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 by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

Settlement Agreement

The 2012 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 2012 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 2012 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 2012 Settlement Agreement.

Other key provisions of the 2012 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 acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

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

· Modifications to the Environmental Improvement Surcharge 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 PSA, including the elimination of the 90/10 sharing provision;

· A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below;

· Allowing a negative credit that existed in the PSA rate 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.

The 2012 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 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs 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 the 2009 Settlement Agreement entered into by APS and twenty-one other parties. The 2009 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 $700 million during the period beginning June 1, 2009 through December 31, 2014 and compliance with various financial conditions, including the maintenance of a prescribed capital structure (APS was able to meet these conditions without the need for additional equity infusions beyond the $253 million infused into APS in the second quarter of 2010); and

· Renewable energy programs that require APS to expand its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses.

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 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC professional staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue, but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.

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.

On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Rules, 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 2009 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. This amount was recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels. ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward. APS expects to receive a decision from the ACC in early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished. This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

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;

· 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 for 2013 and 2012 (dollars in millions):

	Twelve Months Ended December 31,
	2013			2012
Beginning balance	$	73		$	28
Deferred fuel and purchased power costs - current period	(21		)	(72		)
Amounts (charged) credited to customers	(31		)	117
Ending balance	$	21		$	73

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year. This represents a $0.000228 per kWh increase over the 2013 PSA charge. This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh. Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, 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 2012 Settlement Agreement (discussed above), however, 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- or under-collected amounts.

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.

Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula. Pursuant to the 2012 Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.

APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014. APS anticipates that the ACC will consider whether to approve APS’s LFCR adjustment prior to the end of March 2014.

Deregulation

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are expected to be held in 2014.

Four Corners

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. As a result of this purchase, APS now owns 63% of Units 4 and 5. APS has a total entitlement from Four Corners of 970 MW. The final purchase price for the interest was approximately $182 million. APS acquired assets and assumed certain of SCE’s decommissioning and mine reclamation obligations. We have recognized plant-in-service, net of accumulated depreciation, of $316 million, which includes an acquisition adjustment of $255 million. In addition, we have recognized a liability of $34 million for the decommissioning obligations, $93 million for the mine reclamation obligations, $18 million of other various liabilities, and $11 million of construction work in progress relating to this purchase. These amounts are subject to revision during the measurement period, not to exceed one year, to the extent additional information is obtained about the facts and circumstances that existed as of the acquisition date. While we expect the ACC to approve the recovery of the acquisition adjustment, should recovery be disallowed, it will be reclassified from plant-in-service to goodwill, subject to impairment testing. The decommissioning and mine reclamation obligations were recognized at their fair value. Because APS’s rates are regulated, APS expects to recover the costs of the acquired plant assets, including a return on its investment based on its cost of capital. APS believes this return is consistent with what a market participant would consider to be fair value in APS’s regulatory environment. Accordingly, APS believes the cost of the plant assets approximate their fair value.

The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. This includes deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Four Corners Units 1-3. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Four Corners Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Four Corners Units 1-3 was $37 million as of December 31, 2013.

As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners. This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate. APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration.

Regulatory Assets and Liabilities

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

	Remaining Amortization		December 31, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Pension and other postretirement benefits	(a	)	$	—	$	314	$	—	$	780
Income taxes — AFUDC equity	2043		4		105		4		92
Deferred fuel and purchased power — mark-to-market (Note 17)	2016		5		29		19		21
Transmission vegetation management	2016		9		14		9		23
Coal reclamation	2038		8		18		8		24
Palo Verde VIEs (Note 19)	2046		—		41		—		38
Deferred compensation	2036		—		34		—		34
Deferred fuel and purchased power (b) (c)	2014		21		—		73		—
Tax expense of Medicare subsidy	2023		2		15		2		17
Loss on reacquired debt	2034		1		17		2		18
Income taxes — investment tax credit basis adjustment	2043		1		39		1		26
Pension and other postretirement benefits deferral	2015		8		4		8		13
Four Corners cost deferral	2024		—		37		—		—
Lost fixed cost recovery	2014		25		—		7		—
Transmission cost adjustor	2015		8		2		10		—
Retired power plant costs	2020		3		18		—		—
Other	Various		2		25		1		14
Total regulatory assets (d)			$	97	$	712	$	144	$	1,100

(a) This asset represents the future recovery of under-funded pension and other postretirement benefit obligations 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. See Note 8 for further discussion.

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

(d) 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, 2013				December 31, 2012
	Period		Current		Non-Current		Current		Non-Current
Removal costs	(a	)	$	28	$	303	$	27	$	321
Asset retirement obligations	(a	)	—		266		—		256
Renewable energy standard (b)	2015		33		15		43		—
Income taxes — change in rates	2043		—		74		—		66
Spent nuclear fuel	2047		6		36		10		36
Deferred gains on utility property	2019		2		10		2		12
Income taxes — deferred investment tax credit	2043		3		79		2		52
Demand side management (b)	2014		27		—		4		—
Other	Various		—		18		—		16
Total regulatory liabilities			$	99	$	801	$	88	$	759

(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.