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Regulatory Matters

9 Months Ended

Sep. 30, 2011

3. Regulatory Matters

Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. The Company requested that the increase become effective July 1, 2012. The request would increase the average retail customer bill approximately 6.6%. The filing is based on a test year ended December 31, 2010, adjusted as described below. APS’s filing was deemed sufficient by the ACC staff and a hearing has been scheduled to begin January 19, 2012.

The key financial provisions of the request included:

· an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through the Company’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (the “PSA”) (which will decrease base rates);

· a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

· the following proposed capital structure and costs of capital:

	Capital Structure		Cost of Capital
Long-term debt	46.1	%	6.38	%
Common stock equity	53.9	%	11.00	%
Weighted-average cost of capital			8.87	%

· a base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

The Company proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision. In addition, APS proposed two new recovery mechanisms that would adjust electricity rates annually between changes in retail base rates. The Efficiency and Infrastructure Account, a decoupling mechanism, would address recovery of the Company’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation. The Environmental and Reliability Account, a generation infrastructure adjustment mechanism, would allow recovery of the costs associated with generation investments related to new generation additions, generation efficiency projects and environmental compliance requirements.

2008 General Retail Rate Case Impacts

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

· Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

· An authorized return on common equity of 11%;

· A capital structure comprised of 46.2% debt and 53.8% common equity;

· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

· Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

· Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

Renewable Energy Standard. In 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (“RES”). Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable generation in compliance with requirements through 2014, and requested RES funding of $87 million for 2010, which was later approved by the ACC. APS also sought various other determinations in its plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff, Arizona described below.

On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100 megawatts (“MW”) of APS-owned solar resources through 2014. Through this program, APS plans to invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire through competitive procurement processes. The costs associated with the first 50 MW under this program will be recovered initially through the RES until such time as the costs are recovered in base rates or other mechanisms. The costs of the second 50 MW will be recovered through a mechanism to be determined in APS’s current retail rate case, although APS seeks to recover 19 MW of this second tranche in its 2012 RES implementation plan as discussed below.

On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of up to 200 residential and business customers located within a certain test area in Flagstaff, Arizona. The capital carrying costs of the program will be recovered through the RES until such time as these costs are recovered in base rates.

On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015 timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed enhancements to the residential distributed energy incentive program based on high customer participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation plan to reflect the following items, among others: 1) increased clarity relating to customer project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan and associated funding request. On February 11, 2011, the ACC amended its original decision that approved the 2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b) restricted APS’s ownership of facilities to only economically challenged, rural schools and only after a school has received a bid from a third-party solar installer; (c) approved the Rapid Reservation program; and (d) maintained the original approved budget with some timing modifications.

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million. The range in the funding request arises from APS offering several options for third-party initiatives. The options involve obtaining 150 MW from third-parties entirely through power purchase agreements (“PPAs”) or through a mix of PPAs and non-residential distributed energy programs. APS also proposed (i) an additional 100 MW of APS-owned AZ Sun projects; (ii) permission to recover costs for a 19 MW AZ Sun project now instead of waiting for a recovery mechanism in APS’s current retail rate case; and (iii) an additional 25 MW of APS-owned systems on school and government facilities. On October 26, 2011, the ACC staff issued a report recommending an RES budget of $131.7 million, including the addition of 100 MW of APS-owned AZ Sun projects, permission to recover costs for a 19 MW AZ Sun project through the 2012 RES, and an additional 15 MW of APS-owned systems on school and government facilities. APS expects a decision from the ACC by year end.

Demand-Side Management Adjustor Charge (“DSMAC”). The settlement agreement related to the 2008 retail rate case requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to customer bills in order to recover these estimated amounts for use on certain demand-side management programs. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.

The ACC approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.

On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the settlement agreement (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs discussed above and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012. APS expects a decision from the ACC by year end.

PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2011 and 2010 (dollars in millions):

	Nine Months Ended September 30,
	2011			2010
Beginning balance	$	(58	)	$	(87	)
Deferred fuel and purchased power costs-current period	(31		)	(50		)
Amounts refunded through revenues	121			96
Ending balance	$	32		$	(41	)

The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to ($0.0045) per kWh for the prior year. Any uncollected (overcollected) deferrals during the 2011 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2012.

Transmission Rates and Transmission Cost Adjustor. In July 2008, the United States Federal Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the transmission cost adjustor (“TCA”).

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

Regulatory Assets and Liabilities

As discussed in Note 1, as of September 30, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Condensed Consolidated Balance Sheets. This presentation is reflected in the tables below.

The detail of regulatory assets is as follows (dollars in millions):

	September 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	663	$	—	$	669
Deferred income taxes	3		82		3		69
Deferred fuel and purchased power — mark-to-market (Note 8)	35		27		42		35
Transmission vegetation management	9		34		—		46
Coal reclamation	2		35		2		36
Palo Verde VIE (Note 7)	—		34		—		33
Deferred compensation	—		34		—		32
Deferred fuel and purchased power (a)	32		—		—		—
Tax expense of Medicare subsidy	2		18		2		21
Loss on reacquired debt	1		19		1		21
Pension and other post-retirement benefits deferral	—		9		—		—
Demand side management (a)	3		2		12		6
Other	—		21		—		18
Total regulatory assets (b)	$	87	$	978	$	62	$	986

(a) See Cost Recovery Mechanisms discussion above.

(b) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”

The detail of regulatory liabilities is as follows (dollars in millions):

	September 30, 2011				December 31, 2010
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	21	$	355	$	22	$	357
Asset retirement obligations (Note 15)	—		202		—		184
Renewable energy standard (b)	58		—		50		—
Income taxes — change in rates	—		50		—		—
Spent nuclear fuel	5		43		4		41
Deferred gains on utility property	2		15		2		16
Income taxes- deferred investment tax credit	—		9		—		1
Deferred fuel and purchased power (b)(c)	—		—		58		—
Other	8		15		3		15
Total regulatory liabilities	$	94	$	689	$	139	$	614

(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.

(b) See Cost Recovery Mechanisms discussion above.