1.                                      Summary of Significant Accounting Policies

 

Description of Business and Basis of Presentation

 

Pinnacle West is a holding company that conducts business through its subsidiaries, APS and El Dorado, and formerly SunCor and APSES.  APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010.  In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business.  All activities for SunCor are reported as discontinued operations.  APSES provided energy-related projects to commercial and industrial retail customers in competitive markets in the western United States.  APSES was sold in 2011 and is reported as discontinued operations.  El Dorado is an investment firm.

 

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS and El Dorado, and formerly SunCor and APSES.  APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.

 

We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 19).

 

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

 

Certain line items are presented in more detail on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows than was presented in the prior years.  Other line items are more condensed than the previous presentation.  The prior year amounts were reclassified to conform to the current year presentation.  These reclassifications had no impact on total assets or net cash flow provided by operating activities.  The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):

 

Balance Sheets - December 31, 2012		As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Long-Term Debt less Current Maturities —
Long-term debt less current maturities		$	3,160,219		$	38,869		$	3,199,088
Long-Term Debt less Current Maturities —
Palo Verde sale leaseback lessor notes less
current maturities		38,869			(38,869		)	—

 

Statement of Cash Flows for the Year Ended December 31, 2012		As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes		$	228,602		$	(41,579	)	$	187,023
Deferred investment tax credit		—			41,579			41,579
Accrued taxes and income tax receivable		8,693			(8,693		)	—
Income tax receivable		—			(4,043		)	(4,043		)
Accrued taxes		—			12,736			12,736

 

Statement of Cash Flows for the Year Ended December 31, 2011		As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Deferred income taxes		$	176,192		$	(58,240	)	$	117,952
Deferred investment tax credit		—			58,240			58,240
Accrued taxes and income tax receivable		12,068			(12,068		)	—
Income tax receivable		—			3,983			3,983
Accrued taxes		—			8,085			8,085

 

Accounting Records and Use of Estimates

 

Our accounting records are maintained in accordance with GAAP.  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

 

Regulatory Accounting

 

APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.  Regulatory liabilities generally represent expected future costs that have already been collected from customers.

 

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

 

See Note 3 for additional information.

 

Electric Revenues

 

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers.  Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers.  The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month.  Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed.  Differences historically between the actual and estimated unbilled revenues are immaterial.  We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

 

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income.  In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy.  This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow.  We net these book-outs, which reduces both revenues and fuel and purchased power costs.

 

For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3).  Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.

 

Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

 

Allowance for Doubtful Accounts

 

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues.  The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

 

Property, Plant and Equipment

 

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:

 

·                                          material and labor;

·                                          contractor costs;

·                                          capitalized leases;

·                                          construction overhead costs (where applicable); and

·                                          allowance for funds used during construction.

 

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 12.

 

APS records a regulatory liability on its regulated assets for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.

 

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2013 were as follows:

 

·                                          Fossil plant — 18 years;

·                                          Nuclear plant — 26 years;

·                                          Other generation — 26 years;

·                                          Transmission — 37 years;

·                                          Distribution — 34 years; and

·                                          Other — 7 years.

 

APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008.  On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses.  The nuclear plant remaining life takes into consideration an ACC decision which authorizes the use of the new Palo Verde nuclear plant lives, effective January 1, 2012.

 

Pursuant to an ACC order, we defer operating costs related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  See Note 3 for further discussion.  These costs are deferred on the depreciation line of the Consolidated Statements of Income.

 

For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.

 

Allowance for Funds Used During Construction

 

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

 

AFUDC was calculated by using a composite rate of 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

 

Materials and Supplies

 

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

 

Fair Value Measurements

 

We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).

 

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

 

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

 

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.

 

See Note 14 for additional information about fair value measurements.

 

Derivative Accounting

 

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emission allowances and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

 

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 17 for additional information about our derivative instruments.

 

Loss Contingencies and Environmental Liabilities

 

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

 

Retirement Plans and Other Benefits

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 8 for additional information on pension and other postretirement benefits.

 

Nuclear Fuel

 

APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.

 

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation.  See Note 11 for information on spent nuclear fuel disposal costs.

 

Income Taxes

 

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).

 

Cash and Cash Equivalents

 

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

 

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):

 

		Years ended December 31,
		2013			2012			2011
Cash paid during the period for:
Income taxes, net of refunds		$	18,537		$	2,543		$	10,324
Interest, net of amounts capitalized		184,010			200,923			217,789
Significant non-cash investing and financing activities:
Accrued capital expenditures		$	33,184		$	26,208		$	27,245
Dividends declared but not paid		62,528			59,789			—
Liabilities assumed relating to acquisition of SCE Four Corners’ interest (see Note 3)		145,609			—			—

 

Intangible Assets

 

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets.  The intangible assets are amortized over their finite useful lives.  Amortization expense was $53 million in 2013, $50 million in 2012, and $47 million in 2011.  Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018.  At December 31, 2013, the weighted-average remaining amortization period for intangible assets was 6 years.

 

Investments

 

El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).

 

Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 and Note 20 for more information on these investments.

 

Business Segments

 

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

 

2.                                      New Accounting Standards

 

During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures.  The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet.  The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 17), but did not impact our financial statement results.

 

During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from accumulated other comprehensive income.  This guidance requires new disclosures relating to accumulated other comprehensive income and how reclassifications from accumulated other comprehensive income impact net income.  As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 21 and S-4).  The adoption of this guidance did not impact our financial statement results.

 

In July 2013, new guidance was issued which will generally require entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward.  The intent of this guidance is to eliminate diversity in practice in the presentation of certain unrecognized tax benefits.  The new guidance is effective for us during the first quarter of 2014, and is permitted to be adopted using either a prospective or retrospective application.  Currently, we do not present unrecognized tax benefits as a reduction to deferred tax asset carryforwards on the balance sheet.  As a result, the adoption of this new guidance will impact our balance sheet presentation; however, we do not expect these presentation changes to be material to our balance sheet.  The adoption of this new guidance will not impact our results of operations or cash flows.

 

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.

(c)                                  Subject to a carrying charge.

(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.

4.             Income Taxes

 

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.

 

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits.  The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.

 

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.

 

The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt.  As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter.  This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.  Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

 

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination.  On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund.  Cash related to this refund was received in the first quarter of 2014.

 

On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property.  These final regulations apply to tax years beginning on or after January 1, 2014.  Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment.  To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets.  Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.

 

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

 

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

 

		2013			2012			2011
Total unrecognized tax benefits, January 1		$	133,422		$	136,005		$	127,595
Additions for tax positions of the current year		3,516			5,167			10,915
Additions for tax positions of prior years		13,158			—			—
Reductions for tax positions of prior years for:
Changes in judgment		(108,099		)	(7,729		)	(1,555		)
Settlements with taxing authorities		—			—			(124		)
Lapses of applicable statute of limitations		—			(21		)	(826		)
Total unrecognized tax benefits, December 31		$	41,997		$	133,422		$	136,005

 

Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

 

As of the balance sheet date, the tax year ended December 31, 2010 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2010.

 

We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense.  The amount of interest recognized in the Consolidated Statements of Income related to unrecognized tax benefits was a pre-tax benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.

 

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2013, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

 

The components of income tax expense are as follows (dollars in thousands):

 

		Year Ended December 31,
		2013			2012			2011
Current:
Federal		$	(81,784	)	$	(3,493	)	$	(310	)
State		10,537			8,395			15,140
Total current		(71,247		)	4,902			14,830
Deferred:
Federal		279,973			200,322			159,566
State		21,865			28,280			16,626
Total deferred		301,838			228,602			176,192
Total income tax expense		230,591			233,504			191,022
Less: income tax expense (benefit) on discontinued operations		—			(3,813		)	7,418
Income tax expense — continuing operations		$	230,591		$	237,317		$	183,604

 

The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):

 

		Year Ended December 31,
		2013			2012			2011
Federal income tax expense at 35% statutory rate		$	234,695		$	229,709		$	188,733
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		21,387			23,819			19,594
Credits and favorable adjustments related to prior years resolved in current year		(3,356		)	—			—
Medicare Subsidy Part-D		823			483			823
Allowance for equity funds used during construction (see Note 1)		(6,997		)	(6,158		)	(6,881		)
Palo Verde VIE noncontrolling interest (see Note 19)		(11,862		)	(11,065		)	(9,636		)
Other		(4,099		)	529			(9,029		)
Income tax expense — continuing operations		$	230,591		$	237,317		$	183,604

 

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

 

		December 31,
		2013			2012
Current asset		$	91,152		$	152,191
Long-term liability		(2,351,882		)	(2,151,371		)
Deferred income taxes — net		$	(2,260,730	)	$	(1,999,180	)

 

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013 APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

 

On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.  As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

 

The components of the net deferred income tax liability were as follows (dollars in thousands):

 

		December 31,
		2013			2012
DEFERRED TAX ASSETS
Risk management activities		$	44,920		$	72,243
Regulatory liabilities:
Asset retirement obligation and removal costs		235,959			238,669
Unamortized investment tax credits		82,116			53,837
Other		42,609			33,764
Pension and other postretirement liabilities		198,642			408,764
Renewable energy incentives		65,434			66,941
Credit and loss carryforwards		133,070			139,022
Other		148,492			68,844
Total deferred tax assets		951,242			1,082,084
DEFERRED TAX LIABILITIES
Plant-related		(2,903,730		)	(2,584,166		)
Risk management activities		(16,191		)	(23,940		)
Regulatory assets:
Allowance for equity funds used during construction		(43,058		)	(37,899		)
Deferred fuel and purchased power		(8,282		)	(28,858		)
Deferred fuel and purchased power — mark-to-market		(13,343		)	(15,796		)
Pension and other postretirement benefits		(129,250		)	(316,757		)
Other		(93,202		)	(68,170		)
Other		(4,916		)	(5,678		)
Total deferred tax liabilities		(3,211,972		)	(3,081,264		)
Deferred income taxes — net		$	(2,260,730	)	$	(1,999,180	)

 

As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.