Regulatory Matters

9 Months Ended

Sep. 30, 2012

Regulatory Matters

Regulatory Matters

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.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

Settlement Agreement

The Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for purchased power costs (“Base Fuel Rate”)) from $0.03757 to $0.03207 per kilowatt-hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.

Other key provisions of the Settlement Agreement include the following:

·An authorized return on common equity of 10.0%;

·A capital structure comprised of 46.1% debt and 53.9% common equity;

·A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

·Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

·Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

·Deferral of 100% in all years if Arizona property tax rates decrease;

·A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);

·Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;

·Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

·Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the current 90/10 sharing provision;

·A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of the 2008 rate case settlement agreement discussed below.

·Allowing a negative credit that currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

·Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

·Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

The Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2008 rate case settlement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.

2008 General Retail Rate Case On-Going 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 contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

·A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;

·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 through 2012 and its use of renewable energy through 2015, 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 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.

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.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility-owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $92.8 million to $102.4 million.  The budget range stems from options related to distributed energy.  The first option involves no new incentives for distributed energy.  The second option would offer incentives for residential photovoltaic distributed energy beginning where 2012 incentives end and stepping down gradually based upon market participation.  APS’s filing also proposed a system of establishing compliance with distributed energy requirements that depends upon tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  Further, APS described its Community Solar program, a utility-owned 25 MW program that will be split into 3 to 7 separate projects throughout communities in APS’s service territory (this is the 25 MW program described in clause (iv) of the preceding paragraph).  APS expects a decision from the ACC around year end.

Demand Side Management Adjustor Charge.  The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

The ACC previously 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 2008 retail rate case 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, which ends in 2012.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Standards, which became effective January 1, 2011.  The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year.  This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (2.75% of total energy resources for the same two-year period).  The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later this year, APS intends to file a supplement to its plan that will include a proposed budget for 2013.

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 2012 and 2011 (dollars in millions):

	Nine Months Ended September 30,
	2012			2011
Beginning balance	$	28		$	(58	)
Deferred fuel and purchased power costs — current period	(52		)	(31		)
Amounts credited to customers	92			121
Ending balance	$	68		$	32

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

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 was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC.

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.

Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.  Because of higher relative system demand by APS’s retail customers, the approximately $16 million increase reflects roughly a $2 million decrease for wholesale customers and an $18 million increase for APS retail customers.

On May 14, 2012, APS filed an application with the ACC to implement the FERC-approved transmission rates for retail customers.  On July 18, 2012, the ACC approved the application authorizing the implementation of the FERC-approved transmission rates for retail customers, which became effective August 2012.

As part of APS’s proposed acquisition of Southern California Edison’s (“SCE”) interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California.  On October 1, 2012, APS filed a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period.  APS expects a decision from FERC before the end of 2012.  We believe these costs are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

Regulatory Assets and Liabilities

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

	September 30, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	$	—	$	939	$	—	$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity	3		91		3		81
Deferred fuel and purchased power — mark-to-market (Note 8)	11		16		43		34
Transmission vegetation management	9		25		9		32
Coal reclamation	8		26		2		35
Palo Verde VIEs (Note 7)	—		37		—		35
Deferred compensation	—		35		—		33
Deferred fuel and purchased power (a)	68		—		28		—
Tax expense of Medicare subsidy	2		17		2		18
Loss on reacquired debt	1		18		1		19
Income taxes — investment tax credit basis adjustment	1		17		—		15
Pension and other postretirement benefits deferral	8		15		—		12
Demand side management (a)	—		—		7		1
Other	11		15		2		14
Total regulatory assets (b)	$	122	$	1,251	$	97	$	1,352

(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, 2012				December 31, 2011
	Current		Non-Current		Current		Non-Current
Removal costs (a)	$	28	$	328	$	22	$	349
Asset retirement obligations	—		258		—		225
Renewable energy standard (b)	47		—		54		—
Income taxes — change in rates	—		59		—		59
Spent nuclear fuel	9		38		5		44
Deferred gains on utility property	2		13		2		14
Income taxes- deferred investment tax credit	1		35		1		30
Demand side management (b)	8		—		—		—
Other	1		16		4		16
Total regulatory liabilities	$	96	$	747	$	88	$	737

(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.