form8k.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

DATE OF REPORT
(DATE OF EARLIEST EVENT REPORTED):  July 2, 2007


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
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o       Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o       Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o       Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o       Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
 
 
Item 8.01 - Other Events.

TEP Files Rate Proposal Methodologies with the ACC

As previously reported, beginning in May 2005, Tucson Electric Power Company (TEP) filed a series of pleadings requesting the Arizona Corporation Commission (ACC) to resolve the uncertainties surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008.  In accordance with an ACC order in this proceeding, TEP filed the following rate proposal methodologies with the ACC to establish new rates for TEP when the existing rate increase moratorium of the 1999 Settlement Agreement (Settlement Agreement) is lifted on January 1, 2009:

Market Methodology

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

TEP’s 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, it is projected that the Market Methodology would result in an overall increase of approximately 22% over current rates.

Cost-of-Service Methodology

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

TEP’s rate base under this methodology would include an ICRA of $47 million amortized over four years to reflect the 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 the company is not permitted to charge market rates for generation service beginning in 2009.

Under this methodology, a Purchased Power and Fuel Adjustor Clause (PPFAC) would be implemented.  In addition, the costs of the Luna Energy Facility (Luna) is included in the PPFAC at $7 per KW-month for capacity plus the cost of fuel; 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, it is projected that the Cost-of-Service Methodology would result in an overall increase of approximately 23% over current rates.
 
 
Hybrid Methodology

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

The excluded generation assets consist of TEP’s interest in Navajo Generating Station 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 electricity generated 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, it is projected that the Hybrid Methodology would result in an 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 for deferral, while the $47 million ICRA in the Cost-of- Service and Hybrid Methodologies includes additional costs 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 forecasted fuel and purchased power costs for the following year.  For example, forecasts for fuel and purchased power in 2010 would be used to establish the PPFAC Forward Component for 2010.
 
 
 
·  
True-Up Component. This component would reflect the difference between actual fuel and purchase power costs less 90% of short-term wholesale revenues with the amount TEP collected through both base rates and the PPFAC rate in a given year.  In the Hybrid Methodology, TEP would offset 100% of short-term wholesale revenues against its actual fuel and purchased power costs to determine the True-Up Component.  If actual net 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.

The tables below summarize the major components for each of the rate methodologies.  All Methodologies reflect a pro forma capital structure of 45% equity and 55% debt, as well as a 10.75% return on equity.

 
Rate
Annual
Revenue
Annual
Revenue
 
Methodology
Increase
Requirement
Increase
PPFAC
 
 
  
 
 
Market
21.9%
 
$980 million
$172 million
None
Cost-of-Service
23%
 
$989 million
 
$181 million
Yes
Hybrid
14.9%
$925 million
$117 million
Yes

 
Rate of
 
Rate Base
  
Methodology
Return
OCRB1
RCND2
FVRB3
Rate Base Composition
Market
8.35%
$540 million
$1.01 billion
$777 million
 
Distribution and Local Generation assets
Cost-of-Service
8.35%
$983 million
$1.85 billion
$1.42 billion
 
Distribution and Generation assets
Hybrid
8.35%
$921 million
$1.71 billion
$1.31 billion
 
Distribution and Generation assets (excluding Navajo and Four Corners)


1 Original Cost Rate Base
2 Reconstructed Cost New Less Deprecation
3 Fair Value Rate Base as traditionally calculated by the ACC
 
 
TEP filed Demand-Side Management Portfolio and Renewable Energy Action Plan information in separate dockets as ordered by the ACC.  However, TEP is requesting that appropriate cost recovery mechanisms be established in this rate proposal proceeding so that TEP may recover its costs associated with those programs in a timely manner.  TEP is also requesting that the cost recovery mechanisms be in place prior to the implementation of any plans.

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 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 revenue collected as a result of retaining the Fixed CTC after it would otherwise terminate (approximately May 2008), 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.  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 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.   TEP cannot predict the outcome of these proceedings or whether any of its rate proposals will be adopted by the ACC in whole or in part.
 

 

SIGNATURES
 
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
     
 
    
Date: July 2, 2007
 
 
UNISOURCE ENERGY CORPORATION
——————————————————
(Registrant)
 
 
/ s /  Kevin P. Larson
 
 
——————————————————
Senior Vice President and Principal
Financial Officer
 
 
     
Date: July 2, 2007
 
 
TUCSON ELECTRIC POWER COMPANY
——————————————————
(Registrant)
 
 
/ s /  Kevin P. Larson
 
 
——————————————————
Senior Vice President and Principal
Financial Officer