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REGULATORY MATTERS
12 Months Ended
Dec. 31, 2013
Text Block [Abstract]  
REGULATORY MATTERS
REGULATORY MATTERS
The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP, UNS Electric, and UNS Gas. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and the pending merger. The FERC regulates terms and prices of transmission services and wholesale electricity sales, and the pending merger.
2013 TEP RATE ORDER
In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.
The provisions of the 2013 TEP Rate Order include, but are not limited to:
an increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues;
an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion;
a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%;
a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt;
a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million);
a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and
an agreement by TEP to seek recovery of costs related to the discontinued Nogales transmission project from the FERC before seeking rate recovery from the ACC.
The 2013 TEP Rate Order also includes the following cost recovery mechanisms:
a new Purchased Power and Fuel Adjustment Clause (PPFAC) credit of 0.1388 cents per kWh effective July 1, 2013. The credit reflects the following:
a reduction in the PPFAC bank balance, recorded in June 2013, as an increase to fuel expense, of $3 million related to prior sulfur credits; and
a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final settlement with the San Juan operator related to insurance proceeds.
a modification of the PPFAC mechanism to include recovery of generation-related lime costs offset by sulfur credits.
a Lost Fixed Cost Recovery mechanism (LFCR) to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation. In the fourth quarter of 2013, TEP recorded revenues of $2 million related to unrecovered non-fuel costs incurred during 2013.
an Environmental Compliance Adjustor (ECA) mechanism to recover certain capital carrying costs to comply with government-mandated environmental regulations between rate cases. The ECA rate is capped at 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues, and will be charged to customers beginning in May 2014 for any qualifying costs incurred between August 2013 and December 2013.
an energy efficiency provision which includes a 2013 calendar year budget of approximately $21 million to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a $2 million performance incentive.
2013 UNS ELECTRIC RATE ORDER
In December 2013, the ACC issued the 2013 UNS Electric Rate Order that resolved the rate case filed by UNS Electric in December 2012 which was based on a test year ended June 30, 2012. The 2013 UNS Electric Rate Order approved new rates effective January 1, 2014.
The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:
an increase in non-fuel retail Base Rates of approximately $3 million;
an OCRB of approximately $213 million and a FVRB of approximately $283 million;
a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;
a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and
a capital structure of 52.6% equity and 47.4% long-term debt.
The 2013 UNS Electric Rate Order also includes the following cost recovery mechanisms:
a LFCR mechanism to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation; and
a Transmission Cost Adjustor (TCA), which will allow more timely recovery of transmission costs associated with serving retail customers.
2012 UNS GAS RATE ORDER
In April 2012, the ACC approved a Base Rate increase of $2.7 million, or 1.8%, and an LFCR mechanism to enable UNS Gas to recover lost fixed cost revenues as a result of implementing the ACC’s Gas Energy Efficiency Standards (Gas EE Standards).
The ACC approved an authorized rate of return of 8.3% on an OCRB of $183 million, and a 1.0% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million). The new rates became effective in May 2012.
COST RECOVERY MECHANISMS
TEP, UNS Electric, and UNS Gas have received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless suspended by the ACC.
TEP's PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between prudently incurred actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.
Prior to the 2013 UNS Electric Rate Order, UNS Electric’s PPFAC rate was adjusted annually each June 1st, effective for the subsequent 12-month period. As a result of the 2013 UNS Electric Rate Order, effective January 1, 2014, UNS Electric's PPFAC rate reflects a weighted 12-month rolling average of actual fuel and purchased power costs incurred by UNS Electric. The PPFAC rate adjusts monthly, but it is restricted from changing by more than 0.83 percent from the preceding month's rate. If the PPFAC deferral balance reflects an over-collection of $10 million or more on a billed-to-customer basis, UNS Electric must file for a PPFAC rate adjustment. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis.
The tables below summarize TEP’s and UNS Electric’s PPFAC rates:
 
TEP
 
2013
 
2012
 
July - December
 
January - June
 
April - December
 
January - March
 
Cents per kWh
PPFAC Rate
0.14

 
0.77

 
0.77

 
0.53

Competition Transition Charge (1)

 

 

 
(0.53
)
Net TEP PPFAC Rate
0.14

 
0.77

 
0.77

 

(1) 
TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.
 
UNS Electric
 
2013
 
2012
 
September - December
 
June - August
 
January - May
 
June - December
 
January - May
 
Cents per kWh
PPFAC Rate
(0.40
)
 
(0.92
)
 
(1.44
)
 
(1.44
)
 
(0.88
)

UNS Gas Purchased Gas Adjustor
The PGA mechanism allows UNS Gas to adjust Retail Rates to recover fluctuations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than 15 cents per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed-to-customer basis.
In October 2013, the ACC approved an increase to the existing PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At December 31, 2013 and December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.
The PGA rate ranged from 0.4504 to 0.5280 cents per therm in 2013, and ranged from 0.5202 to 0.6501 cents per therm in 2012.
Renewable Energy Standards
TEP and UNS Electric are required to expand their use of renewable energy in order to meet the ACC’s RES. TEP and UNS Electric, through a customer surcharge, recover costs associated with meeting the RES. These costs include the purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.
In October 2013, the ACC approved TEP's 2014 RES plan and authorized a total 2014 RES budget of $40 million with $34 million to be collected through the 2014 RES funding mechanism. TEP earned returns on solar investments of $2 million in each of 2013 and 2012 and $1 million in 2011.
In October 2013, the ACC approved UNS Electric's 2014 RES plan and authorized a total 2014 RES budget of $7 million with $6 million to be collected through the 2014 RES funding mechanism.  UNS Electric earned returns on solar investments of less than $0.5 million in 2013 and 2012. No return was earned in 2011.
Energy Efficiency Standards
TEP, UNS Electric, and UNS Gas are required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs.
In December 2013, the ACC approved UNS Electric’s 2013-2014 energy efficiency implementation plan that included a 2014 calendar year budget of approximately $5 million to fund programs that support the ACC’s Electric EE Standards as well as a performance incentive.
In June 2013, the ACC approved the UNS Gas 2011-2012 energy efficiency implementation plan with certain modifications. The approval included an annual energy efficiency budget of approximately $2 million and a waiver of the Gas EE Standards through 2013.
Lost Fixed Cost Recovery Mechanism
The LFCR is a mechanism to recover certain non-fuel costs that would go unrecovered due to lost sales as a result of implementing ACC approved EE Standards and distributed generation targets.
In April 2012, the ACC authorized a LFCR mechanism that enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards.
In June 2013, the ACC authorized a LFCR mechanism for TEP subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate which will recover 2013 costs, to be effective on July 1, 2014, upon review by the ACC of verified lost kWh sales.
In December 2013, as part of the 2013 UNS Electric Rate Order, the ACC authorized a LFCR for UNS Electric, to be effective on July 1, 2014.
REGULATORY ASSETS AND LIABILITIES
The following tables summarize regulatory assets and liabilities:
 
December 31, 2013
 
TEP
 
UNS
Electric
 
UNS
Gas
 
UNS
Energy
 
Millions of Dollars
Regulatory Assets—Current
 
 
 
 
 
 
 
Property Tax Deferrals (1)
$
20

 
$

 
$

 
$
20

Derivative Instruments (Note 15)
1

 

 

 
1

San Juan Mine Fire Cost Deferral (2)
10

 

 

 
10

PPFAC (2)
4

 
10

 

 
14

DSM and LFCR (2)
3

 

 

 
3

Other Current Regulatory Assets (3)
5

 

 

 
5

Total Regulatory Assets—Current
43

 
10

 

 
53

Regulatory Assets—Noncurrent
 
 
 
 
 
 
 
Pension and Other Retiree Benefits (Note 10)
75

 
3

 
2

 
80

Income Taxes Recoverable through Future Revenues (4)
22

 
3

 

 
25

PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)
25

 

 

 
25

Discontinued Nogales Transmission Project (6)
5

 

 

 
5

Other Regulatory Assets (3)
14

 
2

 

 
16

Total Regulatory Assets—Noncurrent
141

 
8

 
2

 
151

Regulatory Liabilities—Current
 
 
 
 
 
 
 
PGA (2)

 

 
(15
)
 
(15
)
RES (2)
(22
)
 
(9
)
 

 
(31
)
Other Current Regulatory Liabilities
(2
)
 
(6
)
 

 
(8
)
Total Regulatory Liabilities—Current
(24
)
 
(15
)
 
(15
)
 
(54
)
Regulatory Liabilities—Noncurrent
 
 
 
 
 
 
 
Net Cost of Removal for Interim Retirements (7)
(254
)
 
(12
)
 
(26
)
 
(292
)
Income Taxes Payable through Future Rates
(5
)
 

 
(1
)
 
(6
)
Deferred Investment Tax Credit (8)
(4
)
 

 

 
(4
)
Total Regulatory Liabilities—Noncurrent
(263
)
 
(12
)
 
(27
)
 
(302
)
Total Net Regulatory Assets (Liabilities)
$
(103
)
 
$
(9
)
 
$
(40
)
 
$
(152
)
 
December 31, 2012
 
TEP
 
UNS
Electric
 
UNS
Gas
 
UNS
Energy
 
Millions of Dollars
Regulatory Assets—Current
 
 
 
 
 
 
 
Property Tax Deferrals (1)
$
18

 
$

 
$

 
$
18

Derivative Instruments (Note 15)
2

 
6

 
3

 
11

PPFAC (2)
7

 
8

 

 
15

DSM (2)
5

 

 

 
5

Other Current Regulatory Assets (3)
2

 

 
1

 
3

Total Regulatory Assets—Current
34

 
14

 
4

 
52

Regulatory Assets—Noncurrent
 
 
 
 
 
 
 
Pension and Other Retiree Benefits (Note 10)
130

 
5

 
4

 
139

Income Taxes Recoverable through Future Revenues (4)
8

 
2

 

 
10

PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)
22

 

 

 
22

Discontinued Nogales Transmission Project (6)
5

 

 

 
5

Other Regulatory Assets (3)
13

 
1

 
1

 
15

Total Regulatory Assets—Noncurrent
178

 
8

 
5

 
191

Regulatory Liabilities—Current
 
 
 
 
 
 
 
PGA (2)

 

 
(17
)
 
(17
)
RES (2)
(19
)
 
(4
)
 

 
(23
)
Other Current Regulatory Liabilities
(2
)
 
(1
)
 
(1
)
 
(4
)
Total Regulatory Liabilities—Current
(21
)
 
(5
)
 
(18
)
 
(44
)
Regulatory Liabilities—Noncurrent
 
 
 
 
 
 
 
Net Cost of Removal for Interim Retirements (7)
(231
)
 
(11
)
 
(25
)
 
(267
)
Income Taxes Payable through Future Rates
(5
)
 

 
(1
)
 
(6
)
Deferred Investment Tax Credit (8)
(5
)
 

 

 
(5
)
Other Regulatory Liabilities

 
(1
)
 

 
(1
)
Total Regulatory Liabilities—Noncurrent
(241
)
 
(12
)
 
(26
)
 
(279
)
Total Net Regulatory Assets (Liabilities)
$
(50
)
 
$
5

 
$
(35
)
 
$
(80
)
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.
(1) 
Property Tax is recovered over approximately a six-month period as costs are paid, rather than as costs are accrued.
(2) 
See Cost Recovery Mechanisms discussion above.
(3) 
TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).
(4) 
Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.
(5) 
Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.
(6) 
TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.
Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers, as described below:
(7) 
Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.
(8) 
The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.
IMPACTS OF REGULATORY ACCOUNTING
If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements.