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 in Arizona, New Mexico, Idaho and Utah but in 2009 and 2010, essentially all of these assets were sold.  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 now reported as discontinued operations (see Note 21).  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 now reported as discontinued operations (see Note 21).  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 20).

 

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.

 

Accounting Records and Use of Estimates

 

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“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 the 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 the state 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 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 retail rate case settlement agreement (see Note 3).  Effective July 1, 2012, as a result of the 2011 rate case 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.

 

Utility Plant and Depreciation

 

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 capitalized 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, 2012 were as follows:

 

·                                          Fossil plant — 16 years;

·                                          Nuclear plant — 27 years;

·                                          Other generation — 26 years;

·                                          Transmission — 39 years;

·                                          Distribution — 35 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 new Palo Verde Nuclear plant lives, effective January 1, 2012.

 

For the years 2010 through 2012, the depreciation rates ranged from a low of 0.45% to a high of 12.08%.  The weighted-average rate was 2.71% for 2012, 2.98% for 2011, and 2.98% for 2010.

 

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 8.60% for 2012, 10.25% for 2011, and 9.2% for 2010.  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 18 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 another postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provide 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,
		2012			2011			2010
Cash paid during the period for:
Income taxes, net of (refunds)		$	2,543		$	10,324		$	(23,447	)
Interest, net of amounts capitalized		200,923			217,789			221,728
Significant non-cash investing and financing activities:
Accrued capital expenditures		$	26,208		$	27,245		$	19,226
Dividends declared but not paid		59,789			—			—

 

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 $50 million in 2012, $47 million in 2011, and $45 million in 2010. Estimated amortization expense on existing intangible assets over the next five years is $45 million in 2013, $37 million in 2014, $28 million in 2015, $20 million in 2016, and $12 million in 2017. At December 31, 2012, 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 22 for more information on these investments.

 

2.                                      New Accounting Standards

 

During 2012, we adopted amended guidance intended to converge fair value measurement and disclosure requirements for GAAP and international financial reporting standards (“IFRS”).  The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures.  The adoption of this new guidance resulted in additional fair value disclosures (see Note 14), but did not impact our financial statement results.

 

During 2012, we also adopted amended guidance on the presentation of comprehensive income.  As a result of the amended guidance, we have changed our format for presenting comprehensive income.  Previously, components of comprehensive income were presented within changes in equity.  Due to the amended guidance, we now present comprehensive income in a new financial statement titled “Consolidated Statements of Comprehensive Income”.  The adoption of this guidance changed our format for presenting comprehensive income, but did not impact our financial statement results.

 

3.                                      Regulatory Matters

 

Retail Rate Case Filing with the Arizona Corporation Commission

 

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the Settlement Agreement without material modifications.

 

Settlement Agreement

 

The Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate for fuel and purchased power costs 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 Four Corners;

 

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

 

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

 

·                                          Modifications to the PSA, including the elimination of the current 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 2008 rate case settlement agreement discussed below;

 

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

 

2008 General Retail Rate Case On-Going Impacts

 

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:

 

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

 

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

 

·                                          Various modifications to the existing energy efficiency, demand side management and renewable energy programs that require APS to, among other things, expand its conservation and demand side management programs through 2012 and its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand side management costs and incentives.

 

Cost Recovery Mechanisms

 

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

 

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

 

On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requested 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, own up to an additional 100 MW under its AZ Sun Program, for a total potential program amount of up to 200 MW.  The AZ Sun program, originally approved by the ACC in March 2010, contemplates the development of photovoltaic solar plants which APS will own.  Under this program to date, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million.

 

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requested 2013 RES funding of $97 million to $107 million.  In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS’s 2013 RES plan.  That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives.  The ACC further ordered that a hearing take place to consider:  (i) APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS’s largest industrial customers when calculating APS’s compliance with the annual RES requirements.

 

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

 

The ACC previously approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery was amortized over a three-year period, which ended in 2012.

 

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

 

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.  In 2013, the standards will require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.  Although this proposed budget is approximately $5.6 million more than the approved 2012 budget, the expiration of the three-year amortization of 2009 costs and prior year credits would result in a small decrease in the DSMAC.  APS expects to receive a decision from the ACC in the second quarter of 2013.

 

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The 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 (liability) for 2012 and 2011 (dollars in millions):

 

		Twelve Months Ended December 31,
		2012			2011
Beginning balance		$	28		$	(58	)
Deferred fuel and purchased power costs — current period		(72		)	(69		)
Amounts credited to customers		117			155
Ending balance		$	73		$	28

 

The PSA rate for the PSA year beginning February 1, 2013 is $0.0013 per kWh as compared to ($0.0042) per kWh for the prior year.  This represents a $0.0055 per kWh increase over the 2012 PSA charge.  This new rate is comprised of a forward component of ($0.0010) per kWh and a historical component of $0.0023 per kWh.  The Settlement Agreement allowed APS to exceed the $0.004 per kWh cap to PSA rate changes in this instance.  Any uncollected (overcollected) deferrals during the 2013 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2014.

 

Transmission Rates and Transmission Cost Adjustor.  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 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 beginning in 2013 and will go into effect automatically unless suspended by the ACC.

 

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

 

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

 

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

 

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

 

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

 

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 the Company in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as roof-top solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the recent rate case 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 the Company’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 its LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved an LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the Settlement Agreement went into effect on July 1, 2012.

 

Regulatory Assets and Liabilities

 

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

 

		Remaining Amortization		December 31, 2012						December 31, 2011
		Period		Current			Non-Current			Current			Non-Current
Pension and other postretirement benefits		(a)		$	—		$	780		$	—		$	1,023
Income taxes — AFUDC equity		2042		4			92			3			81
Deferred fuel and purchased power — mark-to-market (Note 18)		2016		19			21			43			34
Transmission vegetation management		2016		9			23			9			32
Coal reclamation		2026		8			24			2			35
Palo Verde VIEs (Note 20)		2046		—			38			—			35
Deferred compensation		2036		—			34			—			33
Deferred fuel and purchased power (b) (c)		2013		73			—			28			—
Tax expense of Medicare subsidy		2024		2			17			2			18
Loss on reacquired debt		2034		2			18			1			19
Income taxes — investment tax credit basis adjustment		2042		1			26			—			15
Pension and other postretirement benefits deferral		2015		8			13			—			12
Other		Various		18			14			9			15
Total regulatory assets (d)				$	144		$	1,100		$	97		$	1,352

 

(a)                                 This asset represents the future recovery of under-funded pension and other postretirement benefits obligation 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)                                  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, 2012						December 31, 2011
		Period		Current			Non-Current			Current			Non-Current
Removal costs		(a)		$	27		$	321		$	22		$	349
Asset retirement obligations		(a)		—			256			—			225
Renewable energy standard (b)		2013		43			—			54			—
Income taxes — change in rates		2042		—			66			—			59
Spent nuclear fuel		2047		10			36			5			44
Deferred gains on utility property		2019		2			12			2			14
Income taxes- deferred investment tax credit		2042		2			52			1			30
Other		Various		4			16			4			16
Total regulatory liabilities				$	88		$	759		$	88		$	737

 

(a)                                 In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal (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 statements purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using the 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 investment tax credits 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 represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt.  Further clarification of the timing is expected from the IRS within the next twelve months.

 

Net income associated with the Palo Verde sale leaseback variable interest entities is not subject to tax (see Note 20).  As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.

 

During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007.  As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate.  Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.

 

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):

 

		2012			2011			2010
Total unrecognized tax benefits, January 1		$	136,005		$	127,595		$	201,216
Additions for tax positions of the current year		5,167			10,915			7,551
Reductions for tax positions of prior years for:
Changes in judgment		(7,729		)	(1,555		)	(11,017		)
Settlements with taxing authorities		—			(124		)	(62,199		)
Lapses of applicable statute of limitations		(21		)	(826		)	(7,956		)
Total unrecognized tax benefits, December 31		$	133,422		$	136,005		$	127,595

 

Included in the balances of unrecognized tax benefits at December 31, 2012, 2011 and 2010 were approximately $10 million, $8 million and $7 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, 2008 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 2008.

 

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009.  At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

 

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 expense of $4 million for 2012, a pre-tax expense of $3 million for 2011 and a pre-tax benefit of $2 million for 2010.

 

The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $13 million as of December 31, 2012, $9 million as of December 31, 2011 and $6 million as of December 31, 2010.  To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate.  Additionally, as of December 31, 2012, 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,
		2012			2011			2010
Current:
Federal		$	(3,493	)	$	(310	)	$	(108,827	)
State		8,395			15,140			25,545
Total current		4,902			14,830			(83,282		)
Deferred:
Federal		200,322			159,566			260,236
State		28,280			16,626			10,911
Discontinued operations		—			—			(10,736		)
Total deferred		228,602			176,192			260,411
Total income tax expense		233,504			191,022			177,129
Less: income tax expense (benefit) on discontinued operations		(3,813		)	7,418			16,260
Income tax expense — continuing operations		$	237,317		$	183,604		$	160,869

 

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,
		2012			2011			2010
Federal income tax expense at 35% statutory rate		$	229,709		$	188,733		$	177,002
Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit		23,819			19,594			17,485
Credits and favorable adjustments related to prior years resolved in current year		—			—			(17,300		)
Medicare Subsidy Part-D		483			823			1,311
Allowance for equity funds used during construction (see Note 1)		(6,158		)	(6,881		)	(6,563		)
Palo Verde VIE noncontrolling interest (see Note 20)		(11,065		)	(9,636		)	(7,057		)
Other		529			(9,029		)	(4,009		)
Income tax expense — continuing operations		$	237,317		$	183,604		$	160,869

 

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

 

		December 31,
		2012			2011
Current asset		$	152,191		$	130,571
Long-term liability		(2,151,371		)	(1,925,388		)
Deferred income taxes — net		$	(1,999,180	)	$	(1,794,817	)

 

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, 2012, APS has recorded a regulatory liability of $69 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.

 

The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions making qualified property placed into service in 2013 eligible for 50% bonus depreciation for federal income tax purposes.  Full recognition of the cash benefit of this provision would delay realization of approximately $79 million in federal general business income tax credit carryforwards which are classified as current assets as of December 31, 2012.

 

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

 

		December 31,
		2012			2011
DEFERRED TAX ASSETS
Risk management activities		$	72,243		$	117,765
Regulatory liabilities:
Asset retirement obligation and removal costs		238,669			236,739
Renewable energy standard		—			19,722
Unamortized investment tax credits		53,837			31,460
Other		33,764			33,155
Pension and other postretirement liabilities		408,764			501,202
Renewable energy incentives		66,941			57,901
Credit and loss carryforwards		139,022			171,915
Other		68,844			73,759
Total deferred tax assets		1,082,084			1,243,618
DEFERRED TAX LIABILITIES
Plant-related		(2,584,166		)	(2,446,908		)
Risk management activities		(23,940		)	(30,171		)
Regulatory assets:
Allowance for equity funds used during construction		(37,899		)	(33,347		)
Deferred fuel and purchased power		(28,858		)	(10,884		)
Deferred fuel and purchased power — mark-to-market		(15,796		)	(30,559		)
Pension and other postretirement benefits		(316,757		)	(408,716		)
Other		(68,170		)	(73,087		)
Other		(5,678		)	(4,763		)
Total deferred tax liabilities		(3,081,264		)	(3,038,435		)
Deferred income taxes — net		$	(1,999,180	)	$	(1,794,817	)

 

As of December 31, 2012, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $111 million and federal net operating losses of $21 million, both of which first begin to expire in 2031, and other federal and state loss carryforwards of $7 million which first begin to expire in 2017.

 

5.                                      Lines of Credit and Short-Term Borrowings

 

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):

 

Credit Facility		Expiration		Amount Committed			Unused Amount (a)			Commitment Fees
Pinnacle West Revolving Credit Facility		November 2016		$	200		$	200		0.225	%
APS Revolving Credit Facility		November 2016		500			408			0.175	%
APS Revolving Credit Facility		February 2015		500			500			0.20	%
Total				$	1,200		$	1,108

 

(a)                                 At December 31, 2012, APS had $92 million of outstanding commercial paper.  Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million.

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

At December 31, 2012, the Pinnacle West credit facility, which terminates in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At December 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

 

APS

 

APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.  In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.

 

See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

 

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2011 (dollars in millions):

 

Credit Facility		Expiration		Amount Committed			Unused Amount (a)			Commitment Fees
Pinnacle West Revolving Credit Facility		November 2016		$	200		$	200		0.275	%
APS Revolving Credit Facility		November 2016		500			500			0.225	%
APS Revolving Credit Facility		February 2015		500			500			0.250	%
Total				$	1,200		$	1,200

 

(a)                                 These facilities were also fully available as of December 31, 2011.

 

Pinnacle West

 

On November 4, 2011, Pinnacle West refinanced its $200 million revolving credit facility that would have matured in February 2013, with a new $200 million facility.  The new revolving credit facility terminates in November 2016.  Interest rates are based on Pinnacle West senior unsecured debt credit ratings.

 

At December 31, 2011, the Pinnacle West credit facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  At December 31, 2011, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.

 

APS

 

On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million.  The new revolving credit facility terminates in February 2015.  APS will use the facility to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility.  The new revolving credit facility terminates in November 2016.  APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use the facility to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper.

 

See “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

 

Debt Provisions

 

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.  On February 6, 2013, the ACC issued a financing order in which it, subject to specified parameters and procedures, (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt.  This financing order is set to expire on December 31, 2017.