996, SRP filed a lawsuit in Maricopa County Superior Court on behalf of the participants at Navajo Generating Station, including TEP, seeking declaratory judgment that the participants are not responsible for these costs.  The Navajo Generating Station participants and Peabody continue to discuss a potential settlement.  We expect resolution of this matter in 2008.

Environmental Reclamation at Remote Generating Stations

TEP currently pays on-going reclamation costs related to the coal mines which supply the remote generating stations, and it is probable that TEP will have to pay a portion of final reclamation costs upon mine closure.  When a reasonable estimate of final reclamation costs is available, the liability is recognized as a cost of coal over the remaining term of the corresponding coal supply agreement.  At December 31, 2007, TEP has recorded a liability of $4 million based on our $13 million obligation at the expiration dates of the coal supply agreements in 2011 through 2017.

Amounts recorded for final reclamation are subject to various assumptions, such as estimating the costs of reclamation, estimating when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities.  As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreement term.  TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition occurs over the remaining terms of its coal supply agreements.

TEP Wholesale Accounts Receivable and Allowances

TEP’s Accounts Receivable from Electric Wholesale Sales, includes $16 million of receivables at December 31, 2007 and December 31, 2006 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000.  TEP’s Allowance for Doubtful Accounts on the balance sheet includes $13 million at December 31, 2007 and December 31, 2006 related to these sales.  There are several outstanding legal issues, complaints and lawsuits concerning the California energy crisis related to the FERC, wholesale power suppliers, Southern California Edison Company, Pacific Gas and Electric Company, the CPX and the CISO.  We cannot predict the outcome of these issues or lawsuits.  We believe, however, that TEP is adequately reserved for its transactions with the CPX and the CISO.

GUARANTEES AND INDEMNITIES

In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries.  We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis.  The most significant of these guarantees are:

 
·
UES’ guarantee of senior unsecured notes issued in 2003 by UNS Gas ($100 million) and UNS Electric ($60 million),
 
·
UES’ guarantee of a $60 million unsecured revolving credit agreement for UNS Gas and UNS Electric,
 
·
UniSource Energy’s guarantee of approximately $2 million in building lease payments for UNS Gas.  In January 2008, UniSource Energy was released from a $3 million guarantee on behalf of UNS Gas.

To the extent liabilities exist under these contracts, the liabilities are included in our consolidated balance sheets.

In addition, we have indemnified the purchasers of interests in certain investments from additional taxes due for years before the sale of such investments.  The terms of the indemnifications do not include a limit on potential future payments; however, we believe that we have abided by all tax laws and paid all tax obligations.  We have not made any payments under the terms of these indemnifications to date.

We believe that the likelihood UniSource Energy or UES would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.

 
NOTE 6.  UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

The following table shows Utility Plant in Service by company and major class.
 
 
December 31, 2007
 
- Millions of Dollars -
 
TEP
  
UNS
Gas
  
  UNS
Electric
  
UniSource Energy
Plant in Service:
                        
 Electric Generation Plant
   $ 1,343     $ -     $ 17     $ 1,360  
 Electric Transmission Plant
     580       -       28       608  
 Electric Distribution Plant
     985       -       143       1,128  
 Gas Distribution Plant
     -       185       -       185  
 Gas Transmission Plant
     -       18       -       18  
 General Plant
     162       12       10       184  
 Intangible Plant
     69       1       7       77  
 Electric Plant Held for Future Use
     5       1       -       6  
Total Plant in Service
   $ 3,144     $ 217     $ 205     $ 3,566  
                                 
Utility Plant under Capital Leases
   $ 701     $ -     $ 1     $ 702  
 
 
December 31, 2006
 
- Millions of Dollars -
 
TEP
  
UNS
Gas
  
  UNS
Electric
  
UniSource Energy
 
Plant in Service:
                        
 Electric Generation Plant
   $ 1,302     $ -     $ 17     $ 1,319  
 Electric Transmission Plant
     566       -       18       584  
 Electric Distribution Plant
     931       -       119       1,050  
 Gas Distribution Plant
     -       168       -       168  
 Gas Transmission Plant
     -       18       -       18  
 General Plant
     154       16       10       180  
 Intangible Plant
     78       1       7       86  
 Electric Plant Held for Future Use
     4       1       -       5  
Total Plant in Service
   $ 3,035     $ 204     $ 171     $ 3,410  
                                 
Utility Plant under Capital Leases
   $ 701     $ -     $ 1     $ 702  

Intangible Plant primarily represents computer software costs.  TEP’s unamortized computer software costs were $34 million as of December 31, 2007 and $32 million as of December 31, 2006.  UNS Gas and UNS Electric had no unamortized computer software costs as of December 31, 2007 and as of December 31, 2006.

All TEP Utility Plant under Capital Leases is used in TEP’s generation operations.

The following table reconciles the gross investment in utility plant to net investment in utility plant, segregated between regulated and non-regulated utility plant.

December 31, 2007
   
TEP
    
UNS
Gas
    
UNS
Electric
    
UniSource Energy
Consolidated
  
   
T&D
    
Gen*
    
Total
Plant
    
Total
Plant
    
Total
Plant
    
All Other
    
TEP
Gen*
    
Total
Plant
  
   
-Millions of Dollars-
  
Gross Plant in Service
   $ 1,801     $ 1,343     $ 3,144     $ 217     $ 205     $ 2,223     $ 1,343     $ 3,566  
Less Accumulated
   Depreciation and
   Amortization
       836       654       1,490       5       39       880       654       1,534  
Net Plant in Service
   $ 965     $ 689     $ 1,654     $ 212     $ 166     $ 1,343     $ 689     $ 2,031  
 
 
         
 
December 31, 2006
  
   
TEP
    
UNS
Gas
    
UNS
Electric
    
UniSource Energy
Consolidated
  
   
T&D
    
Gen*
    
Total
Plant
    
Total
Plant
    
Total
Plant
    
All Other
    
TEP
Gen*
    
Total
Plant
  
   
-Millions of Dollars-
  
Gross Plant in Service
   $ 1,733     $ 1,302     $ 3,035     $ 204     $ 171     $ 2,108     $ 1,302     $ 3,410  
Less Accumulated
   Depreciation and
   Amortization
       808       638       1,446       16       31       855       638       1,493  
Net Plant in Service
   $ 925     $ 664     $ 1,589     $ 188     $ 140     $ 1,253     $ 664     $ 1,917  

*The ACC does not set rates on TEP’s generation operations on a cost-of-service basis, and; therefore, these operations are not accounted for under the provisions of FAS 71.  Rates for the remaining utility operations appearing in this table are set by the ACC on a cost-of-service basis, and are accounted for under the provisions of FAS 71.  The category T&D includes all transmission and distribution Plant in Service.  The category Gen includes the generation assets.

The depreciable lives currently used by TEP are as follows:

Major Class of Utility Plant in Service
Depreciable Lives
   
Electric Generation Plant
20-71 years
Electric Transmission Plant
10-50 years
Electric Distribution Plant
24-60 years
General Plant
5-45 years
Intangible Plant
3-10 years

During the second quarter 2005, the estimate for San Juan’s economic useful life changed.  As a result of the analysis performed, TEP lengthened the estimated useful life of San Juan from 40 to 60 years beginning April 1, 2005.  This change in the estimated useful life reduces annual depreciation expense by $6 million.

See TEP Utility Plant in Note 1 and TEP Capital Lease Obligations in Note 7.

The depreciable lives currently used by UNS Gas and UNS Electric are as follows:

Major Class of Utility Plant in Service
Depreciable Lives
   
Electric Generation Plant
23-40 years
Electric Transmission Plant
11-45 years
Electric Distribution Plant
14-26 years
Gas Distribution Plant
17-48 years
Gas Transmission Plant
37-55 years
General Plant
3-33 years

JOINTLY-OWNED FACILITIES

At December 31, 2007, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:
 
     
Percent Owned by TEP
      
Plant
in
Service *
      
Construction Work in
Progress
      
Accumulated
Depreciation
  
   
-Millions of Dollars-
San Juan Units 1 and 2
    
50.0%
     $ 299     $ 19     $ 215  
Navajo Station Units 1, 2 and 3
    
7.5
       116       1       70  
Four Corners Units 4 and 5
    
7.0
       83       4       66  
Transmission Facilities
     7.5 to 95.0     370       -       229  
Luna Energy Facility
    
33.3
       48       1       2  
Total
           $ 916     $ 25     $ 582  

*Included in Utility Plant shown above.
 
 
TEP has financed or provided funds for the above facilities and TEP’s share of their operating expenses is reflected in the income statements.  See Note 5 for commitments related to TEP’s jointly-owned facilities.


NOTE 7.  DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

Long-term debt matures more than one year from the date of the financial statements.  We summarize UniSource Energy and TEP’s long-term debt in the statements of capitalization.

UNISOURCE ENERGY DEBT

Convertible Senior Notes

In March 2005, UniSource Energy issued $150 million of 4.50% Convertible Senior Notes (Convertible Senior Notes) due 2035.  The Convertible Senior Notes are unsecured and are not guaranteed by TEP or any other UniSource Energy subsidiary.  Each $1,000 of Convertible Senior Notes is convertible into 26.6667 shares of UniSource Energy Common Stock at any time, representing a conversion price of approximately $37.50 per share of our Common Stock, subject to adjustment in certain circumstances.

Beginning on March 5, 2010, UniSource Energy will have the option to redeem the Convertible Senior Notes, in whole or in part, for cash at a price equal to 100% of the principal amount plus accrued interest.  Holders of the Convertible Senior Notes may require UniSource Energy to repurchase the Convertible Senior Notes, in whole or in part, for cash on March 1, 2015, 2020, 2025 and 2030, or if certain change of control transactions occur, or if our common stock is no longer listed on a national securities exchange.  The repurchase price will be 100% of the principal amount of the Convertible Senior Notes plus accrued interest.

Certain of the Convertible Senior Notes features are considered to be embedded derivatives.  Based on accounting requirements, we concluded that the embedded derivatives either do not have any value or they are not required to be separated from the debt and accounted for separately.

In March 2005, UniSource Energy used $106 million of the net proceeds from this offering to repay the $95 million promissory note to TEP plus accrued interest of $11 million.  TEP used these funds, along with borrowings under its revolving credit facility to repurchase and redeem $225 million of industrial development bonds (IDBs).  See TEP Debt – Unsecured IDBs, below.

Intercompany Notes Payable

In 1998, TEP and UniSource Energy exchanged all of the outstanding common stock of TEP on a share-for-share basis for the Common Stock of UniSource Energy in a transaction which resulted in UniSource Energy becoming a holding company with TEP as its subsidiary.  Following the share exchange, TEP transferred the stock of Millennium to UniSource Energy for a $95 million promissory note due in 2008.  On March 1, 2005, UniSource Energy used $106 million of the $146 million of net proceeds from the convertible debt offering, as discussed above, to repay the $95 million promissory note to TEP plus accrued interest of $11 million.  Repayment of the note resulted in a $25 million capital contribution to TEP.

TEP DEBT

Collateral Trust Bonds

In 1998, TEP issued a total of $140 million, 7.5% collateral trust bonds, due August 11, 2008.  The balance outstanding as of December 31, 2007 was $138 million and is reported as a Current Liability in the TEP and UniSource Energy balance sheets.  TEP intends to refinance these bonds in 2008.
 
 
1941 Mortgage IDBs

In March 2005, TEP redeemed, at par, all of the remaining $52 million of its 1941 Mortgage IDBs.

Unsecured IDBs

In May 2005, TEP purchased $221 million of fixed rate Unsecured IDBs at a price of $101.50 per $100 principal amount and redeemed, at par, the remaining $4 million of bonds outstanding under those series.  In connection with the repurchase, TEP recognized a loss of approximately $3 million related to previously deferred debt costs.  TEP does not plan to cancel the IDBs that it repurchased, but is holding the bonds as treasury bonds.  This means the bonds remain outstanding under their indentures but are not reflected as debt on the balance sheet.  In February 2008, TEP received approval from the Industrial Development Authority of Pima County to issue refunding IDBs, the proceeds of which would be used to redeem the $221 million of  Unsecured IDBs held by TEP.

Mortgage Indenture

TEP's indenture creates liens on and security interests in most of TEP's utility plant assets, with the exception of Springerville Unit 2.  San Carlos Resources Inc., a wholly-owned subsidiary of TEP, holds title to Springerville Unit 2.  Utility Plant under Capital Leases is not subject to such liens or available to TEP creditors, other than the lessors.  The net book value of TEP's utility plant subject to the lien of the indenture was approximately $1 billion at December 31, 2007.

TEP CAPITAL LEASE OBLIGATIONS

The terms of TEP’s capital leases are as follows:

 
·
The Sundt Lease has an initial term to January 2011 and provides for renewal periods of two or more years through 2020.
 
·
The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025.
 
·
The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030.
 
·
The Springerville Coal Handling Facilities Leases have an initial term to April 2015 and provide for one renewal period of six years, then additional renewal periods of five or more years through 2035.

TEP has agreed with the owners of Springerville Units 3 and 4 that, upon expiration of the Springerville Coal Handling Facilities and Common Leases, TEP is obligated to acquire the facilities at fixed prices of $120 million in 2015, $38 million in 2017, and $68 million in 2021.  Upon such acquisitions by TEP, each of the owners of Unit 3 and Unit 4 have the obligation to purchase from TEP a 17% and 14% interest, respectively, in such facilities.  On or before the Sundt and Springerville Unit 1 Lease expiration dates, TEP will determine if it will purchase the assets at the fair market value or renegotiate the lease terms.

In January 2008, TEP made the following scheduled lease payments:  Sundt Lease $12 million; Springerville Common Facilities Leases $2 million; Springerville Unit 1 Leases $72 million; and Springerville Coal Handling Facilities Leases $2 million.

Investments in Springerville Lease Debt and Equity

In June 2006, TEP purchased a 14% undivided equity ownership interest in the Springerville Unit 1 Lease and now is the owner participant under the leveraged lease arrangements relating to such undivided interest.  As a result, the scheduled lease payments were reduced by $19 million, as TEP no longer makes payments to the former equity holders.

TEP held an investment in Springerville Unit 1 lease debt totaling $71 million at December 31, 2007 and $82 million at December 31, 2006.  TEP also held an investment in Springerville Coal Handling Facilities lease debt totaling $34 million at December 31, 2007 and $52 million at December 31, 2006.
 
Springerville Common Lease Debt Refinancing

In 1985, TEP sold and leased back its undivided one-half ownership interest in the common facilities at the Springerville Generating Station.  TEP refinanced the lease debt totaling $68 million in June 2006, and the leases were amended to remove the requirement that the notes be periodically refinanced to avoid the occurrence of a   
 
 
special event of loss.  The lease debt now matures when the leases expire.  Interest is payable at LIBOR plus 1.5% through 2009.  Thereafter, the spread over LIBOR increases by 0.125% every three years, to 2% by June 2018.  Prior to the refinancing, the interest rate was LIBOR plus 4%.  The refinancing had no impact on the Springerville Common Facilities capital lease obligation or asset.

A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the underlying floating rate lease debt.  In June 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt.  This swap has the effect of fixing the interest portion of rent at a rate of 7.27% on a portion of the principal balance, which was $36 million as of December 31, 2007.   The interest rate swap has been recorded by TEP as a cash flow hedge for financial reporting purposes.  See Note 4.

UNS GAS AND UNS ELECTRIC LONG-TERM DEBT

Senior Unsecured Notes

In 2003, UNS Gas and UNS Electric issued a total of $160 million of senior unsecured notes in a private placement.  UNS Gas issued $50 million of 6.23% notes due August 11, 2011 and $50 million of 6.23% notes due August 11, 2015.  UNS Electric issued $60 million of 7.61% notes due August 11, 2008. All three series of notes may be prepaid with a make-whole call premium reflecting a discount rate equal to an equivalent maturity U.S. Treasury security yield plus 50 basis points.  UES guarantees the notes.  UNS Gas and UNS Electric incurred a total of $2 million in debt costs related to the issuance of the notes.  We deferred these costs and are amortizing them over the life of the notes.

At December 31, 2007, the UNS Electric $60 million senior unsecured note, due August 11 2008, is included in Current Liabilities in the UniSource Energy balance sheet.

The note purchase agreements for both UNS Gas and UNS Electric contain certain restrictive covenants, including restrictions on transactions with affiliates, mergers, additional indebtedness, dividend restrictions, and minimum net worth requirements.

As of December 31, 2007, UNS Gas and UNS Electric complied with the terms of the note purchase agreements.

DEBT MATURITIES

Long-term debt, including term loan payments, revolving credit facilities, and capital lease obligations mature on the following dates:

   
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
    
Total
  
- Millions of Dollars -
  
2008
   $ -     $ 138     $ 118     $ 256     $ -     $ 60     $ 6     $ 322  
2009
     -       -       63       63       -       -       6       69  
2010
     -       -       93       93       -       -       6       99  
2011
     329       -       107       436       50       26       23       535  
2012
     -       -       118       118       -       -       -       118  
Total 2008 – 2012
     329       138       499       966       50       86       41       1,143  
Thereafter
     -       354       421       775       50       -       150       975  
Less:  Imputed Interest
      -       -       (331 )     (331 )     -        -        -       (331 )
Total
   $ 329     $ 492     $ 589     $ 1,410     $ 100     $ 86     $ 191     $ 1,787  

TEP’s Variable Rate IDBs are backed by letters of credit (LOC) issued pursuant to TEP’s Credit Agreement which expires in August 2011.  Although the Variable Rate IDBs mature between 2018 and 2022, the above table reflects
 
 
a redemption or repurchase of such bonds in 2011 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement.

Effective with commercial operation of Springerville Unit 3 on September 1, 2006, Tri-State is reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including 14% of the Springerville Common Lease payments and 17% of the Springerville Coal Handling Facilities Lease payments.  TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement.

UNISOURCE ENERGY CREDIT AGREEMENT

The UniSource Credit Agreement consists of a $30 million amortizing term loan facility and a $70 million revolving credit facility and matures in August 2011.

Principal payments of $1.5 million on the outstanding term loan are due quarterly, with the balance due at maturity.  At December 31, 2007, there was $21 million outstanding under the term loan facility of which $15 million is included in Long-Term Debt and $6 million is included in Current Liabilities and $20 million outstanding under the revolving credit facility at a weighted average interest rate of 6.27%.  We have included these borrowings in Long-Term Debt as UniSource Energy has the ability and the intent to have outstanding borrowings for the next twelve months.  In January 2008, UniSource Energy repaid $8 million outstanding under its revolving credit facility.

At December 31, 2006, UniSource Energy had $27 million outstanding under the term loan facility, of which $21 million is included in Long-Term Debt and $6 million is included in Current Liabilities, and $20 million outstanding under the revolving credit facility, included in Current Liabilities.  UniSource Energy repaid the $20 million outstanding under its revolving credit facility in January 2007.

We have the option of paying interest on the term loan and on borrowings under the revolving credit facility at adjusted LIBOR plus 1.25% or the sum of the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate and 0.25%.

The UniSource Credit Agreement restricts additional indebtedness, liens, mergers, sales of assets, and certain investments and acquisitions.  We must also meet: (1) a minimum cash flow to interest coverage ratio for UniSource Energy on a standalone basis and (2) a maximum leverage ratio on a consolidated basis.  We may pay dividends if, after giving effect to the dividend payment, we have more than $15 million of unrestricted cash and unused revolving credit.  As of December 31, 2007, we were in compliance with the terms of the UniSource Credit Agreement.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $150 million revolving credit facility, and a $341 million LOC facility which supports $329 million of tax-exempt Variable Rate IDBs.  The TEP Credit Agreement matures in August 2011 and is secured by $491 million 1992 Mortgage Bonds.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. Letter of credit fees are 0.55% per annum and amounts drawn under a letter of credit would bear interest at LIBOR plus 0.55% per annum.  TEP has the option of paying interest on borrowings under the revolving credit facility at LIBOR plus 0.55% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The TEP Credit Agreement restricts additional indebtedness, liens, sale of assets and sale-leaseback agreements.  The TEP Credit Agreement also requires TEP to meet a minimum cash coverage ratio and a maximum leverage ratio.  If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UniSource Energy.  As of December 31, 2007, TEP was in compliance with the terms of the TEP Credit Agreement.

As of December 31, 2007, TEP had $10 million outstanding under its revolving credit facility at an interest rate of 7.25%.  As of December 31, 2006, TEP had $30 million outstanding under this facility.  The balances are included in Current Liabilities in the UniSource Energy and TEP balance sheets.
 
 
UNS GAS/UNS ELECTRIC CREDIT AGREEMENT

The UNS Gas/UNS Electric Revolver is a $60 million revolving credit facility which matures in August 2011.   Either UNS Gas or UNS Electric may borrow up to a maximum of $45 million, so long as the combined amount borrowed does not exceed $60 million.  UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver.  UES guarantees the obligations of both UNS Gas and UNS Electric.

UNS Gas and UNS Electric each have the option of paying interest at LIBOR plus 1.0% or the greater of the federal funds rate plus 0.5% or the agent bank’s reference rate.

The UNS Gas/UNS Electric Revolver contains restrictions on additional indebtedness, liens, mergers and sales of assets. The UNS Gas/UNS Electric Revolver also contains a maximum leverage ratio and a minimum cash flow to interest coverage ratio for each borrower.  As of December 31, 2007, UNS Gas and UNS Electric were each in compliance with the terms of the UNS Gas/UNS Electric Revolver.

As of December 31, 2007, UNS Gas had no borrowings outstanding under the UNS Gas/UNS Electric revolving credit facility and $10 million in outstanding letters of credit.  The outstanding letters of credit support gas purchases and are off-balance sheet obligations for UNS Gas.  UNS Electric had $26 million of borrowings outstanding under the UNS Gas/UNS Electric revolving credit facility, at a weighted average interest rate of 5.89%.  As of December 31, 2006, UNS Gas had no borrowings outstanding and UNS Electric had $19 million of borrowings outstanding.  These revolver balances were excluded from Current Liabilities and presented as Long-Term Debt, in the UniSource Energy balance sheets, as UNS Electric has the ability and the intent to have outstanding borrowings under its revolving credit facilities for the next twelve months.


NOTE 8.  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying values and fair values of our financial instruments are as follows:

   
December 31,
  
   
2007
    
2006
  
   
Carrying
Value
    
Fair
Value
    
Carrying
Value
    
Fair
Value
  
   
-Millions of Dollars-
  
Assets:
                        
TEP Investment in Springerville Lease Debt Securities
   $ 105     $ 109     $ 133     $ 139  
TEP Investment in Springerville Lease Equity
     48       48       48       48  
Liabilities:
                                
UniSource Energy Convertible Senior Notes
     150       153       150       164  
UniSource Energy Credit Agreement
     41       41       27       27  
   TEP Secured Variable Rate IDBs
     329       329       329       329  
TEP Collateral Trust Bonds
     138       141       138       142  
TEP Unsecured IDBs -  Fixed Rate
     354       357       354       359  
UNS Gas Senior Unsecured Notes
     100       106       100       102  
UNS Electric Senior Unsecured Notes
     60       60       60       60  
UNS Electric Credit Agreement - Revolving Credit Facility
     26       26       19       19  

See Note 7 for a description of TEP’s investment in Springerville Lease Debt and Equity.  TEP intends to hold the $105 million investment in Springerville Lease Debt Securities to maturity (Springerville Coal Handling Facilities lease debt totaling $34 million matures through July 1, 2011, and Springerville Unit 1 lease debt totaling $71 million matures through January 1, 2013).  This investment is stated at amortized cost, which means the purchase cost has been adjusted for the amortization of the premium and discount to maturity.

 
·
TEP considers the purchase price of the Springerville Lease Equity to be a reasonable estimate of its fair value.
 
·
UniSource Energy and TEP used quoted market prices to determine the fair value of the UNS Convertible Senior Notes and TEP’s tax-exempt fixed rate obligations (Unsecured IDBs).
 
·
TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of their fair value.
 
 
We determined the fair value of our remaining financial instruments (TEP Springerville Lease Debt Securities, TEP Collateral Trust Bonds, and UNS Gas and UNS Electric Senior Unsecured Notes) by calculating the present value of the cash flows using a discount rate consistent with market yields generally available as of December 31, 2007 and December 31, 2006 for bonds with similar characteristics with respect to credit rating and time-to-maturity.  The use of different market assumptions and/or estimation methodologies may yield different estimated fair value amounts.

The TEP Collateral Trust Bonds are due in August 2008 and are included in Current Maturities of Long-Term Debt in our balance sheets at December 31, 2007.  The fair value was determined as described above.  The carrying amounts of our remaining current assets and liabilities approximate fair value.
 
NOTE 9.  STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UniSource Energy

In February 2008, UniSource Energy declared a first quarter dividend to shareholders of $0.24 per share of UniSource Energy Common Stock.  The dividend, totaling approximately $8 million, will be paid on March 21, 2008 to common shareholders of record as of March 10, 2008.  In 2007, UniSource Energy paid quarterly dividends to the shareholders of $0.225 per share, for a total of $0.90 per share, or $32 million for the year.  In 2006, UniSource Energy paid quarterly dividends to the shareholders of $0.21 per share, for a total of $0.84 per share, or $29 million, for the year.  During 2005, UniSource Energy paid quarterly dividends to the shareholders of $0.19 per share, for a total of $0.76 per share, or $26 million, for the year.

Our ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium and UED, as well as compliance with various debt covenant requirements.    As of December 31, 2007, we complied with the terms of all such debt covenant requirements.

TEP

TEP paid dividends of $53 million in 2007, $62 million in 2006, and $46 million in 2005.  UniSource Energy is the holder of TEP’s common stock.  TEP met the requirements discussed below before paying these dividends.

In December 2007, UniSource Energy contributed $18 million of capital to TEP.

Bank Credit Agreement

TEP’s Credit Agreement as of August 2006 allows TEP to pay dividends as long as TEP complies with the agreement and certain financial covenants including quarterly limits on the ratio of total indebtedness to total earnings before interest expense/income, income taxes and non-cash items.  TEP is in compliance with these covenants.

Federal Power Act

This Act states that dividends shall not be paid out of funds properly included in capital accounts.  TEP’s 2007, 2006 and 2005 dividends were paid from current year earnings.

UNS Gas and UNS Electric

Restrictions placed on UNS Gas and UNS Electric limit UES’ ability to pay dividends.  The 2003 UES Settlement Agreement allows UNS Gas and UNS Electric to pay dividends greater than 75% of its earnings to UniSource Energy when the ratio of common equity to total capitalization reaches 40%.  As of December 31, 2007 and December 31, 2006, both UNS Gas and UNS Electric met this ratio requirement.  Additionally, the terms of the senior unsecured note agreements entered into by both UNS Gas and UNS Electric contain dividend restrictions. See Note 7.  UES did not pay any dividends to UniSource Energy in 2007, 2006 or 2005.

UniSource Energy made capital contributions to UNS Electric of $10 million in each of the years 2007 and 2006.
 
 
Millennium and UED

In 2007, Millennium paid a $15 million dividend to UniSource Energy.  Millennium did not pay dividends to UniSource Energy in 2006 or 2005.  UED did not pay dividends to UniSource Energy in 2007, 2006 or 2005.  Millennium and UED have no dividend restrictions.

UNISOURCE ENERGY SHAREHOLDER RIGHTS PLAN

In March 1999, UniSource Energy adopted a Shareholder Rights Plan.  As of April 1, 1999, each Common Stock shareholder receives one Right for each share held.  Each Right initially allows shareholders to purchase UniSource Energy’s Series X Preferred Stock at a specified purchase price.  However, the Rights are exercisable only if a person or group (the “acquirer”) acquires or commences a tender offer to acquire 15% or more of UniSource Energy Common Stock.  Each Right would entitle the holder (except the acquirer) to purchase a number of shares of UniSource Energy Common or Preferred Stock (or, in the case of a merger of UniSource Energy into another person or group, common stock of the acquiring person) having a fair market value equal to twice the specified purchase price.  At any time until any person or group has acquired 15% or more of the Common Stock, UniSource Energy may redeem the Rights at a redemption price of $0.001 per Right.  The Rights trade automatically with the Common Stock when it is bought and sold.  The Rights expire on March 31, 2009.


NOTE 10.  INCOME TAXES

We record deferred income tax assets and liabilities for amounts that will increase and decrease, respectively, income taxes on future tax returns. We consider it more likely than not that all the deferred tax assets will be used on a tax return.  Consequently, we have not recorded a valuation allowance to reduce our deferred tax assets.

Deferred tax assets (liabilities) consist of the following:
 
 
 UniSource Energy
  
 TEP
 
 December 31,
  
December 31,
 
 2007
  
 2006
  
 2007
  
2006
 
-Millions of Dollars-
Gross Deferred Income Tax Liabilities
                        
Plant – Net
   $ (334 )   $ (327 )   $ (315 )   $ (312 )
Income Taxes Recoverable Through Future
                                
Revenues Regulatory Asset
     (12 )     (15 )     (12 )     (15 )
   Transition Recovery Asset
     (9 )     (40 )     (9 )     (40 )
   Pensions
     (4 )     (3 )     (5 )     (3 )
   Unbilled Revenue
     -       (3 )     -       (3 )
   Convertible Debt
     (4 )     (2 )     -       -  
Other
     (6 )     (8 )     (5 )     (6 )
Gross Deferred Income Tax Liability
     (369 )     (398 )     (346 )     (379 )
                                 
Gross Deferred Income Tax Assets
                        
Capital Lease Obligations
     152       181       152       181  
   Alternative Minimum Tax Credit(no expiration)     38       48       24       34  
Accrued Postretirement Benefits
     25       26       25       26  
Emission Allowance Inventory
     14       13       12       13  
   Customer Advances
     11       11       3       2  
Coal Contract Termination Fees
     8       10       8       10  
   Unregulated Investment Losses
     7       7       -       -  
   Vacation & Sick Accrual
     3       3       3       3  
Capital Loss Carryforwards
     2       15       -       -  
Other
     19       15       14       12  
Gross Deferred Income Tax Asset
     279       329       241       281  
Net Deferred Income Tax Liability
   $ (90 )   $ (69 )   $ (105 )   $ (98 )
 
UniSource Energy has a capital loss carryforward of $4 million which expires in 2011.  The $2 million of capital loss carryforward included in the above table is the tax benefit of the capital loss.
 
 
The balance sheets display the net deferred income tax liability as follows:
 
 
 UniSource Energy
  
 TEP
 
 December 31,
  
 December 31,
 
 2007
  
 2006
  
 2007
  
 2006
 
 -Millions of Dollars-
                                 
Deferred Income Taxes – Current Assets
   $ 60     $ 58     $ 59     $ 57  
Deferred Income Taxes – Noncurrent Liabilities
     (150 )     (127 )     (164 )     (155 )
Net Deferred Income Tax Liability
   $ (90 )   $ (69 )   $ (105 )   $ (98 )

As of December 31, 2007, UniSource Energy’s deferred income tax assets include $7 million related to unregulated investment losses of Millennium, of which $3 million relates to Nations Energy.  These losses have not been reflected on our consolidated income tax returns.  If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the foreseeable future, it would have to write-off these deferred tax assets.  Millennium expects to dispose of these investments in the foreseeable future and thereby recognize the losses on a consolidated tax return.

As of December 31, 2007 and December 31, 2006, TEP’s net intercompany tax receivable from affiliates equaled $2 million and $10 million respectively.  TEP includes these amounts under Intercompany Accounts  Receivable on its balance sheet.

Income tax expense (benefit) included in the income statements consists of the following:
 
   
 UniSource Energy
  
 TEP
   
 Years Ended December 31,
   
  2007 
    
  2006 
    
  2005 
    
  2007 
    
  2006 
    
  2005 
  
   
 -Millions of Dollars-
                                                 
Current Tax Expense
                                    
Federal
   $ 14     $ 37     $ 19     $ 22     $ 32     $ 16  
State
     3       12       10       6       10       11  
Total
     17       49       29       28       42       27  
Deferred Tax Expense (Benefit)
                                                
Federal
     20       -       13       9       5       13  
State
     2       (5 )     (3 )     (1 )     (5 )     (5 )
Total
     22       (5 )     10       8       -       8  
Increase (Reduction) in Valuation Allowance
     -       -       (1 )     -       -       (1 )
Total Federal and State Income Tax Expense
         (before Discontinued Operations and
          Cumulative Effect of Accounting Change)
     39       44       38       36         42         34  
Tax on Discontinued Operations
     -       (2 )     (5 )     -       -       -  
Total Federal and State Income Tax Expense
        (including Discontinued Operations and
         Cumulative Effect of Accounting Change)
   $ 39     $ 42     $ 33     $ 36     $ 42     $ 34  

The differences between the income tax expense and the amount obtained by multiplying pre-tax income by the U.S. statutory federal income tax rate of 35% are as follows:
 
   
 UniSource Energy
  
 TEP
   
 Years Ended December 31,
   
  2007 
    
  2006 
    
  2005 
    
  2007 
    
  2006 
    
  2005 
  
   
 -Millions of Dollars-
                                                 
Federal Income Tax Expense at Statutory Rate
   $ 34     $ 40     $ 32     $ 31     $ 38     $ 29  
State Income Tax Expense, Net of Federal
      Deduction
     5       5       5       4       5       4  
Depreciation Differences (Flow Through Basis)
     3       2       3       3       2       3  
Federal/State Tax Credits
     (2 )     (2 )     (1 )     (2 )     (2 )     (1 )
Other
     (1 )     (1 )     (1 )     -       (1 )     (1 )
Total Federal and State Income Tax Expense
     (before Discontinued Operations and
      Cumulative Effect of Accounting Change)
   $ 39     $ 44     $ 38     $ 36     $ 42     $ 34  
 
The Total Federal and State Income Tax Expense in the tables above is included on UniSource Energy and TEP’s income statements.
 
 
Uncertain Tax Positions

FIN 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FAS 109 (FIN 48) issued July 2006, requires us to determine whether it is “more likely than not” that we will sustain a tax position under examination.  Such a position is measured to determine the amount of benefit to recognize in the financial statements.  UniSource Energy adopted the provisions of FIN 48 on January 1, 2007.  The cumulative effects of applying this interpretation were recorded as an increase of less than $1 million to retained earnings and the recognition of a $13 million uncertain tax liability.  A reconciliation of the amount of uncertain tax liability recorded for 2007 is as follows:
 
   
UniSource Energy
    
TEP
  
   
-Millions of Dollars-
  
Unrecognized Tax Benefit at January 1, 2007
   $ 13     $ 13  
  Gross Increase to Tax Benefit Related to Tax Positions in Prior Year
     -       -  
  Gross Decrease to Tax Benefit Related to Tax Positions in Prior Year
     (1 )     (1 )
  Gross Increase to Tax Benefit Related to Tax Positions in Current Year
     -       -  
  Settlement With Taxing Authorities
     -       -  
  Lapse of Statute of Limitations
     -       -  
Unrecognized Tax Benefits (Liability) at December 31, 2007
   $ 12     $ 12  

If we recorded the unrecognized tax benefit at December 31, 2007, there would be no impact on our effective tax rate.  It is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next 12 months.  However, an estimate of the range of the increase or decrease cannot be made.  Tax years 2002 through 2006 are open under Federal, Arizona and New Mexico statutes.

TEP recognizes interest accrued related to unrecognized tax benefits in Other Interest Expense in the income statements.  The total interest expense recognized for 2007 was $1 million and the balance of interest payable at December 31, 2007 is $2 million.  No penalties have been recognized.

Other Tax Matters

On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets.  We also used the new accounting method on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.

In 2005, the Internal Revenue Service issued a ruling limiting the ability of electric and gas utilities to use the new accounting method.  As a result, TEP, UNS Gas and UNS Electric amended their 2002, 2003 and 2004 federal and state tax returns to remove the benefit previously claimed using the accounting method and remitted tax and interest of $31 million, $1 million and $0.3 million, respectively, to the IRS and state tax authorities.  Based on settlement guidelines relating to the accounting method that were issued by the IRS in March 2007, TEP, UNS Gas and UNS Electric have settled this issue with the IRS.  In December 2007, TEP recorded the effect of the settlement by recognizing $2 million of interest income.  TEP anticipates receiving $12 million of taxes and interest during 2008 which will have no impact on the overall tax provision or net income.


NOTE 11.  EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees.  Employees receive benefits based on their years of service
 
 
and average compensation.  TEP, UNS Gas and UNS Electric fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations.  Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by IRS benefit or compensation limitations.

In 2008, TEP expects to contribute $9 million and UNS Gas and UNS Electric expect to contribute $1 million to the pension plans.

OTHER POSTRETIREMENT BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees.  All regular employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.  UNS Gas and UNS Electric provide postretirement medical benefits for current retirees and a small group of active employees.

INCREMENTAL EFFECT OF APPLYING FAS 158

As a result of applying FAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, in December 2006, we are required to recognize the underfunded status of our defined benefit pension and other postretirement plans as a liability on our consolidated balance sheets.  The underfunded status is measured as the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated postretirement benefit obligation for other postretirement benefit plans.  The adjustment required to initially recognize the pension liability upon implementation of this statement resulted in recognition of a regulatory asset for our regulated operations and an adjustment to Accumulated Other Comprehensive Loss for our unregulated operations.  We recorded the required increase in our other postretirement obligation as an adjustment to Accumulated Other Comprehensive Loss as the ACC allows TEP, UNS Gas and UNS Electric to recover other postretirement costs through rates only as benefit payments are made.

The following table presents the incremental effect of applying FAS 158, in combination with FAS 71, as well as the change to the additional minimum pension liability, on individual line items in TEP’s balance sheet at December 31, 2006:
 
   
Before Application
of FAS 158
              
 
 
 
 
TEP Balance Sheet Line Items:
  
Preliminary
Balances at December 31, 2006
    
Application of Pre-FAS158 Accounting Guidance
    
 
 
FAS 158 Adjustment
    
Balances at December 31, 2006 After
Application of FAS 158
  
   
- Millions of Dollars -
  
Other Assets
   $ 29     $ 9     $ (16 )   $ 22  
Other Regulatory Assets
     20       4       28       52  
Total Assets
     2,598       13       12       2,623  
Deferred Income Taxes - Noncurrent
     156       9       (10 )     155  
Other Liabilities
     100       (9 )     36       127  
Total Deferred Credits and Other Liabilities
     336       -       26       362  
Accumulated Other Comprehensive Loss
  (Net of Tax)
     16       14       (15 )     15  
Total Stockholders’ Equity
     556       14       (15 )     555  

Prior to the application of FAS 158, the accounting guidance (Pre-FAS 158) required TEP to adjust its minimum pension liability in Accumulated Other Comprehensive Loss to reflect the underfunded status of its plans based on the accumulated benefit obligation.  After the implementation of FAS 158 and before applying the provisions of FAS 71, TEP had an accumulated comprehensive loss balance (net of tax) of $35 million attributable to its pension and other postretirement benefit obligations.  TEP subsequently recorded a regulatory asset of $32 million and an offsetting reduction on an after-tax basis of accumulated other comprehensive loss of $19 million, representing a reasonable approximation of the actuarial losses and prior service costs of TEP’s pension plans that are probable of recovery in rates by its regulated operations in future periods.

UNS Gas and UNS Electric were not required to record a minimum pension liability under Pre-FAS 158 accounting guidance.  Following the implementation of FAS 158, UNS Gas and UNS Electric recorded a combined regulatory pension asset and increase in pension liability of $3 million.  The impact of FAS 158 on the postretirement plans of UNS Gas and UNS Electric was less than $1 million.
 
 
The pension and other postretirement benefit related amounts (excluding tax balances) included in the UniSource Energy balance sheet are:

   
Pension Benefits
Other
Postretirement
Benefits
  
   
Years Ended December 31,
  
   
2007
    
2006
    
2007
    
2006
  
   
-Millions of Dollars-
  
Regulatory Pension Asset included in Other Regulatory Assets
   $ 16     $ 35     $ -     $ -  
Accrued Benefit Liability included in Accrued Employee Expenses
     -       -       (4 )     (3 )
Accrued Benefit Liability included in Pension and Other Postretirement Benefits
     (16 )     (42 )     (60 )     (63 )
Accumulated Other Comprehensive Loss
     10       17       6       8  
Net Amount Recognized
   $ 10     $ 10     $ (58 )   $ (58 )

The table above includes a combined accrued pension benefit liability of approximately $3 million and a postretirement benefit liability of less than $2 million for UNS Gas and UNS Electric, for each period presented, in addition to the minimal FAS 158 impact previously noted.

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other postretirement benefit plans at December 1.  FAS 158 requires the measurement date to be changed to the end of the year effective December 31, 2008.  The tables below include TEP, UNS Gas and UNS Electric plans.  The change in projected benefit obligation and plan assets and reconciliation of the funded status are as follows:
 
   
 Pension Benefits
  
 Other Postretirement
Benefits
   
 Years Ended December 31,
   
2007
  
 2006
  
 2007
  
 2006
   
 -Millions of Dollars-
Change in Projected Benefit Obligation
                        
Benefit Obligation at Beginning of Year
   $ 218     $ 208     $ 66     $ 70  
Actuarial (Gain) Loss
     (17 )     -       (1 )     (7 )
Interest Cost
     13       12       4       4  
Service Cost
     8       7       2       2  
Amendments
     -       -       (3 )     -  
Benefits Paid
     (13 )     (9 )     (3 )     (3 )
Projected Benefit Obligation at End of Year
     209       218       65       66  
                                 
Change in Plan Assets
                                
Fair Value of Plan Assets at Beginning of Year
     176       149       -       -  
Actual Return on Plan Assets
     20       21       -       -  
Benefits Paid
     (13 )     (9 )     (4 )     (3 )
Employer Contributions
     10       15       4       3  
Fair Value of Plan Assets at End of Year
     193       176       -       -  
                                 
Funded Status at End of Year
   $ (16 )   $ (42 )   $ (65 )   $ (66 )
 
The tables above include a combined pension benefit obligation of less than $8 million and plan assets of less than $5 million for UNS Gas and UNS Electric for all periods presented.

The following table provides the components of UniSource Energy’s accumulated other comprehensive loss and regulatory assets that have not been recognized as components of net periodic benefit cost as of December 31, 2007:
 

   
Pension Benefits
    
Other Postretirement Benefits
  
   
-Millions of Dollars-
  
Net Loss
   $ 19     $ 14  
Prior Service Cost (Benefit)
     7       (8 )

The accumulated benefit obligation for all defined benefit pension plans was $180 million at December 31, 2007 and $184 million at December 31, 2006.  Changes in actuarial assumptions including an increase in the discount rate impacted the accumulated benefit obligation.
 
 
   
December 31,
  
   
2007
    
2006
  
   
-Millions of Dollars-
  
 Information for Pension Plans with an Accumulated            
Benefit Obligation in Excess of Plan Assets:
            
Projected Benefit Obligation at End of Year
   $ 10     $ 116  
Accumulated Benefit Obligation at End of Year
     7       100  
Fair Value of Plan Assets at End of Year
     -       89  

At December 31, 2006, three UniSource Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets.  Due to 2007 contributions and returns on plan assets and the favorable impact on the accumulated benefit obligations of the increase in the discount rate, only the Supplemental Executive Retirement Plan, which is unfunded, has an accumulated benefit obligation in excess of plan assets at December 31, 2007.

The components of net periodic benefit costs are as follows:
 
     Pension Benefits  
 Other Postretirement
Benefits
   
 Years Ended December 31,
   
  2007
  
  2006
  
 2005
  
 2007
  
  2006
  
  2005
   
 -Millions of Dollars-
Components of Net Periodic Cost
                                    
Service Cost
   $ 8     $ 7     $ 7     $ 2     $ 2     $ 2  
Interest Cost
     13       12       11       4       4       4  
Expected Return on Plan Assets
     (14 )     (13 )     (11 )     -       -       -  
Prior Service Cost Amortization
     1       2       2       (2 )     (1 )     (1 )
Recognized Actuarial Loss
     2       3       3       1       1       2  
Net Periodic Benefit Cost
   $ 10     $ 11     $ 12     $ 5     $ 6     $ 7  

The amounts recognized in Other Comprehensive Income (OCI) or as regulatory assets are as follows:
 
   
Pension Benefits
  
   
2007
    
2006
    
2005
  
   
Regulatory Asset
  
OCI
  
Regulatory Asset
  
OCI
  
Regulatory Asset
  
OCI
  
Changes in Plan Assets and Benefit Obligations Recognized in OCI or as Regulatory Assets
                                    
Current Year Actuarial (Gain) Loss
   $ (16 )   $ (6 )   $ -     $ -     $ -     $ -  
Amortization of Actuarial Gain (Loss)
     (1 )     (1 )     -       -       -       -  
Prior Service (Cost) Amortization
     (1 )     (1 )     -       -       -       -  
Change in Additional Minimum Liability
     -       -       4       (23 )     -       3  
Total Recognized in OCI or as Regulatory Assets
   $ (18 )   $ (8 )   $ 4     $ (23 )   $ -     $ 3  
 

   
Other Postretirement Benefits
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
Changes in Benefit Obligation Recognized in OCI
                  
Current Year Actuarial (Gain) Loss
   $ (1 )   $ -     $ -  
Amortization of Actuarial Gain (Loss)
     (1 )     -       -  
Prior Service Cost (Credit)
     (2 )     -       -  
Prior Service (Cost) Amortization
     2       -       -  
Total Recognized in OCI
   $ (2 )   $ -     $ -  
 
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 less than $1 million estimated net loss and $2 million prior service cost from accumulated other comprehensive income and other regulatory assets into net periodic benefit cost in 2008.  The estimated net loss and prior service benefit for the defined benefit postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2008 are $1 million and $2 million, respectively.

 
 
Pension Benefits
Other Postretirement Benefits
 
2007
2006
2007
2006
Weighted-Average Assumptions Used to Determine
  Benefit Obligations as of December 1,
        
Discount Rate
6.6 – 6.8%
5.9%
6.5%
5.6%
Rate of Compensation Increase
3.0 – 5.0%
3.0 – 5.0%
N/A
N/A

 
Pension Benefits
Other Postretirement Benefits
 
2007
2006
2007
2006
Weighted-Average Assumptions Used to Determine
  Net Periodic Benefit Cost for Years Ended
  December 31,
        
Discount Rate
5.9%
5.8 – 5.9%
5.6 – 5.8%
5.8%
Rate of Compensation Increase
3.0 – 5.0%
3.0 – 5.0%
N/A
N/A
Expected Return on Plan Assets
8.3%
8.3%
N/A
N/A

Net periodic benefit cost for the other postretirement benefit plan was remeasured as of January 1, 2007 to reflect the plan amendment communicated to plan participants on January 2, 2007.  A discount rate of 5.6% was used for the January 2007 portion of the expense, while a discount rate of 5.8% was used for the remaining eleven months.

Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. We estimated the expected return on plan assets based on a review of the plans’ asset allocations.  We also consulted with a third-party investment consultant and the plans’ actuary who consider factors such as:
 
·
market and economic indicators
 
·
historical market returns
 
·
correlations and volatility
 
·
central banks’ and government treasury departments’ forecasts and objectives, and
 
·
recent professional or academic research.
Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.

 
December 31,
    
   
2007
    
2006
Assumed Health Care Cost Trend Rates
          
Health Care Cost Trend Rate Assumed for Next Year
     8 %     9 %
Ultimate Health Care Cost Trend Rate Assumed
     5 %     5 %
    Year that the Rate Reaches the Ultimate Trend Rate     2013        2013   
 
 
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, 2007 amounts:

 
One-Percentage-
Point Increase
One-Percentage-
Point Decrease
 
-Millions of Dollars-
Effect on Total of Service and Interest Cost Components
        $   1
         $    1
Effect on Postretirement Benefit Obligation
          4
          (4)

PENSION PLAN ASSETS

TEP, UNS Gas and UNS Electric calculate the fair value of plan assets on December 1, the measurement date.   TEP’s pension plan asset allocations at December 31, 2007 and 2006 by asset category follow:
 
 
Plan Assets
December 31,
 
2007
2006
Asset Category
    
Equity Securities
54%
67%
Debt Securities
27%
23%
Real Estate
10%
10%
Other
  9%
-
Total
100%
100%
 
TEP’s investment policy for the pension plans targets exposure to the various asset classes in the following allocations: equity securities 50%, debt securities 25%, other 15%, and real estate 10%.  TEP rebalances the portfolio when the portfolio allocation is not within the desired range of exposure.  The plan seeks to provide returns in excess of a portfolio benchmark.  A third party investment consultant tracks the plan’s portfolio relative to the benchmark and provides quarterly investment reviews which consist of a performance and risk assessment on all investment managers and on the portfolio.

Investment managers for the plan may use derivative financial instruments for risk management purposes or as a part of their investment strategy.  Currency hedges have also been used for defensive purposes.  Real estate managers use leverage but it is limited by investment policy.

The UNS Gas and UNS Electric pension plan provides exposure to equity and debt securities by investing in a balanced fund.  At December 31, 2007, the fund held 66% equity securities, 33% fixed income securities, and 1% cash.  The fund will hold no more than 75% of its total assets in equity securities.

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects to pay the following benefit payments, which reflect future service, as appropriate.
 
 

Pension
Benefits
Other
Postretirement
Benefits
 
-Millions of Dollars-
2008
 $ 6
 $ 4
2009
  8
  5
2010
  9
  5
2011
  10
  6
2012
  11
  6
Years 2013-2017
  73
  32
 
UNS Gas and UNS Electric expect to pay pension and postretirement benefits of approximately $1 million in 2008 through 2012 and $3 million in 2013 through 2016.
 

DEFINED CONTRIBUTION PLANS

TEP, UNS Gas and UNS Electric 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.  TEP, UNS Gas, and UNS Electric match part of a participant’s contributions to the plans.  TEP made matching contributions to these plans of approximately $4 million in 2007, $4 million in 2006 and $3 million in 2005.  UNS Gas and UNS Electric made matching contributions of less than $0.5 million in each of 2007, 2006, and 2005.


NOTE 12.  SHARE-BASED COMPENSATION PLANS

Under the 2006 Omnibus Stock and Incentive Plan, the Compensation Committee of the UniSource Energy Board of Directors 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 Plan cannot exceed 2.25 million shares.  At December 31, 2007, the total number of shares awarded under the 2006 Omnibus Stock and Incentive Plan was 0.5 million shares.

STOCK OPTIONS

Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant and expire on the tenth anniversary of the grant.  Compensation expense is recorded on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures.  For awards granted to retirement eligible officers, compensation expense is recorded immediately.  Certain stock option awards accrue dividend equivalents that are paid in cash on the earlier of the date of exercise of the underlying option or the date the option expires.  Compensation expense is recognized as dividends are paid.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table.  The expected term of options granted was estimated using a “simplified” method which considers the 3 year vesting period and the contractual term.  The risk-free rate is based on the rate available on a U.S. Treasury Strip with a maturity equal to the expected term of the option at the time of the grant.  Expected volatility was based on historical volatility for UniSource Energy’s stock for the past 6 years, the expected term.  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.

   
2007
2006
2005
         
Expected Term (Years)
  
6
6
6
Risk-Free Rate
  
4.4%
4.97%
4.00%
Expected Volatility
  
20.2%
22.57%
22.94%
Expected Dividend Yield
  
2.4%
2.45%
2.54%
Weighted-Average Grant-Date Fair Value of Options
    Granted During The Period
  
 
$8.13
 
$7.38
 
$7.39

A summary of the stock option activity follows:
 
(Shares in Thousands)
  
2007
  
2006
  
2005
Stock Options
  
Shares
Weighted Average Exercise Price
  
Shares
Weighted Average Exercise Price
  
Shares
Weighted Average Exercise Price
Outstanding, Beginning of Year
  
1,388
$18.59
  
1,537
$16.75
  
2,076
$16.19
Granted
  
184
$37.88
  
187
$30.55
  
50
$33.55
Exercised
  
(120)
$16.56
  
(304)
$15.97
  
(582)
$16.18
Forfeited
  
(1)
$12.28
  
(32)
$25.14
  
(7)
$17.87
Outstanding, End of Year
  
1,451
$21.21
  
1,388
$18.59
  
1,537
$16.75
                   
Exercisable, End of Year
  
1,139
$17.43
  
1,188
$16.49
  
1,480
$16.18
Aggregate Intrinsic Value of Options Exercised ($000s)
  
$2,226
    
$4,687
    
$7,983
  
 

 
At December 31,2007 ($000s)
Aggregate Intrinsic Value for Options Outstanding
$16,170
Aggregate Intrinsic Value for Options  Exercisable
$16,068
Weighted Average Remaining Contractual Life
4.6 years
Weighted Average Remaining Contractual Life of Exercisable Shares
3.5 years
 
A summary of stock option activity follows:

 
Options Outstanding
Options Exercisable
Range of Exercise Prices
Number of  Shares
(000s)
Weighted-Average Remaining Contractual Life
 
Weighted-Average Exercise Price
Number of Shares
(000s)
Weighted-Average Exercise Price
$11.00 - $15.56
484
2 years
$14.29
484
$14.29
$16.78 - $18.84
572
4 years
$18.01
572
$18.01
$30.55 - $37.88
395
8.7 years
$34.35
 82
$31.76

We summarize the status of nonvested stock options as of December 31, 2007, and changes during 2007 below:

Nonvested Shares
  
Number of Shares
(000s)
  
Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2007
  
194
  
$7.38
  Granted
  
184
  
$8.13
  Vested
  
  (66)
  
$7.39
Nonvested at December 31, 2007
  
312
  
$7.83

RESTRICTED STOCK UNITS/AWARDS AND PERFORMANCE SHARES

Restricted Stock Units

 Restricted stock and stock units are generally granted under the Plan to non-employee directors.  Restricted stock is an award of Common Stock that is subject to forfeiture if the restrictions specified in the award are not satisfied.  Stock units are a non-voting unit of measure that is equivalent to one share of Common Stock.  The directors may elect to receive stock units in lieu of restricted stock.  Restricted stock generally vests over periods ranging from one to three years and are payable in Common Stock.  Stock units vest either immediately or over periods ranging from one to three years.  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.  Compensation expense is recognized when dividends are paid.

In 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 17,857 stock units at a weighted average fair value of $37.30 per share to non-employee directors.  In 2006, we granted 17,151 stock units to non-employee directors at a weighted-average fair value of $30.76 per share on the grant date.  In 2005, we granted 13,213 stock unit awards at a weighted-average fair value of $29.72 per share on the grant date.

Restricted Stock Awards

We did not grant any restricted stock awards in 2007 or 2006.  In 2005, we granted 3,264 restricted stock awards to non-employee directors at a fair value of $24.51 per share on the grant date. These awards vest over 3 years.
 
 
Performance Share Awards

On March 20, 2007, the Compensation Committee of the UniSource Energy Board of Directors granted 37,270 performance share awards (targeted shares) to certain officers at a grant date fair value of $35.56 per share (market price of $37.88 less the present value of expected dividends of $2.32).  The performance share awards will be paid out in shares of UniSource Energy Common Stock based on UniSource Energy’s performance over the performance period of January 1, 2007 through December 31, 2009.

In May 2006, 45,520 performance share awards (targeted shares) were granted to certain officers at a grant date fair value of $28.39 per share (market price of $30.55 less the present value of expected dividends of $2.16). The performance share awards will be paid out in shares of UniSource Energy Common Stock based on UniSource Energy’s performance over the period of January 1, 2006 through December 31, 2008.

The performance criteria specified in the awards is determined based on targeted UniSource Energy cumulative Diluted Earnings per Share and cumulative Cash Flow from Operations during the performance period.  The performance shares vest ratably over the performance period and any unearned awards are forfeited.  Compensation expense equal to the fair market value on the grant date less the present value of expected dividends is recognized over the vesting period if it is probable that the performance criteria will be met.
 
   
Performance Shares
  
Restricted Stock Units
   
 
 
Shares (000s)
  
Weighted-
Average
 Grant-Date
 Fair Value
  
 
 
Shares (000s)
  
Weighted-
Average
Grant-Date
Fair Value
Non-vested at January 1, 2007
  
41
  
$28.39
  
21
  
$28.68
   Granted
  
37
  
$35.56
  
18
  
$37.30
   Vested
  
 -
  
-
  
(19)
  
$29.17
   Forfeited
  
  (6)
  
$32.52
        
Non-vested at December 31, 2007
  
72
  
$31.77
  
20
  
$35.91
 
SHARE-BASED COMPENSATION EXPENSE (Stock Options, Performance Shares and Restricted Stock Units)

Annually during 2005 through 2007, TEP recorded share-based compensation expense of $2 million.  UniSource Energy recorded share-based compensation expense of $3 million in 2007 and $2 million annually in 2006 and 2005.  The actual tax deduction realized from the exercise of share-based payment arrangements totaled $0.5 million in 2007, $2 million in 2006, and $3 million in 2005.  We did not capitalize any share-based compensation costs.

At December 31, 2007, 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 March 2010. The total number of shares awarded but not yet issued, including target performance based shares, under the share-based compensation plans at December 31, 2007 was 2 million.


NOTE 13.  UNISOURCE ENERGY EARNINGS PER SHARE (EPS)

We compute basic EPS by dividing Net Income by the weighted average number of common shares outstanding during the period.  Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options, contingently issuable shares under equity-based awards or common shares that would result from the conversion of convertible notes.  The numerator in calculating diluted earnings per share is Net Income adjusted for the interest on convertible notes (net of tax) that would not be paid if the notes were converted to common shares.

The following table shows the effects of potential dilutive common stock on the weighted average number of shares:
 
 
   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
Numerator
  
- In Thousands -
  
Net Income
   $ 58,373     $ 67,447     $ 46,144  
Income from Assumed Conversion of Convertible Senior Notes
     4,390       4,390       3,654  
Adjusted Numerator
   $ 62,763     $ 71,837     $ 49,798  
                         
Denominator:
                        
Weighted-average Shares of Common Stock Outstanding
     35,486       35,264       34,798  
Effect of Diluted Securities
                        
Convertible Senior Notes
     4,000       4,000       3,345  
Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan
     583       601       708  
Total Shares
     40,069       39,865       38,851  
 
Stock options to purchase an average of 169,000 and 67,000 shares of Common Stock were outstanding during 2007 and 2006, respectively, but were not included in the computation of EPS because the stock option’s exercise price was greater than the average market price of the Common Stock at year end.  There were no outstanding options excluded from the computation of EPS during the year ended December 31, 2005.


NOTE 14.  RELATED PARTIES

UniSource Energy incurs corporate costs that are allocated to its subsidiaries, including TEP.  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 and its other affiliates would have incurred as stand-alone entities.  Charges allocated to TEP were $7 million each in 2007 and 2006, and $5 million in 2005.  Charges allocated to UNS Gas and UNS Electric were $1 million each in 2007 and 2006 and $0.5 million each in 2005.

TEP provides all corporate services (finance, accounting, tax, information technology services, etc.) to UniSource Energy, UNS Gas and UNS Electric as well as to UniSource Energy’s non-utility businesses.  Costs are directly assigned to the benefiting entity where possible.  Common costs are allocated on a cost-causative basis.  Management believes this method of allocation is reasonable.  The charges by TEP to the other companies were $14 million in 2007, $9 million in 2006, and $8 million in 2005.

Global Solar, previously Millennium’s largest subsidiary, develops and manufactures light weight thin-film photovoltaic cells and panels.  Global Solar is reflected in these financial statements as discontinued operations.  See Note 15.  Global Solar did not record any revenue from transactions with TEP in 2006.  Global Solar recorded revenue from transactions with TEP of less than $1 million in 2005.

Southwest Energy Solutions, Inc. (SES), a subsidiary of Millennium, provides a supplemental workforce for TEP and UNS Electric.  Types of services provided for TEP include dusk to dawn lighting, facilities maintenance, meter reading, transmission and distribution, line locating, and general supplemental support.   SES bills TEP for these services. Management believes that the charges for services are reasonable and approximate the cost that TEP would have incurred if it performed these services directly.  SES charged TEP $14 million in 2007, $14 million in 2006, and $12 million in 2005 for these services.  SES provides meter reading services for UNS Electric.  SES charged UNS Electric $1 million for these services in 2007, 2006 and 2005.

Haddington Energy Partners II, LP (Haddington) funds energy-related investments.  A member of the UniSource Energy Board of Directors had an investment in Haddington but redeemed his interest in that investment in 2007 and no longer has any role with respect to Haddington other than the right to receive a certain percentage of proceeds from a disposition of remaining Haddington assets.

Carboelectrica Sabinas, S. de R.L. de C.V. (Sabinas) is a Mexican limited liability company created to develop up to 800 megawatts (MW) of coal-fired generation in the Sabinas region of Coahuila, Mexico.   Millennium owns 50% of Sabinas.  Altos Hornos de Mexico, S.A. de C.V. (AHMSA) and affiliates own the other 50%.  UniSource Energy’s Chairman, President and Chief Executive Officer is on the board of directors of AHMSA.  As of December 31, 2007, Millennium’s remaining investment in Sabinas is $14 million.
 

NOTE 15.  DISCONTINUED OPERATIONS

In January 2006, UniSource Energy’s Board of Directors approved a plan to dispose of its investment in Global Solar to a third party.  Global Solar appears in these financial statements as discontinued operations.

On March 31, 2006, UniSource Energy sold all of the capital stock of Global Solar to a third party.  UniSource Energy received $16 million in cash as part of the transaction; a portion of the proceeds was used to satisfy $10 million of secured promissory notes held by a UniSource Energy subsidiary.  In addition to the cash purchase price, UniSource Energy received a ten-year option to purchase between 5 and 10 percent of the common stock of Global Solar.  The option is only exercisable after the seventh anniversary of the closing or upon the occurrence of certain events including a sale of all or substantially all of the assets of Global Solar, a merger, a change of control transaction, an initial public offering of Global Solar common stock or the payment by Global Solar of dividends in excess of specified amounts.  For accounting purposes, no value was assigned to this repurchase option.

Listed below are the major classes of assets and liabilities related to the sale of Global Solar as of December 31:

   
2005
  
   
-Millions of Dollars-
  
Assets
      
Property, Plant and Equipment, net
   $ 10  
Goodwill
     3  
Noncurrent Assets of Subsidiary Held for Sale
   $ 13  
         
Trade Accounts Receivable
   $ 1  
Inventory
     4  
Deferred Income Taxes - Current
     12  
Current Assets of Subsidiary Held for Sale
   $ 17  
         
Liabilities
        
Accounts Payable
   $ 2  
Current Liabilities of Subsidiary Held for Sale
   $ 2  

The following summarizes the amounts included in Discontinued Operations – Net of Tax for all periods presented

   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Millions of Dollars-
  
Revenues from Discontinued Operations
   $ -     $ 1     $ 5  
                         
Loss from Discontinued Operations Before Income Taxes
     -       (4 )     (10 )
Income Tax Benefit
     -       (2 )     (5 )
Discontinued Operations – Net of Tax
   $ -     $ (2 )   $ (5 )
 

NOTE 16.  SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of net income to net cash flows from operating activities follows:
 
   
UniSource Energy
  
    Years Ended December 31,  
    2007      2006        2005   
   
-Thousands of Dollars-
 
Net Income
 $ 58,373   $ 67,447     $ 46,144  
Adjustments to Reconcile Net Income
                    
  To Net Cash Flows from Operating Activities
                    
     Depreciation and Amortization Expense
   140,638     130,502       132,577  
     Depreciation and Amortization Recorded to Fuel and Other O&M Expense
   6,897     7,604       6,496  
     Amortization of Transition Recovery Asset
   77,681     65,985       56,418  
     Mark-to-Market Transactions
   2,459     (929 )     1,259  
     Net Unrealized Loss (Gain) on MEG Trading Activities
   2,562     9,955       (10,764 )
     Amortization of Deferred Debt-Related Costs included in
                    
  Interest Expense
   3,831     4,622       4,730  
Loss on Extinguishment of Debt
   -     1,080       5,261  
Provision for Bad Debts
   3,592     3,439       2,696  
     Deferred Income Taxes
   22,021     (5,530 )     7,851  
     Pension and Postretirement Expense
   14,442     17,753       18,050  
     Pension and Postretirement Funding
   (13,809 )   (12,557 )     (14,465 )
     Share Based Compensation Expense
   2,693     2,276       780  
     Excess Tax Benefit from Stock Option Exercises
   (541 )   (1,501 )     (2,527 )
     Changes in Assets and Liabilities which Provided (Used)
                    
       Cash Exclusive of Changes Shown Separately
                    
         Accounts Receivable
   4,981     (33,335 )     985  
         Materials and Fuel Inventory
   (8,805 )   (7,912 )     (8,433 )
         Over/Under Recovered Purchased Gas Cost
   2,377     4,808       (4,037 )
         Accounts Payable
   (5,057 )   9,163       (3,516 )
         Income Taxes Payable
   (2,895 )   (11,896 )     13,598  
         Interest Accrued
   10,031     7,814       8,282  
         Taxes Other Than Income Taxes
   1,344     453       541  
     Other
   (49 )   24,332       11,999  
     Cumulative Effect of Accounting Change-Net of Tax
   -     -       626  
     Discontinued Operations – Net of Tax
   -     1,796       5,483  
     Net Cash Used by Operating Activities of Discontinued Operations
   -     (2,710 )     (6,151 )
Net Cash Flows – Operating Activities
 $ 322,766   $ 282,659     $ 273,883  
 
 
 
TEP
  
 
Years Ended December 31,
  
 
2007
  
2006
    
2005
  
 
-Thousands of Dollars-
  
               
Net Income
 $ 53,456   $ 66,745     $ 48,267  
Adjustments to Reconcile Net Income
                    
  To Net Cash Flows from Operating Activities
                    
     Depreciation and Amortization Expense
   119,811     112,346       114,704  
  Depreciation and Amortization Recorded to Fuel and Other O&M Expense
   5,339     6,320       6,417  
     Amortization of Transition Recovery Asset
   77,681     65,985       56,418  
     Mark-to-Market Transactions
   2,459     (929 )     1,259  
     Amortization of Deferred Debt-Related Costs included in
                    
       Interest Expense
   2,677     3,356       3,687  
Loss on Extinguishment of Debt
   -     685       5,261  
Provision for Bad Debts
   2,161     1,869       1,964  
     Deferred Income Taxes
   8,310     (233 )     6,555  
     Pension and Postretirement Expense
   12,683     16,050       16,270  
     Pension and Postretirement Funding
   (12,479 )   (11,133 )     (12,893 )
     Share Based Compensation Expense
   2,097     1,799       621  
     Interest Accrued on Note Receivable from UniSource Energy
   -     -       (1,684 )
     Changes in Assets and Liabilities which Provided (Used)
                    
       Cash Exclusive of Changes Shown Separately
                    
         Accounts Receivable
   4,013     (45,185 )     (6,779 )
         Materials and Fuel Inventory
   (9,103 )   (5,814 )     (6,608 )
         Accounts Payable
   (6,230 )   22       (4,790 )
         Interest Accrued
   10,113     8,191       5,295  
         Interest Received from UniSource Energy
   -     -       11,013  
         Income Taxes Receivable/Payable
   (3,378 )   (8,702 )     (704 )
         Taxes Other Than Income Taxes
   1,463     (33 )     137  
     Other
   (6,961 )   15,889       (2,023 )
     Cumulative Effect of Accounting Change-Net of Tax
   -     -       626  
Net Cash Flows – Operating Activities
 $ 264,112   $ 227,228     $ 243,013  

Non-cash investing and financing activities of UniSource Energy and TEP that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

   
Years Ended December 31,
  
   
2007
    
2006
    
2005
  
   
-Thousands of Dollars-
  
                   
Additions to Utility Plant
   $ 24,915     $ (3,434 )   $ 9,439  
Net Cost of Removal of Interim Retirements
     21,301       6,859       10,367  
Capital Lease Obligations
     13,259       12,808       12,720  
Preliminary Engineering Fees
     212       -       3,691  

The non-cash additions to Utility Plant represent accruals for capital expenditures.

The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations.

The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments in 2007, 2006 and 2005.

The non-cash preliminary engineering fees represent costs incurred related to potential capital projects that are recorded in other assets and subsequently reclassified to construction work in progress upon affirmation the capital project will be undertaken.
 
 
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 months and peak sales periods for UNS Gas generally occur during the winter months.  Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
 
   
UniSource Energy
  
   
First
    
Second
    
Third
    
Fourth
  
2007
  
-Thousands of Dollars-
(except per share data)
  
                         
Operating Revenue
   $ 317,841     $ 329,772     $ 398,204     $ 335,556  
Operating Income
     38,199       47,131       71,608       55,967  
Net Income
     4,943       11,806       25,417       16,207  
Basic EPS
     0.14       0.33       0.72       0.46  
Diluted EPS
     0.14       0.32       0.66       0.43  
                                 
2006
                                
                                 
Operating Revenue
   $ 305,426     $ 315,391     $ 369,768     $ 317,556  
Operating Income
     64,088       47,791       80,635       47,632  
Income Before Discontinued Operations
     19,491       9,998       28,203       11,551  
Discontinued Operations – Net of Tax
     (2,669 )     -       -       873  
Net Income
     16,822       9,998       28,203       12,424  
Basic EPS
                                
Income Before Discontinued Operations
     0.56       0.28       0.80       0.33  
Discontinued Operations – Net of Tax
     (0.08 )     -       -       0.02  
Net Income
     0.48       0.28       0.80       0.35  
Diluted EPS
                                
Income Before Discontinued Operations
     0.52       0.28       0.73       0.32  
Discontinued Operations – Net of Tax
     (0.07 )     -       -       0.02  
Net Income
     0.45       0.28       0.73       0.34  
 
   
TEP
  
   
First
    
Second
    
Third
    
Fourth
  
2007
  
-Thousands of Dollars-
  
                         
Operating Revenue
   $ 219,629     $ 268,371     $ 328,841     $ 253,662  
Operating Income
     27,099       45,420       68,020       48,519  
                                 
Net Income
     821       12,271       25,959       14,405  
                                 
2006
                                
                                 
Operating Revenue
   $ 208,815     $ 249,629     $ 298,093     $ 232,457  
Operating Income
     53,971       44,955       77,493       39,232  
                                 
Net Income
     16,587       11,220       29,601       9,337  
 
EPS is computed independently for each of the quarters presented.  Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.

The principal unusual items for TEP and UniSource Energy include:
 

UniSource Energy and TEP
 
·
Fourth Quarter 2007:  In the fourth quarter of 2007, TEP recorded adjustments relating to periods prior to the fourth quarter of 2007 which decreased net income by less than $0.5 million.

UniSource Energy
  ·  
First Quarter 2006:  On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar at a future date.  The option is exercisable, upon the occurrence of certain events, beginning in April 2013 and expires in April 2016.  In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar.


UniSource Energy
Schedule II - Valuation and Qualifying Accounts

 
 
Description
  
Beginning Balance
    
Additions- Charged to Income
    
 
Deductions
    
Ending Balance
  
Year Ended December 31,
  
-Millions of Dollars-
  
       
Deferred Tax Assets Valuation Allowance (1)
                        
2007
   $ -     $ -     $ -     $ -  
2006
     7       -       7       -  
2005
     8       -       1       7  
                                 
Allowance for Doubtful Accounts (2)
                                
2007
   $ 17     $ 4     $ 3     $ 18  
2006
     15       4       2       17  
2005
     17       3       5       15  
                                 
 
 (1) The deferred tax assets valuation allowance reduced the deferred tax asset balance.  It related to NOL and ITC carryforward amounts.  The $7 million valuation allowance at December 31, 2005, relates to losses generated by Global Solar.  Global Solar was sold in March 2006 and is no longer included in our consolidated tax returns.  The decrease in 2005 of $1 million relates to TEP’s anticipated utilization of ITC carryforward.

(2) TEP, UNS Gas and UNS Electric record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified.  Deductions principally reflect amounts charged off as uncollectible, less amounts recovered.  Balances related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001.  See Note 5.
 
TEP
Schedule II - Valuation and Qualifying Accounts

 
 
Description
  
Beginning Balance
    
Additions- Charged to Income
    
 
Deductions
    
Ending Balance
  
Year Ended December 31,
  
-Millions of Dollars-
  
       
Deferred Tax Assets Valuation Allowance (1)
                        
2007
   $ -     $ -     $ -     $ -  
2006
     -       -       -       -  
2005
     1       -       1       -  
                                 
Allowance for Doubtful Accounts (2)
                                
2007
   $ 16     $ 2     $ 1     $ 17  
2006
     15       2       1       16  
2005
     14       2       1       15  
                                 
 
 
(1) The deferred tax assets valuation allowance reduced the deferred tax asset balance.  It related to NOL and ITC carryforward amounts.  The 2005 reduction of $1 million related to TEP’s anticipated utilization of ITC carryforwards.

(2)  TEP records additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified.  Deductions principally reflect amounts charged off as uncollectible, less amounts recovered.  Balances related primarily to TEP reserves for sales to the CPX and CISO in 2000 and 2001.  See Note 5.
 
 

ITEM 9. – CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.

 
ITEM 9A. – CONTROLS AND PROCEDURES

UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of December 31, 2007.  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 2007, 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 2007 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.

ITEM 9B. – OTHER INFORMATION

The Board of Directors of UniSource Energy amended Article VII of its By-laws (the "By-laws"), effective as of February 27, 2008, to allow for the issuance of uncertificated shares. By being able to issue uncertificated shares, UniSource Energy may now participate in the Direct Registration System, which is currently administered by The Depository Trust Company. The Direct Registration System allows investors to have securities registered in their names without the issuance of physical certificates and allows investors to electronically transfer securities to broker-dealers in order to effect transactions without the risks and delays associated with transferring physical certificates.

The full text of the By-laws, as amended, is filed as Exhibit 3(d) to this Annual Report.

 

ITEM 10. – DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
 
Directors

Certain of the individuals serving as Directors of UniSource Energy also serve as the Directors of TEP. Information concerning Directors will be contained under Election of Directors in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.

Executive Officers – UniSource Energy

Executive Officers of UniSource Energy, who are elected annually by UniSource Energy’s Board of Directors, are as follows:

 
 
Name
 
 
Age
 
 
Position(s) Held
 
Executive Officer Since
James S. Pignatelli
64
Chairman, President and Chief Executive Officer
1998
Michael J. DeConcini
43
Senior Vice President and Chief Operating Officer, Transmission and Distribution
1999
Raymond S. Heyman
52
Senior Vice President and General Counsel
2005
Kevin P. Larson
51
Senior Vice President, Chief Financial Officer and Treasurer
2000
Kentton C. Grant
49
Vice President, Finance and Rates
2007
Arie Hoekstra
60
Vice President, Generation
2007
David G. Hutchens
41
Vice President, Wholesale Energy
2007
Karen G. Kissinger
53
Vice President, Controller and Chief Compliance Officer
1998
Steven W. Lynn
61
Vice President, Communications and Government Relations
2003
Thomas A. McKenna
59
Vice President, Engineering
2007
Catherine E. Ries
48
Vice President, Human Resources
2007
Herlinda H. Kennedy
46
Corporate Secretary
2006

James S. Pignatelli
Mr. Pignatelli joined TEP as Senior Vice President in August 1994 and was elected Senior Vice President and Chief Operating Officer in 1996. He was named Senior Vice President and Chief Operating Officer of UniSource Energy in January 1998, and Executive Vice President and Chief Operating Officer of TEP in March 1998. On June 23, 1998, Mr. Pignatelli was named Chairman, President and CEO of UniSource Energy and TEP. Prior to joining TEP, he was President and Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a subsidiary of SCE Corp.

Michael J. DeConcini
Mr. DeConcini joined TEP in 1988 and served in various positions in finance, strategic planning and wholesale marketing. He was Manager of TEP’s Wholesale Marketing Department in 1994, adding Product Development and Business Development in 1997. In November 1998, he was elected Vice President of MEH and elected Vice President, Strategic Planning of UniSource Energy in February 1999. He was named Senior Vice President, Investments and Planning of UniSource Energy in October 2000. Mr. DeConcini was elected Senior Vice President and Chief Operating Officer of the Energy Resources business unit of TEP, effective January 1, 2003.  In August 2006, he was named Senior Vice President and Chief Operating Officer, Transmission and Distribution.

Raymond S. Heyman
Mr. Heyman was elected to the position of Senior Vice President and General Counsel of TEP and UniSource Energy in September 2005.  Prior to joining TEP, Mr. Heyman was a  member from 1995 - 2005 of the Phoenix, Arizona law firm Roshka, Heyman & DeWulf, PLC, and has represented UniSource Energy, TEP and UES in proceedings before the Arizona Corporation Commission, as well as in other legal and regulatory matters.
 

Kevin P. Larson
Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and at TEP’s investment subsidiaries. In January 1991, he was elected Assistant Treasurer of TEP and named Manager of Financial Programs. He was elected Treasurer of TEP in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer of both UniSource Energy and TEP and remains Treasurer of both organizations.  He was named Senior Vice President in September 2005.

Kentton C. Grant
Mr. Grant joined TEP in 1995 and was named Director of Capital Resources and Assistant Treasurer in 1997.  He was promoted to Manager of Financial Planning in 1998 and General Manager of Financial Planning in 2003.  In January 2007, Mr. Grant was elected Vice President of Finance and Rates at UniSource Energy and TEP. Prior to joining TEP, Mr. Grant worked as a staff member at the Public Utility Commission of Texas.

Arie Hoekstra
Mr. Hoekstra joined TEP in 1979 as a Maintenance Superintendent.  He was promoted to Manager of Tucson Power Production in 1983 and Manager of Springerville Power Production in 1995.  He was named General Manager of Energy Resources – Power Production in 2003.  In January 2007, Mr. Hoekstra was elected Vice President of Generation at UniSource Energy and TEP. Prior to joining TEP, Mr. Hoekstra worked in various roles for Arizona Public Service Company and Westinghouse Electric Corporation.

David G. Hutchens
Mr. Hutchens joined TEP in 1995 and was named Supervisor of Wholesale Power Operations in 1999.  He was promoted to Manager of Wholesale Marketing in 2001 and General Manager of Fuels and Wholesale Power in 2003.  In January 2007, Mr. Hutchens was elected Vice President of Wholesale Marketing at UniSource Energy and TEP, and Vice President of UNS Gas. Prior to joining TEP, Mr. Hutchens served in the United States Navy, achieving the rank of Lieutenant.

Karen G. Kissinger
Ms. Kissinger joined TEP as Vice President and Controller in January 1991. She was named Vice President, Controller and Principal Accounting Officer of UniSource Energy in January 1998. In November 1998, Ms. Kissinger was also named Chief Information Officer of TEP. She was named Chief Compliance Officer of UniSource Energy and TEP, effective January 1, 2003.

Steven W. Lynn
Mr. Lynn joined TEP in 2000 as Manager of Corporate Relations for UniSource Energy and was named Manager of Corporate Relations of both TEP and UniSource Energy during 2000.  In January 2003, he was elected Vice President of Communications and Government Relations at UniSource Energy and TEP. Prior to joining TEP, Mr. Lynn was an owner-partner from 1984 - 2000 of Nordensson Lynn & Associates, Inc., a Tucson-based advertising, marketing and public relations firm.

Thomas A. McKenna
Mr. McKenna joined Nations Energy Corporation (a wholly-owned subsidiary of Millennium) in 1998, as Director of Project Development. In 2001, he was named Manager of Project Development for UniSource Energy.  In January 2007, Mr. McKenna was elected Vice President of Engineering at UniSource Energy and TEP, and Vice President of UNS Electric. Prior to joining UniSource Energy, Mr. McKenna was a Vice President of Sargent & Lundy Engineers.

Catherine E. Ries
Ms. Ries joined UniSource Energy and TEP in June 2007 as Vice President of Human Resources.  Prior to joining UniSource Energy and TEP, Ms. Ries worked for Clopay Building Products, a division of Griffon Corporation, from 2000-2007 and held the position of Vice President of Human Resources prior to joining UniSource Energy and TEP.  She also worked in various positions at America West Airlines from 1987-2000, now known as US Airways.

Herlinda H. Kennedy
Ms. Kennedy joined TEP as an administrative assistant in 1980. She was promoted to Assistant to the CEO in 1986.  Ms. Kennedy was named assistant Corporate Secretary of TEP and UniSource Energy in 1999 and was elected Corporate Secretary of UniSource Energy and TEP in September 2006.
 
 
Executive Officers - TEP

Executive Officers of TEP, who are elected annually by TEP’s Board of Directors, are:
 
 
Name
 
 
Age
 
 
Position(s) Held
Executive
Officer
Since
James S. Pignatelli
64
Chairman, President and Chief Executive Officer
1994
Michael J. DeConcini
43
Senior Vice President and Chief Operating Officer, Transmission and Distribution
2003
Raymond S. Heyman
52
Senior Vice President and General Counsel
2005
Kevin P. Larson
51
Senior Vice President, Chief Financial Officer and Treasurer
1994
Kentton C. Grant
49
Vice President, Finance and Rates
2007
Thomas N. Hansen
57
Vice President, Environmental Services, Conservation and Renewable Energy
1992
Arie Hoekstra
60
Vice President, Generation
2007
David G. Hutchens
41
Vice President, Wholesale Energy
2007
Karen G. Kissinger
53
Vice President, Controller and Chief Compliance Officer
1991
Steven W. Lynn
61
Vice President, Communications and Government Relations
2003
Thomas A. McKenna
59
Vice President, Engineering
2007
Catherine E. Ries
48
Vice President, Human Resources
2007
Herlinda H. Kennedy
46
Corporate Secretary
2006

James S. Pignatelli
See description shown under UniSource Energy Corporation above.

Michael J. DeConcini
See description shown under UniSource Energy Corporation above.

Raymond S. Heyman
See description shown under UniSource Energy Corporation above.

Kevin P. Larson
See description shown under UniSource Energy Corporation above.

Kentton C. Grant
See description shown under UniSource Energy Corporation above.

Thomas N. Hansen
Mr. Hansen joined TEP in December 1992 as Vice President, Power Production. Prior to joining TEP, Mr. Hansen was Century Power Corporation’s Vice President, Operations from 1989 and Plant Manager at Springerville from 1987 through 1988.  In 1994, he was named Vice President / Technical Advisor.  In 2007, he was named Vice President, Environmental Services, Conservation and Renewable Energy.

Arie Hoekstra
See description shown under UniSource Energy Corporation above.

David G. Hutchens
See description shown under UniSource Energy Corporation above.

Karen G. Kissinger
See description shown under UniSource Energy Corporation above.

Steven W. Lynn
See description shown under UniSource Energy Corporation above.

Thomas A. McKenna
See description shown under UniSource Energy Corporation above.

Catherine E. Ries
See description shown under UniSource Energy Corporation above.

Herlinda H. Kennedy
See description shown under UniSource Energy Corporation above.

Information required by Items 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.
 

ITEM 11. – EXECUTIVE COMPENSATION

Information concerning Executive Compensation will be contained in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.


ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 26, 2008, UniSource Energy had outstanding 35.4 million shares of Common Stock.  As of February 26, 2008, the number of shares of Common Stock beneficially owned by all directors and officers of UniSource Energy as a group amounted to approximately 5% of the outstanding Common Stock.

At February 26, 2008, 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 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.

Security Ownership of Management

Information concerning the security ownership of the Directors and Executive Officers of UniSource Energy and TEP will be contained in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.

Securities Authorized for Issuance Under Equity Compensation Plans

Information concerning securities authorized for issuance under equity compensation plans will be contained in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.


ITEM 13. – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information concerning certain relationships and related transactions, and director independence of UniSource Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks and Insider Participation in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.


ITEM 14. – PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning principal accountant fees and services will be contained in UniSource Energy’s Proxy Statement relating to the 2008 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2007, which information is incorporated herein by reference.
 


ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

     
Page
(a)
1.
Consolidated Financial Statements as of December 31, 2007 and 2006
and for Each of the Three Years in the Period Ended December 31, 2007
  
       
   
UniSource Energy Corporation
  
   
Report of Independent Registered Public Accounting Firm
78
   
Consolidated Statements of Income
81
   
Consolidated Statements of Cash Flows
82
   
Consolidated Balance Sheets
83
   
Consolidated Statements of Capitalization
85
   
Consolidated Statements of Changes in Stockholders’ Equity
86
   
Notes to Consolidated Financial Statements
93
       
   
Tucson Electric Power Company
  
   
Report of Independent Registered Public Accounting Firm
79
   
Consolidated Statements of Income
87
   
Consolidated Statements of Cash Flows
88
   
Consolidated Balance Sheets
89
   
Consolidated Statements of Capitalization
91
   
Consolidated Statements of Changes in Stockholders’ Equity
92
   
Notes to Consolidated Financial Statements
93
       
 
2.
Financial Statement Schedule
  
   
Schedule II
  
   
Valuation and Qualifying Accounts
142
       
 
3.
Exhibits
  
 
 Reference is made to the Exhibit Index commencing on page 154.


Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
UNISOURCE ENERGY CORPORATION
 
 
Date:  February 29, 2008
By: /s/
Kevin P. Larson
   
Kevin P. Larson
Senior Vice President and Principal Financial Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Date:  February 29, 2008
/s/
James S. Pignatelli*
   
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
 
Date:  February 29, 2008
/s/
Kevin P. Larson
   
Kevin P. Larson
Principal Financial Officer
 
Date:  February 29, 2008
/s/
Karen G. Kissinger*
   
Karen G. Kissinger
Principal Accounting Officer
 
Date:  February 29, 2008
/s/
Lawrence J. Aldrich*
   
Lawrence J. Aldrich
Director
 
Date: February 29, 2008
/s/
Barbara Baumann*
   
Barbara Baumann
Director
 
Date:  February 29, 2008
/s/
Larry W. Bickle*
   
Larry W. Bickle
Director
 
Date:  February 29, 2008
/s/
Elizabeth T. Bilby*
   
Elizabeth T. Bilby
Director
 
Date:  February 29, 2008
/s/
Harold W. Burlingame*
   
Harold W. Burlingame
Director
 
 
Date:  February 29, 2008
/s/
John L. Carter*
   
John L. Carter
Director
 
Date:  February 29, 2008
/s/
Robert A. Elliott*
   
Robert A. Elliott
Director
 
Date:  February 29, 2008
/s/
Daniel W.L. Fessler*
   
Daniel W.L. Fessler
 
Date:  February 29, 2008
/s/
Kenneth Handy*
   
Kenneth Handy
Director
 
Date:  February 29, 2008
/s/
Warren Y. Jobe*
   
Warren Y. Jobe
Director
 
Date:  February 29, 2008
/s/
Ramiro Peru*
   
Ramiro Peru
Director
 
Date:  February 29, 2008
/s/
Gregory A. Pivirotto*
   
Gregory Pivirotto
Director
 
Date:  February 29, 2008
/s/
Joaquin Ruiz*
   
Joaquin Ruiz
Director
 
Date:  February 29, 2008
By: /s/
Kevin P. Larson
   
Kevin P. Larson
As attorney-in-fact for each
of the persons indicated
 
 
SIGNATURES
 
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
TUCSON ELECTRIC POWER COMPANY
 
 
Date:  February 29, 2008
By: /s/
Kevin P. Larson
   
Kevin P. Larson
Senior Vice President and Principal Financial Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Date:  February 29, 2008
/s/
James S. Pignatelli*
   
James S. Pignatelli
Chairman of the Board, President and
Principal Executive Officer
 
Date:  February 29, 2008
/s/
Kevin P. Larson
   
Kevin P. Larson
Principal Financial Officer
 
Date:  February 29, 2008
/s/
Karen G. Kissinger*
   
Karen G. Kissinger
Principal Accounting Officer
 
Date:  February 29, 2008
/s/
Lawrence J. Aldrich*
   
Lawrence J. Aldrich
Director
 
Date: February 29, 2008
/s/
Barbara Baumann*
   
Barbara Baumann
Director
 
Date:  February 29, 2008
/s/
Larry W. Bickle*
   
Larry W. Bickle
Director
 
Date:  February 29, 2008
/s/
Elizabeth T. Bilby*
   
Elizabeth T. Bilby
Director
 
Date:  February 29, 2008
/s/
Harold W. Burlingame*
   
Harold W. Burlingame
Director
 
 
Date:  February 29, 2008
/s/
John L. Carter*
   
John L. Carter
Director
 
Date:  February 29, 2008
/s/
Robert A. Elliott*
   
Robert A. Elliott
Director
 
Date:  February 29, 2008
/s/
Daniel W.L. Fessler*
   
Daniel W.L. Fessler
 
Date:  February 29, 2008
/s/
Kenneth Handy*
   
Kenneth Handy
Director
 
Date:  February 29, 2008
/s/
Warren Y. Jobe*
   
Warren Y. Jobe
Director
 
Date:  February 29, 2008
/s/
Ramiro Peru*
   
Ramiro Peru
Director
 
Date:  February 29, 2008
/s/
Gregory A. Pivirotto*
   
Gregory Pivirotto
Director
 
Date:  February 29, 2008
/s/
Joaquin Ruiz*
   
Joaquin Ruiz
Director
 
Date:  February 29, 2008
By: /s/
Kevin P. Larson
   
Kevin P. Larson
As attorney-in-fact for each
of the persons indicated
 



 
*2(a)
--
Agreement and Plan of Exchange, dated as of March 20, 1995, between TEP, UniSource Energy and NCR Holding, Inc.

 
*3(a)
--
Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for year ended December 31, 1996, File No. 1-5924 -- Exhibit 3(a).)


 
*3(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).)


 
*4(a)(1)
--
Installment Sale Agreement, dated as of December 1, 1973, among the City of Farmington, New Mexico, Public Service Company of New Mexico and TEP. (Form 8-K for the month of January 1974, file No. 0-269 -- Exhibit 3.)

 
*4(a)(2)
--
Ordinance No. 486, adopted December 17, 1973, of the City of Farmington, New Mexico. (Form 8-K for the month of January 1974, File No. 0-269 -- Exhibit 4.)

 
*4(a)(3)
--
Amended and Restated Installment Sale Agreement dated as of April 1, 1997, between the City of Farmington, New Mexico and TEP relating to Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31,1997, File No. 1-5924 -- Exhibit 4(a).)

 
*4(a)(4)
--
City of Farmington, New Mexico Ordinance No. 97-1055, adopted April 17, 1997, authorizing Pollution Control Revenue bonds, 1997 Series A (Tucson Electric Power Company San Juan Project). (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(b).)

 
*4(b)(1)
--
Loan Agreement, dated as of October 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(a).)

 
*4(b)(2)
--
Indenture of Trust, dated as of October 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project).  (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 -- Exhibit 4(b).)

 
*4(b)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(3).)

 
*4(b)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Sundt Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(h)(4).)

 
*4(c)(1)
--
Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects).  (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(1).)
 

 
*4(c)(2)
--
Indenture of Trust dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects).  (Form 10-K for the year ended December 31, 1982, File No. 1-5924 -- Exhibit 4(k)(2).)

 
*4(c)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(3).)

 
*4(c)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(i)(4).)

 
*4(d)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(I)(1).)

 
*4(d)(2)
--
Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1983, File no. 1-5924 -- Exhibit 4(I)(2).)

 
*4(d)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(3).)

 
*4(d)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(k)(4).)

 
*4(d)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(5).)

 
*4(d)(6)
--
Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(k)(6).)

 
*4(e)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(1).)

 
*4(e)(2)
--
Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds.  1983 Series B (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(m)(2).)

 
*4(e)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Developmental Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(3).)
 

 
*4(e)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(I)(4).)

 
*4(e)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(5).)

 
*4(e)(6)
--
Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(I)(6).)

 
*4(f)(1)
--
Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form 10-K for year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(1).)

 
*4(f)(2)
--
Indenture of Trust dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1983, File No. 1-5924 -- Exhibit 4(n)(2).)

 
*4(f)(3)
--
First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(3).)

 
*4(f)(4)
--
First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 4(m)(4).)

 
*4(f)(5)
--
Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(5).)

 
*4(f)(6)
--    Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(m)(6).)

 
*4(g)
--
Reimbursement Agreement, dated as of September 15, 1981, as amended, between TEP and Manufacturers Hanover Trust Company.  (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 4(o)(4).)

 
*4(h)(1)
--
Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and TEP relating to Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(1).)

 
*4(h)(2)
--
Indenture of Trust dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project).  (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 4(r)(2).)
 

 
*4(h)(3)
--
First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and TEP relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(3).)

 
*4(h)(4)
--
First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project).  (Form S-4, Registration No. 33-52860 -- Exhibit 4(o)(4).)

 
*4(i)(1)
--
Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, Trustee.  (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(1).)

 
*4(i)(2)
--
Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series A, dated as of December 1, 1992.  (Form S-1, Registration No. 33-55732 -- Exhibit 4(r)(2).)

 
*4(i)(3)
--
Supplemental Indenture No. 2 creating a series of bonds designated Second Mortgage Bonds, Collateral Series B, dated as of December 1, 1997.  (Form 10-K for year ended December 31, 1997, File No. 1-5924 -- Exhibit 4(m)(3).)

 
*4(i)(4)
--
Supplemental Indenture No. 3 creating a series of bonds designated Second Mortgage Bonds, Collateral Series, dated as of August 1, 1998.  (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(c).)

 
*4(i)(5)
--
Supplemental Indenture No. 4 creating a series of bonds designated Second Mortgage Bonds, Collateral Series C, dated as of November 1, 2002.  (Form 8-K dated November 27, 2002, File Nos. 1-05924 and 1-13739 -- Exhibit 99.2.)

 
*4(i)(6)
--
Supplemental Indenture No. 5 creating a series of bonds designated Second Mortgage Bonds, Collateral Series D, dated as of March 1, 2004.  (Form 8-K dated March 31, 2004, File Nos. 1-05924 and 1-13739 -- Exhibit 10 (b).)

 
*4(i)(7)
--
Supplemental Indenture No. 6 creating a series of bonds designated Second Mortgage Bonds, Collateral Series E, dated as of May 1, 2005.  (Form 10-Q for the quarter ended March 31, 2005, File Nos. 1-5924 and 1-13739 – Exhibit 4(b).)

 
*4(i)(8)
--
Supplemental Indenture No. 7 creating a series of bonds designated First Mortgage Bonds, Collateral Series F, dated as of December 1, 2006.  (Form 8-K dated December 22, 2006, File Nos. 1-5924 and 1-13739 – Exhibit 4.1.)

 
*4(j)(1)
--
Loan Agreement, dated as of April 1, 1997 between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project).  (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(c).)

 
*4(j)(2)
--
Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series A (Tucson Electric Power Company Navajo Project).  (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(d).)

 
*4(k)(1)
--
Loan Agreement, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project).  (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(e).)

 
*4(k)(2)
--
Indenture of Trust, dated as of April 1, 1997, between Coconino County, Arizona Pollution Control Corporation and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1997 Series B (Tucson Electric Power Company Navajo Project).  (Form 10-Q for the quarter ended March 31, 1997, File No. 1-5924 -- Exhibit 4(f).)
 

 
 *4(l)(1)
--
Loan Agreement, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(a).)

 
*4(l)(2)
--
Indenture of Trust, dated as of September 15, 1997, between The Industrial Development Authority of the County of Pima and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1997 Series A (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended September 30, 1997, File No. 1-5924 -- Exhibit 4(b).)

 
*4(m)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(a).)

 
*4(m)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series A (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(b).)

 
*4(n)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(c).)

 
*4(n)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Pollution Control Revenue Bonds, 1998 Series B (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(d).)

 
*4(o)(1)
--
Loan Agreement, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and TEP relating to Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(e).)

 
*4(o)(2)
--
Indenture of Trust, dated as of March 1, 1998, between The Industrial Development Authority of the County of Apache and First Trust of New York, National Association, authorizing Industrial Development Revenue Bonds, 1998 Series C (Tucson Electric Power Company Project).  (Form 10-Q for the quarter ended March 31, 1998, File No. 1-5924 -- Exhibit 4(f).)

 
*4(p)(1)
--
Indenture of Trust, dated as of August 1, 1998, between TEP and the Bank of Montreal Trust Company.  (Form 10-Q for the quarter ended June 30, 1998, File No. 1-5924 -- Exhibit 4(d).)

 
*4(q)(1)
--
Rights Agreement dated as of March 5, 1999, between UniSource Energy Corporation and The Bank of New York, as Rights Agent.  (Form 8-K dated March 5, 1999, File No. 1-13739 -- Exhibit 4.)

 
*4(r)(1)
--
Amended and Restated TEP Credit Agreement dated as of August 11, 2006, among TEP, the Lenders Party Thereto, the Issuing Banks Party Thereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.3.)

 
*4(r)(2)
--
Amendment No. 1 to Amended and Restated TEP Credit Agreement, dated September 1, 2006.  (Form 10-Q for the quarter ended September 30, 2006, File No. 1-5924 – Exhibit 4.)
 

 
*4(s)(1)
--
Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.2.)

 
*4(t)(1)
--
Note Purchase and Guaranty Agreement date August 11, 2003 among UNS Electric, Inc., and UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 -- Exhibit 99.3.)

 
*4(u)(1)
--
Indenture dated as of March 1, 2005, to The Bank of New York, as Trustee.  (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1).

 
*4(v)(1)
--
Registration Rights Agreement dated as of March 1, 2005, between UniSource Energy Corporation and Credit Suisse First Boston LLC, as representative of the several initial purchasers.  (Form 8-K dated March 3, 2005, File Nos. 1-5924 and 1-13739 -- Exhibit 4.2).

 
*4(w)(1)
--
Amended and Restated Credit Agreement dated as of August 11, 2006, among UniSource Energy, the Lenders Party Hereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.1.)

 
*4(x)(1)
--
Amended and Restated Credit Agreement dated as of August 11, 2006, among UNS Electric and UNS Gas, UniSource Energy Services as Guarantor, and the Banks Named Herein and the Other Lenders from Time to Time party Hereto, Union Bank of California, N.A., as Lead Arranger and Administrative Agent, The Bank of New York and JPMorgan Chase, N.A., as Co-Syndication Agents, and Wells Fargo Bank, National Association, and ABN Amro Bank N.V. as Co-Documentation Agents. (Form 8-K dated August 15, 2006, File Nos. 1-5924 and 1-13739 -- Exhibit 4.4.)

 
*10(a)(1)
--
Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented.  (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(1).)

 
*10(a)(2)
--
Guaranty and Agreements, dated as of December 1, 1984, between TEP and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee.  (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(2).)

 
*10(a)(3)
--
General Indemnity Agreements, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee.  (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(3).)

 
*10(a)(4)
--
Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and TEP, Indemnitors.  (Form 10-K for the year ended December 31, 1984, File No. 1-5924 -- Exhibit 10(d)(4).)

 
*10(a)(5)
--
Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(5).)
 

 
*10(a)(6)
--
Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(6).)

 
*10(a)(7)
--
Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-Trustee.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(7).)

 
*10(a)(8)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(8).)

 
*10(a)(9)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(9).)

 
*10(a)(10)
--
Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(10).)

 
*10(a)(11)
--
Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(11).)

 
*10(a)(12)
--
Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant.  (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(12).)

 
*10(a)(13)
--
Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant.  (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(13).)

 
*10(a)(14)
--
Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant.  (Form 10-K for the year ended December 31, 1988, File No. 1-5924 -- Exhibit 10(f)(14).)

 
*10(a)(15)
--
Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar).  (Form S-4 Registration No. 33-52860 -- Exhibit 10(f)(15).)

 
*10(a)(16)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(12).)
 

 
*10(a)(17)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(13).)

 
*10(a)(18)
--
Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(14).)

 
*10(a)(19)
--
Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(19).)

 
*10(a)(20)
--
Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form S-4, Registration No. 33-52860 --Exhibit 10(f)(20).)

 
*10(a)(21)
--
Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(21).)

 
*10(a)(22)
--
Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.   (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(22).)

 
*10(a)(23)
--
Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(15).)

 
*10(a)(24)
--
Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.  (Form 10-K for the year ended December 31, 1986, File No. 1-5924 -- Exhibit 10(e)(16).)

 
*10(a)(25)
--
Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.  (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(25).)
 

 
*10(a)(26)
--
Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station.  (Form S-4, Registration No. 33-52860 -- Exhibit 10(f)(26).)

 
*10(a)(27)
--
Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(f)(27).)

 
*10(b)(1)
--
Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented.  (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(1).)

 
*10(b)(2)
--
Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee.  (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(2).)

 
*10(b)(3)
--
Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee.  (Form 10-K for the year ended December 31, 1985, File No. 1-5924 -- Exhibit 10(f)(3).)

 
*10(b)(4)
--
Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(4).)

 
*10(b)(5)
--
Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar).  (Form S-4, Registration No. 33-52860 -- Exhibit 10(g)(5).)

 
*10(b)(6)
--
Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(6).)

 
*10(b)(7)
--
Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(g)(7).)
 

 
*10(b)(8)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(8).)

 
*10(b)(9)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(9).)

 
*10(b)(10)
--
Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(10).)

 
*10(b)(11)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(11).)

 
*10(b)(12)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(12).)

 
*10(b)(13)
--
Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.  (Form 10-K for the year ended December 31, 1999, File No. 1-5924 -- Exhibit 10(b)(13).)

 
*10(b)(14)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant.  (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(a).)

 
*10(b)(15)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant.  (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(b).)

 
*10(b)(16)
--
Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant.  (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(c).)
 

 
*10(b)(17)
--
Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor.  (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(d).)

 
*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.)
 

 
*10(c)(1)
--
Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Financial Security Assurance Inc., as Surety, Wilmington Trust Company and William J. Wade in their respective individual capacities as provided therein, but otherwise solely as Owner Trustee and Co-Trustee under the Trust Agreement, and Morgan Guaranty, in its individual capacity as provided therein, but Secured Party.  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(1).)

 
*10(c)(2)
--
Lease Agreement, dated as of January 14, 1988, between Wilmington Trust Company and William J. Wade, as Owner Trust Agreement described therein, dated as of November 15, 1987,between such parties and Ford Motor Credit Company, as Lessor, and TEP, as Lessee.  (Form 10-K for the year ended December 31, 1987, File No.1-5924 -- Exhibit 10(j)(2).)

 
*10(c)(3)
--
Tax Indemnity Agreement, dated as of January 14, 1988, between TEP, as Lessee, and Ford Motor Credit Company, as Owner Participant, beneficiary under a Trust Agreement, dated as of November 15, 1987, with Wilmington Trust Company and William J. Wade, Owner Trustee and Co-Trustee, respectively, together as Lessor.  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(3).)

 
*10(c)(4)
--
Loan Agreement, dated as of January 14, 1988, between the Pima County Authority and Wilmington Trust Company and William J. Wade in their respective individual capacities as expressly stated, but otherwise solely as Owner Trustee and Co-Trustee, respectively, under and pursuant to a Trust Agreement, dated as of November 15, 1987, with Ford Motor Credit Company as Trustor and Debtor relating to Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (TEP’s Sundt Project).  (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(4).)

 
*10(c)(5)
--
Indenture of Trust, dated as of January 14, 1988, between the Pima County Authority and Morgan Guaranty authorizing Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (Tucson Electric Power Company Sundt Project).   (Form 10-K for the year ended December 31, 1987, File No. 1-5924 -- Exhibit 10(j)(5).)

 
*10(c)(6)
--
Lease Amendment No. 1, dated as of May 1, 1989, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively under a Trust Agreement dated as of November 15, 1987 with Ford Motor Credit Company.  (Form 10-K for the year ended December 31, 1990, File No. 1-5924 -- Exhibit 10(i)(6).)

 
*10(c)(7)
--
Lease Supplement, dated as of January 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford.  (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(8).)

 
*10(c)(8)
--
Lease Supplement, dated as of March 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford.  (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(9).)

 
*10(c)(9)
--
Lease Supplement No. 4, dated as of December 1, 1991, between TEP, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford.  (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(i)(10).)

 
*10(c)(10)
--
Supplemental Indenture No. 1, dated as of December 1, 1991, between the Pima County Authority and Morgan Guaranty relating to Industrial Lease Development Obligation Revenue Project.   (Form 10-K for the year ended December 31, 1991, File No. 1-5924 -- Exhibit 10(l)(11).)

 
*10(c)(11)
--
Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and Morgan Guaranty, as Indenture Trustee and Refunding Trustee, relating to the restructuring of the Registrant’s lease of Unit 4 at the Sundt Generating Station.  (Form S-4, Registration No. 33-52860 -- Exhibit 10(i)(12).)
 

 
*10(c)(12)
--
Amendment No. 1, dated as of December 15, 1992, to Amended and Restated Participation Agreement, dated as of November 15, 1987, among TEP, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, Financial Security Assurance Inc., as Surety, and Morgan Guaranty, as Indenture Trustee.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(12).)

 
*10(c)(13)
--
Amended and Restated Lease, dated as of December 15, 1992, between TEP as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(13).)

 
*10(c)(14)
--
Amended and Restated Tax Indemnity Agreement, dated as of December 15, 1992, between TEP as Lessee and Ford Motor Credit Company, as Owner Participant.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(h)(14).)

 
*10(d)
--
Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(u).)

 
*10(e)
--
Lease Agreement, dated as of December 15, 1992, between TEP, as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(v).)

 
*10(f)
--
Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and TEP, as Lessee.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(w).)

 
*10(g)
--
Restructuring Agreement, dated as of December 1, 1992, between TEP and Century Power Corporation.  (Form S-1, Registration No. 33-55732 -- Exhibit 10(x).)

 
+*10(h)
--
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(l)
--
UniSource Energy Management and Directors Deferred Compensation Plan.  (Form S-8 dated May 21, 1998, File No. 333-53337.)

 
+*10(m)
--
Officer Change in Control Agreement between TEP and Karen G. Kissinger, dated as of December 4, 1998 (including a schedule of other officers who are covered by substantially identical agreements.)  (Form 10-K for the year ended December 31, 2004, File No. 1-5924 – Exhibit 10(p))

 
+*10(n)
--
Notice of Termination of Change in Control Agreement from TEP to Karen G. Kissinger, dated as of March 3, 2005 (including a schedule of other officers who received substantially identical notices.)  .)  (Form 10-K for the year ended December 31, 2004, File No. 1-5924 – Exhibit 10(q))
 

 
+*10(o)
--
Amended and Restated UniSource Energy 1994 Outside Director Stock Option Plan of UniSource Energy.  (Form S-8 dated September 9, 2002, File No. 333-99317.)

 
*10(p)(1)
--
Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Electric Utility Business in the State of Arizona.  (Form 8-K dated October 31, 2002.  File No. 1-13739 -- Exhibit 99-1.)

 
*10(p)(2)
--
Asset Purchase Agreement dated as of October 29, 2002, by and between UniSource Energy and Citizens Communications Company relating to the Purchase of Citizens’ Gas Utility Business in the State of Arizona.  (Form 8-K dated October 31, 2002.  File No. 1-13739 -- Exhibit 99-2.)

 
*+10(q)
--
UniSource Energy 2006 Omnibus Stock and Incentive Plan (Form S-8 dated January 31, 2007.  File No.  333-140353.)













(*) 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.