Regulatory Matters

12 Months Ended

Dec. 31, 2011

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 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.  On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012.  Opening briefs from parties are due February 29, 2012 and responsive briefs are due March 14, 2012.  See below for details regarding the Settlement Agreement.

The key financial provisions of APS’s original 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 APS’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through 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 Fuel Rate of $0.03242 per kWh based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

APS 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 a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

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 from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the 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;

·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 approximately $5 million annually;

·Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

·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 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.

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

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 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 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.

Demand-Side Management Adjustor Charge (“DSMAC”).  The 2008 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency 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 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 2009 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.

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 related to APS’s 2008 retail rate case (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 authorized in 2009 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 prior to March 31, 2012.

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The PSA is subject to specified parameters and procedures, including the following:

·APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

·under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate (see “Settlement Agreement” above for information regarding the elimination of this arrangement);

·an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

·the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

·the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

·the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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

	Year EndedDecember 31,
	2011			2010
Beginning balance	$	(58	)	$	(87	)
Deferred fuel and purchased power costs-current period	(69		)	(93		)
Amounts refunded through revenues	155			122
Ending balance	$	28		$	(58	)

The PSA rate for the PSA year beginning February 1, 2012 is ($0.0042) per kWh as compared to ($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 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 TCA.  If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 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.

Regulatory Assets and Liabilities

As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Consolidated Balance Sheets.  This presentation is reflected in the tables below.

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

	Remaining Amortization	December 31, 2011				December 31, 2010
	Period	Current		Non-Current		Current		Non-Current
Pension and other postretirementbenefits	(a)	$	—	$	1,023	$	—	$	669
Income taxes —AFUDC equity	2041	3		81		3		69
Deferred fuel and purchasedpower — mark-to-market(Note 18)	2016	43		34		42		35
Transmission vegetationmanagement	2016	9		32		—		46
Coal reclamation	2026	2		35		2		36
Palo Verde VIE (Note 20)	2015	—		35		—		33
Deferred compensation	2036	—		33		—		32
Deferred fuel and purchasedpower (b)	2012	28		—		—		—
Income taxes — Medicare subsidy	2024	2		18		2		21
Loss on reacquired debt	2034	1		19		1		21
Income taxes — investmenttax credit basis adjustment	2044	—		15		—		—
Pension and other postretirementbenefits deferral	2015	—		12		—		—
Demand side management	2013	7		1		12		6
Other	Various	2		14		—		18
Total regulatory assets (c)		$	97	$	1,352	$	62	$	986

(a)This asset represents the future recovery in earnings of under-funded pension and other postretirement benefits obligation costs through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.

(b)See “Cost Recovery Mechanisms” discussion above.

(c)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):

	Remaining Amortization	December 31, 2011				December 31, 2010
	Period	Current		Non-Current		Current		Non-Current
Removal costs	(a)	$	22	$	349	$	22	$	357
Asset retirement obligations	(a)	—		225		—		184
Renewable energy standard (b)	2012	54		—		50		—
Income taxes — change in rates	2041	—		59		—		—
Spent nuclear fuel	2047	5		44		4		41
Deferred gains on utility property	2019	2		14		2		16
Income taxes-unamortizedinvestment tax credit	2044	1		30		—		1
Deferred fuel and purchasedpower (b)(c)		—		—		58		—
Other	Various	4		16		3		15
Total regulatory liabilities		$	88	$	737	$	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.  See Note 12.

(b)See “Cost Recovery Mechanisms” discussion above.

(c)Subject to a carrying charge.