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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, SunCor, El Dorado, and formerly 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. 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, SunCor, APSES, and El Dorado. 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).
In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2011 through the date the financial statements were issued.
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. These consolidated financial statements and notes have been prepared consistently with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income, Consolidated Balance Sheets, and Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 21) and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).
Certain line items are presented in more detail on the 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 net cash flow provided by operating activities.
The following tables show the impact of the reclassifications of prior years (previously reported) amounts (dollars in thousands):
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 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.
Effective January 1, 2010, 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). This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012. Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues.
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 for the asset retirement obligations related to its regulated assets. This regulatory liability represents 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, 2011 were as follows:
· Fossil plant — 18 years; · Nuclear plant — 29 years; · Other generation — 28 years; · Transmission — 38 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 2009 through 2011, the depreciation rates ranged from a low of 1.30% to a high of 10.20%. The weighted-average rate was 2.98% for 2011, 2.98% for 2010, and 3.06% for 2009.
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 10.25% for 2011, 9.2% for 2010, and 5.9% for 2009. 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 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 unobservable inputs, such as models and other valuation methods, 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 that may qualify as derivatives, including futures, forwards, options and swaps. As part of our overall risk management program, we use such 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 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 and 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 and Note 23 for information on nuclear decommissioning 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 liability 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.
Real Estate Investments
We did not have any real estate investments at December 31, 2011 and December 31, 2010 on our Consolidated Balance Sheets. For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets; we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used” in 2010 and 2009. When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. Our internal models used inputs that we believe were consistent with those that would be used by market participants.
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.
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 $47 million in 2011, $45 million in 2010, and $35 million in 2009. Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2012, $35 million in 2013, $28 million in 2014, $21 million in 2015, and $13 million in 2016. At December 31, 2011, the weighted average remaining amortization period for intangible assets was 7 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 23 for more information on these investments. |
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2. New Accounting Standards
In May 2011, the FASB issued amended guidance to converge fair value measurement and disclosure requirements for GAAP and IFRS. The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The guidance is effective for us on January 1, 2012. The adoption of this new guidance will result in additional fair value disclosures, but will not impact our financial statement results.
In June 2011, the FASB issued amended guidance on the presentation of comprehensive income intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence with IFRS. The amended guidance requires entities to present total comprehensive income, which includes components of net income and components of other comprehensive income, in either a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for us on January 1, 2012. The guidance will change our presentation of comprehensive income, but will not impact our financial statement results. |
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3. Regulatory Matters
Retail Rate Case Filing with the Arizona Corporation Commission
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would increase the average retail customer bill approximately 6.6%. The filing is based on a test year ended December 31, 2010, adjusted as described below. On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case. The Settlement Agreement requires the approval of the ACC. Evidentiary hearings on the matter were completed on February 3, 2012. Opening briefs from parties are due February 29, 2012 and responsive briefs are due March 14, 2012. See below for details regarding the Settlement Agreement.
The key financial provisions of APS’s original request included:
· an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the PSA (which will decrease base rates);
· a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;
· the following proposed capital structure and costs of capital:
· a Base Fuel Rate of $0.03242 per kWh based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).
APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision. In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.
Settlement Agreement
The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate from $0.03757 to $0.03207 per kWh); and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.
APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.
Other key provisions of the Settlement Agreement include the following:
· An authorized return on common equity of 10.0%;
· A capital structure comprised of 46.1% debt and 53.9% common equity;
· A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
· Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:
· Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
· Deferral of 100% in all years if Arizona property tax rates decrease;
· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant;
· Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
· Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce approximately $5 million annually;
· Modifications to the PSA, including the elimination of the current 90/10 sharing provision;
· Allowing a negative credit that currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
· Modification of the TCA to streamline the process for future transmission-related rate changes; and
· Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012. As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.
2008 General Retail Rate Case Impacts
On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:
· Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);
· An authorized return on common equity of 11%;
· A capital structure comprised of 46.2% debt and 53.8% common equity;
· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);
· Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and
· Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 MW under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015. In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications. Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.
Demand-Side Management Adjustor Charge (“DSMAC”). The 2008 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand-side management programs over the current year. Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.
The ACC previously approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2009 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.
On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.
On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the settlement agreement related to APS’s 2008 retail rate case (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs authorized in 2009 and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012. APS expects a decision from the ACC prior to March 31, 2012.
PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
· APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
· under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate (see “Settlement Agreement” above for information regarding the elimination of this arrangement);
· an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
· the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
· the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
· the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2011 and 2010 (dollars in millions):
The PSA rate for the PSA year beginning February 1, 2012 is ($0.0042) per kWh as compared to ($0.0057) per kWh for the prior year. Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.
Transmission Rates and Transmission Cost Adjustor. In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.
Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.
Regulatory Assets and Liabilities
As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Consolidated Balance Sheets. This presentation is reflected in the tables below.
The detail of regulatory assets is as follows (dollars in millions):
(a) This asset represents the future recovery in earnings of under-funded pension and other postretirement benefits obligation costs through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (b) See “Cost Recovery Mechanisms” discussion above. (c) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
The detail of regulatory liabilities is as follows (dollars in millions):
(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. See Note 12. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. |
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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 $69 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 cash refunds are not expected to be received in the next twelve months.
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):
Included in the balances of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $7 million and $16 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 few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
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 Statement of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2011, we have recognized $4 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):
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):
The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
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. In 2011, APS increased regulatory liabilities by a total of $62 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):
As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($67 million) and federal net operating losses ($92 million), both of which first begin to expire in 2029, and other federal and state loss carryforwards ($13 million) which first begin to expire in 2014. |
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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, 2011 (dollars in millions):
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011. During the fourth quarter of 2011, APS and Pinnacle West refinanced the existing credit facilities (as discussed below) that would have otherwise matured in February 2013.
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. 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, 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 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.
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 other letters of credit.
The table below presents the consolidated credit facilities and amounts available and outstanding and other short-term borrowings as of December 31, 2010 (dollars in millions):
Pinnacle West
On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. This facility was refinanced on November 4, 2011.
APS
On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. This facility was refinanced on November 4, 2011.
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 October 30, 2007, the ACC issued a financing order in which it approved APS’s request, subject to specified parameters and procedures, to increase (a) APS’s short-term debt authorization from 7% of APS’s capitalization to (i) 7% of APS’s capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’s long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. This financing order expires December 31, 2012; however, all debt previously authorized and outstanding on December 31, 2012 will remain authorized and valid obligations of APS.
On November 22, 2011, APS filed a financing application with the ACC requesting an increase in APS’s long-term debt authorization (approximately $4.2 billion) to approximately $5.5 billion in light of the projected financing needed to fund APS’s capital expenditure and maintenance program and other cash requirements. In addition, APS requested authorization to (i) allow for other types of securities providing long-term capital financing, including preferred stock, trust preferred securities or other forms of hybrid securities, and (ii) manage interest rate risks and exposure associated with any long-term or short-term indebtedness authorized by the ACC.
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6. Long-Term Debt and Liquidity Matters
All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2011 and 2010 (dollars in thousands):
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.09% at December 31, 2011 and 0.32% at December 31, 2010. (c) The weighted-average interest rate was 5.27% at December 31, 2011 and 5.29% at December 31, 2010. (d) The weighted-average interest rate was 1.794% at December 31, 2011.
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt and capitalized lease requirements (dollars in millions):
Debt Fair Value
Our long-term debt fair value estimates are based on quoted market prices of the same or similar issues. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):
Credit Facilities and Debt Issuances
Pinnacle West
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings. As of December 31, 2011, $50 million of the $175 million term loan facility had been repaid.
APS
On August 25, 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011.
On September 7, 2011, APS entered into a new letter of credit agreement supporting its approximately $27 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. The agreement expires September 22, 2016.
On December 8, 2011, APS extended a letter of credit agreement supporting its approximately $17 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project), 1998. The agreement expires December 8, 2016.
On January 10, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale will be used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes due March 1, 2012.
See Lines of Credit and Short-Term Borrowings in Note 5 and “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2011, the ratio was approximately 47% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2011, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements. |
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7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2011, 2010 and 2009 is as follows (dollars in thousands):
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes. (b) In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.
At December 31, 2011, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding. |
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8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
Pinnacle West also sponsors another postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 14 for discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. During 2011, we deferred pension and other postretirement benefit costs of approximately $12 million.
On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset) (dollars in thousands):
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2011 and 2010 (dollars in thousands):
The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2011 and 2010 (dollars in thousands):
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2011 and 2010 (dollars in thousands):
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2011 and 2010 (dollars in thousands):
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2012 (dollars in thousands):
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2012, we are assuming a 7.75% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
Assumed health care cost trend rates above have a significant effect on the amounts reported for the health care plans. In selecting our health care trend rates, we consider past performance and forecasts of health care costs. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
Plan Assets
The Board of Directors has delegated oversight of the plans’ assets to an Investment Management Committee, which has adopted an investment policy. The investment policy’s overall strategy is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plans’ investment policies provide for mixes of investments including long-term fixed income assets and return-generating assets. Long-term fixed income assets are designed to offset changes in benefit obligations due to changes in discount rates and inflation. Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. The determination of total allocation between return-generating and long-term fixed income assets is reviewed on at least an annual basis. Other investment strategies include the external management of the plans’ assets, and the prohibition of investments in Pinnacle West securities.
Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures and other instruments. The investment policy does not provide for a specific mix of long-term fixed income assets, but does require the average credit rating of such assets to be considered upper medium grade or above. The 2011 year-end long-term fixed income asset strategy focused on investments in corporate bonds of primarily investment-grade U.S. issuers and long-term treasuries, with total long-term fixed income assets representing 46% of total pension plan assets and 46% of other benefit plans assets.
Return-generating assets in the pension plan and other benefit plans target a mix of approximately 64% U.S. equities, 27% international equities, and 9% alternative investments. The 2011 year-end U.S. equity holdings were invested primarily in large-cap companies in diverse industries. International equities include investments in emerging and developing markets. Return-generating assets also include investments in securities through commingled funds in common and collective trusts. Alternative investments primarily include investments in real estate. The 2011 year-end return-generating assets represented 54% of total pension plan assets and 54% of other benefit plans’ assets.
See Note 14 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income and equity securities, in addition to investing indirectly in equity securities and real estate through the use of common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate curves. These instruments are classified as Level 2.
The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 index). The common and collective equity trusts are valued using net asset value (“NAV”), which is derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2011 the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market.
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. Additionally, we obtain and review independent audit reports on the trustee’s internal operating controls and valuation processes.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2011, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables.
(b) This category consists primarily of debt securities issued by municipalities.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2010, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables. (b) This category consists primarily of municipal debt securities issued by municipalities.
The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2010 (dollars in thousands):
(a) The return for December 31, 2010 represents the return on assets held as of March 31, 2010, the beginning of the period in which all the assets were transferred out of Level 3.
(b) Transfers into and out of Level 3 are measured at the beginning of the period in which the transfer occurs. Transfers out of Level 3 during 2010 relate to our Real Estate Common and Collective Trust being transferred to a Level 2 investment. During 2009 the Real Estate Common and Collective Trust had special redemption restrictions in place, which limited our ability to transact at the trust’s NAV. During 2010 these special redemption restrictions were lifted, and in 2010 and 2011 we were able to transact at the NAV according to the trust’s contractual redemption policy.
The plans had no investments valued using significant unobservable inputs (Level 3) for the year ended December 31, 2011.
Contributions
The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $160 million in 2014. In 2011, we did not make a contribution to our pension plan. The contribution to our other postretirement benefit plans in 2011 was approximately $19 million. The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share of the pension plan contribution was $195 million in 2010. APS’s share of the contributions to the other postretirement benefit plan were $19 million in 2011, $16 million in 2010, and $15 million in 2009.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
(a) The estimated future other benefit payments take into account the Medicare Part D subsidy.
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2011, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $8 million for 2011, $9 million for 2010 and $9 million for 2009. |
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9. Leases
We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $21 million in 2011, $23 million in 2010 and $28 million in 2009. APS’s lease expense was $18 million in 2011, $19 million in 2010 and $19 million in 2009.
Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):
In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed variable interest entities for which APS is the primary beneficiary. As the primary beneficiary APS consolidated these lessor trust entities. The above lease disclosures exclude the impacts of these sale leaseback transactions, as lease accounting for these agreements is eliminated upon consolidation. See Note 20 for a discussion of VIEs.
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10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2011 (dollars in thousands):
(a) See Note 20.
(b) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(c) Weighted average of interests. |
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11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
APS currently estimates it will incur $122 million (in 2011 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2011, APS had a regulatory liability of $49 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $46 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Fuel and Purchased Power Commitments and Purchase Obligations
APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2012 and 2042 that include required purchase provisions. APS estimates the contract requirements to be approximately $580 million in 2012; $528 million in 2013; $556 million in 2014; $535 million in 2015; $503 million in 2016; and $6.8 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
Of the various fuel and purchased power contracts mentioned above, some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.
The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):
(a) Total take-or-pay commitments are approximately $541 million. The total net present value of these commitments is approximately $401 million.
Renewable Energy Credits
APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $58 million in 2012; $32 million in 2013; $33 million in 2014; $32 million in 2015; $32 million in 2016; and $388 million thereafter.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’s coal mine reclamation obligation was approximately $118 million at December 31, 2011 and $117 million at December 31, 2010.
FERC Market Issues
On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration. On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.
This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.
Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $1 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.
Climate Change Lawsuit
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010. On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.
On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants. However, the Court left open the issue of whether such claims may be available under state law. Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision. We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.
Southwest Power Outage
Regulatory Inquiry. On September 8, 2011 at approximately 3:30PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.
Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.8 million customers (1.6 million in the United States and 1.2 million in northern Mexico) were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.
APS has an internal review of the September 8 events underway. In addition:
· the FERC and the North American Electric Reliability Corporation (“NERC”) are conducting a joint inquiry into the outages; and
· the Western Electricity Coordinating Council (“WECC”) initiated a Detailed Disturbance Analysis process to identify and understand the cause of the events that occurred, and identify and ensure timely implementation of corrective actions.
APS cannot predict the timing, results or potential impacts of any of the inquiries into the September 8 events, or any other claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that the violation is found to have been in existence.
Lawsuit. On September 12, 2011, two purported consumer class action complaints were filed in Federal District Court in San Diego, California, naming APS, Pinnacle West and San Diego Gas & Electric Company as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service. On December 22, 2011, the plaintiffs voluntarily dismissed both lawsuits. In January 2012, one of the cases was refiled in California Superior Court in San Diego, California. APS and Pinnacle West have numerous defenses against any such complaints, and do not believe that any potential impact will be material.
New Source Review
On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the PSD provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS believes the claims in this matter are without merit and will vigorously defend against them. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Financial Assurances
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2011, approximately $44 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 20 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire at December 31, 2015, totaling approximately $52 million. Additionally, APS has issued two letters of credit to support the collateral obligations under a certain natural gas tolling contracts entered into with third parties. At December 31, 2011, $30 million of letters of credit were outstanding to support these tolling contract obligations. These letters of credit will expire in 2015 and 2016.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
Pinnacle West sold its investment in APSES on August 19, 2011. Upon the closing of the sale, Pinnacle West was released from its parental guarantee and surety bond obligations related to the APSES business. Pinnacle West has also issued parental guarantees and surety bonds for APS which were not material at December 31, 2011. |
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12. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. In the first quarter of 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.
Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.
Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.
The following schedule shows the change in our asset retirement obligations for 2011 and 2010 (dollars in millions):
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3. |
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13. Selected Quarterly Financial Data (Unaudited)
Consolidated quarterly financial information for 2011 and 2010 is as follows (dollars in thousands, except per share amounts):
(a) The March 31, 2011 results were adjusted for the effect of reclassifications for discontinued operations (see Note 21). The adjustments resulted in a reduction in operating revenues of $10,728, a reduction in operations and maintenance of $1,457, a reduction in operating income of $1,357, a decrease in income taxes of $356, and a decrease in income from continuing operations of $1,043.
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14. Fair Value Measurements
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.
Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on NAV.
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where models are required due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. Option contracts are valued using a Black-Scholes option pricing model that incorporates commodity prices, volatilities, and correlation factors.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Recurring Fair Value Measurements
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans.
Cash Equivalents
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.
Risk Management Activities — Derivative Instruments
Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. Certain option contracts are valued using option valuation models which utilize both observable and unobservable inputs such as volatility rates and correlation factors. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.
Investments Held in our Nuclear Decommissioning Trust
The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on NAV, which is primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.
Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV.
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate curves. These instruments are classified as Level 2. Whenever possible multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.
Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes. See Note 23 for additional discussion about our nuclear decommissioning trust.
Fair Value Tables
The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 18. (c) Represents nuclear decommissioning trust net pending securities sales and purchases.
The following table presents the fair value at December 31, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 18. (c) Represents nuclear decommissioning trust net pending securities sales and purchases.
The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2011 and 2010 (dollars in millions):
Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.
Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are generally related to changes in the significance of reserves applied to derivative instruments. Transfers out of Level 3 may also be related to our long-dated energy transactions as they move closer to delivery and quoted prices become available.
Nonrecurring Fair Value Measurements
For the periods ended December 31, 2011 and 2010, we had no assets or liabilities measured at fair value on a nonrecurring basis.
Financial Instruments Not Carried at Fair Value
The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. For our long-term debt fair values see Note 6. |
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16. Stock-Based Compensation
Pinnacle West grants long-term incentive awards under the 2007 long-term incentive plan (“2007 Plan”) in the form of Stock Grants, Restricted Stock Units, Restricted Stock and Performance Shares and may grant incentive and stock options, stock appreciation rights, dividend equivalents and stock. The 2007 Plan, effective May 23, 2007, provides a maximum of 8 million common shares to be available for grant to eligible employees and members of the Board of Directors.
Restricted Stock Unit Awards and Stock Grants
Stock grants issued to non-officer members of the Board of Directors in 2009 under the 2007 Plan were paid in fully transferable shares of stock. The 2011 and 2010 grants issued under the 2007 Plan provided Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in lieu of the stock grant. Directors who elect to defer may elect to receive payment in either (1) stock, or (2) 50% in cash and 50% in stock. The Director may elect to receive payments either (1) as of the last business day of the month following the month in which the Director separates from services on the Board, or (2) as of a date specified by the Director, which date must be after December 31 of the year in which the grant was received. The deferred restricted stock units accrue dividend rights equal to the amount of dividends the Director would have received if the Director had directly owned one share of common stock for each restricted stock unit held plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either (1) stock, or (2) 50% stock and 50% cash.
Restricted stock units have been granted to officers and key employees under the 2007 Plan in each year since 2007. From 2007 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. For 2010 and 2011, participants elected to receive payment in either stock, or 50% cash and 50% stock.
Restricted stock unit awards vest and settle over a four-year period. In addition, officers and key employees accrue dividend rights on the vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2007 through 2009 awards are paid in cash. The dividends and interest for the 2010 and 2011 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using Pinnacle West’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately.
An additional grant of restricted stock unit awards was made to officers of the Company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award will vest 50% on February 15, 2013, 25% on February 15, 2014 and 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that an officer would have received if the officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held by the officer from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.
The following table is a summary of granted restricted stock units and stock grants and the weighted average fair value for the years ended 2011, 2010 and 2009:
(a) weighted average fair value
The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2011 and changes during the year. This table represents only the stock portion of restricted stock units, per the election on payment discussed in the paragraph above:
The amount of cash required to settle the payments on restricted stock units is (dollars in millions):
Performance Share Awards
Performance share awards have been granted to officers and key employees under the 2007 Plan since 2008. Performance share awards contain two performance elements criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.
The 2009 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth of relevant companies in a specified utilities index, and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 150% of the target award. Shares received include dividend rights paid in cash equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.
The 2011 and 2010 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period as compared with the total shareholder return of all relevant companies in a specified utilities index and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.
Performance share awards are accounted for as a liability awards, with compensation cost initially calculated on the date of grant using Pinnacle West’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If the performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
The following table is a summary of the performance shares granted and the weighted average fair value for the years ended 2011, 2010 and 2009:
(a) weighted average grant date fair value
The following table is a summary of the status of performance shares, as of December 31, 2011 and changes during the year:
Retention Units
The retention unit awards have fully vested and settled on January 4, 2010; for any employee that was eligible to retire before that date, the employee’s retention units vested by retirement date and the compensation expense was recognized by retirement eligibility. Retention unit awards were granted to key employees in 2006 and 2007. Each retention unit award represented the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. Each retention unit award vested and settled in equal annual installments over a four-year period. In addition, the employee received a cash payment equal to the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. As this award was accounted for as a liability award, compensation costs, initially measured based on Pinnacle West’s stock price on the grant date, were remeasured at each balance sheet date, using Pinnacle West’s closing stock price.
The amount of cash to settle the payment on the first business day of 2010 was $1.3 million, and 2009 was $1.1 million.
Incentive Shares
On January 21, 2009, the Human Resources Committee approved under the 2007 Plan payment of 2008 incentive awards to officers in the form of a Pinnacle West common stock grant. A total of 138,756 shares were issued for this stock grant with a grant date fair value of $32.58 per share. The stock grant was included in stock compensation expense in 2008.
Stock Options
Pinnacle West has not granted stock options since 2004. Currently outstanding stock option grant terms cannot be longer than 10 years and options cannot be repriced during their terms.
The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2011:
Cash received from options exercised under our share-based payment arrangements was $1.8 million for 2011, $4.6 million for 2010, and $3 million for 2009. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements were immaterial for all years.
The intrinsic value of options exercised was immaterial for all years.
As of December 31, 2011, there was $20.5 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2.2 years. The total fair value of shares vested during 2011 was $14.4 million, 2010 was $11 million, and 2009 was $10 million.
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $23 million in 2011, $15 million in 2010, and $5 million in 2009. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $9 million in 2011, $6 million in 2010, and $2 million in 2009. APS’s share of compensation cost that has been charged against income was $22 million in 2011, $15 million in 2010, and $4 million in 2009.
Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock during 2011. |
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17. 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.
Financial data for 2011, 2010 and 2009 is provided as follows (dollars in millions):
(a) All other activities relate to SunCor, APSES and El Dorado. Income from discontinued operations for 2011 is primarily related to the sale of our investment in APSES. Income from discontinued operations for 2010 is primarily related to the APSES sale of its district cooling business. Loss from discontinued operations for 2009 is primarily related to real estate impairment charges at SunCor (see Note 22). None of these segments is a reportable business segment. |
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18. Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative 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. Derivative instruments that meet certain hedge accounting criteria are designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities and delivery points) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 14 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchase and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of December 31, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.
APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives, pursuant to the PSA mechanism, that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
As of December 31, 2011, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
Gains and Losses from Derivative Instruments
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedges during the year ended December 31, 2011 and December 31, 2010 (dollars in thousands):
(a) During the year ended December 31, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.
During the next twelve months, we estimate that a net loss of $80 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.
The following table provides information about gains and losses from derivative instruments not designated as accounting hedges during the year ended December 31, 2011 and December 31, 2010 (dollars in thousands):
Fair Values of Derivative Instruments in the Consolidated Balance Sheets
The following table provides information about the fair value of our risk management activities reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. Amounts are as of December 31, 2011 (dollars in thousands):
(a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Other represents counterparty netting, options, and other risk management contracts.
The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2010 (dollars in thousands):
(a) Includes $11 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Includes $1 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception. (c) Other represents counterparty netting, options, and other risk management contracts.
Credit Risk and Credit Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 80% of Pinnacle West’s $80 million of risk management assets as of December 31, 2011. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2011 (dollars in millions):
(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote above.
We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $194 million if our debt credit ratings were to fall below investment grade. |
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19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2011, 2010 and 2009 (dollars in thousands):
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20. Palo Verde Sale Leaseback Variable Interest Entities
In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, has fair value purchase options, and is obligated to decommission the leased assets.
As a result of consolidation we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for 2011, 2010 and 2009 of $28 million, $20 million and $19 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Consolidated Statements of Cash Flows, but does not impact net cash flows.
Our Consolidated Balance Sheets at December 31, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):
Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2011, APS would have been required to pay the noncontrolling equity participants approximately $141 million and assume $97 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Consolidated Balance Sheets.
For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements. |
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21. Discontinued Operations
SunCor — In 2009, our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. All activity for the income statement and prior comparative period income statement amounts are included in discontinued operations. In 2010 and 2009, SunCor recorded real estate impairment charges (see Note 22). SunCor’s asset sales resulted in no gain for 2010 and 2009 due to the impairment charges discussed above. At December 31, 2011, SunCor had approximately $9 million of assets on its balance sheet, including $7 million of intercompany receivables, and $2 million of other assets. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.
APSES — On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain from discontinued operations of approximately $10 million. In June 2010, APSES sold its district cooling business. As a result of that sale, we recorded an after-tax gain from discontinued operations of approximately $25 million. Prior period income statement amounts related to these sales and the associated revenues and costs are reflected in discontinued operations.
The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009 (dollars in millions):
(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million for the year ended December 31, 2011, $4 million for the year ended December 31, 2010, and $113 million for the year ended December 31, 2009. |
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22. Real Estate Impairment Charge
In 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. As a result, SunCor took impairment charges in 2009 and 2010. There have been no additional impairments in 2011. All SunCor’s operations are reflected in discontinued operations (see Note 21). The detail of the impairment charge is as follows (dollars in millions, and before income taxes):
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23. Nuclear Decommissioning Trust
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2011 and December 31, 2010 (dollars in millions):
(a) Net payables relate to pending securities sales and purchases.
(a) Net payables relate to pending securities sales and purchases.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
(a) Proceeds are reinvested in the trust.
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2011 is as follows (dollars in millions):
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF INCOME (in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION SCHEDULE II — RESERVE FOR UNCOLLECTIBLES (dollars in thousands)
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ARIZONA PUBLIC SERVICE COMPANY SCHEDULE II — RESERVE FOR UNCOLLECTIBLES (dollars in thousands)
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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. |
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 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. |
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.
Effective January 1, 2010, 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). This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012. Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues. |
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 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 for the asset retirement obligations related to its regulated assets. This regulatory liability represents 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, 2011 were as follows:
· Fossil plant — 18 years; · Nuclear plant — 29 years; · Other generation — 28 years; · Transmission — 38 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. |
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 10.25% for 2011, 9.2% for 2010, and 5.9% for 2009. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service. |
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. |
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 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 unobservable inputs, such as models and other valuation methods, 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. |
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 that may qualify as derivatives, including futures, forwards, options and swaps. As part of our overall risk management program, we use such 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 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. |
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. |
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 and 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. |
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. |
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 liability 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. |
We did not have any real estate investments at December 31, 2011 and December 31, 2010 on our Consolidated Balance Sheets. For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets; we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used” in 2010 and 2009. When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. Our internal models used inputs that we believe were consistent with those that would be used by market participants. |
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. |
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. |
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. |
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(a) This asset represents the future recovery in earnings of under-funded pension and other postretirement benefits obligation costs through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (b) See “Cost Recovery Mechanisms” discussion above. (c) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.” |
(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. See Note 12. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. |
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(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average rate for the variable rate pollution control bonds was 0.09% at December 31, 2011 and 0.32% at December 31, 2010. (c) The weighted-average interest rate was 5.27% at December 31, 2011 and 5.29% at December 31, 2010. (d) The weighted-average interest rate was 1.794% at December 31, 2011. |
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(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes. (b) In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes. |
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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2011, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables.
(b) This category consists primarily of debt securities issued by municipalities.
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2010, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables. (b) This category consists primarily of municipal debt securities issued by municipalities. |
(a) The return for December 31, 2010 represents the return on assets held as of March 31, 2010, the beginning of the period in which all the assets were transferred out of Level 3.
(b) Transfers into and out of Level 3 are measured at the beginning of the period in which the transfer occurs. Transfers out of Level 3 during 2010 relate to our Real Estate Common and Collective Trust being transferred to a Level 2 investment. During 2009 the Real Estate Common and Collective Trust had special redemption restrictions in place, which limited our ability to transact at the trust’s NAV. During 2010 these special redemption restrictions were lifted, and in 2010 and 2011 we were able to transact at the NAV according to the trust’s contractual redemption policy. |
(a) The estimated future other benefit payments take into account the Medicare Part D subsidy. |
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(a) See Note 20.
(b) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(c) Weighted average of interests. |
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(a) Total take-or-pay commitments are approximately $541 million. The total net present value of these commitments is approximately $401 million. |
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(a) The March 31, 2011 results were adjusted for the effect of reclassifications for discontinued operations (see Note 21). The adjustments resulted in a reduction in operating revenues of $10,728, a reduction in operations and maintenance of $1,457, a reduction in operating income of $1,357, a decrease in income taxes of $356, and a decrease in income from continuing operations of $1,043. |
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The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a) Primarily consists of heat rate options and other long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 18. (c) Represents nuclear decommissioning trust net pending securities sales and purchases.
The following table presents the fair value at December 31, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a) Primarily consists of long-dated electricity contracts. (b) Represents counterparty netting, margin and collateral. See Note 18. (c) Represents nuclear decommissioning trust net pending securities sales and purchases. |
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(a) weighted average fair value |
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(a) weighted average grant date fair value
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(a) All other activities relate to SunCor, APSES and El Dorado. Income from discontinued operations for 2011 is primarily related to the sale of our investment in APSES. Income from discontinued operations for 2010 is primarily related to the APSES sale of its district cooling business. Loss from discontinued operations for 2009 is primarily related to real estate impairment charges at SunCor (see Note 22). None of these segments is a reportable business segment. |
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(a) During the year ended December 31, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges. |
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The following table provides information about the fair value of our risk management activities reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. Amounts are as of December 31, 2011 (dollars in thousands):
(a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Other represents counterparty netting, options, and other risk management contracts.
The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2010 (dollars in thousands):
(a) Includes $11 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception. (b) Includes $1 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception. (c) Other represents counterparty netting, options, and other risk management contracts. |
(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote above. |
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(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million for the year ended December 31, 2011, $4 million for the year ended December 31, 2010, and $113 million for the year ended December 31, 2009. |
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(a) Net payables relate to pending securities sales and purchases.
(a) Net payables relate to pending securities sales and purchases.
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(a) Proceeds are reinvested in the trust.
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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 $69 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 cash refunds are not expected to be received in the next twelve months.
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):
Included in the balances of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $7 million and $16 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 few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
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 Statement of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2011, we have recognized $4 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):
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):
The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
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. In 2011, APS increased regulatory liabilities by a total of $62 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):
As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($67 million) and federal net operating losses ($92 million), both of which first begin to expire in 2029, and other federal and state loss carryforwards ($13 million) which first begin to expire in 2014. |
S-1. Income Taxes
APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
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 currently enacted 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 ITCs 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.
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):
Included in the balance of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $6 million and $15 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 few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of income as income tax expense. The amount of interest recognized in the Statements of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.
The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2011, we have recognized $4 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 APS’s income tax expense are as follows (dollars in thousands):
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
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 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. In 2011, APS increased regulatory liabilities by a total of $62 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):
As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($60 million) and federal net operating losses ($37 million), both of which first begin to expire in 2031, and other federal and state loss carryforwards ($10 million) which first begin to expire in 2013. |
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13. Selected Quarterly Financial Data (Unaudited)
Consolidated quarterly financial information for 2011 and 2010 is as follows (dollars in thousands, except per share amounts):
(a) The March 31, 2011 results were adjusted for the effect of reclassifications for discontinued operations (see Note 21). The adjustments resulted in a reduction in operating revenues of $10,728, a reduction in operations and maintenance of $1,457, a reduction in operating income of $1,357, a decrease in income taxes of $356, and a decrease in income from continuing operations of $1,043.
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S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2011 and 2010 is as follows (dollars in thousands):
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19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2011, 2010 and 2009 (dollars in thousands):
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S-3. Other Income and Other Expense
The following table provides detail of APS’s other income and other expense for 2011, 2010 and 2009 (dollars in thousands):
(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
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(a) The March 31, 2011 results were adjusted for the effect of reclassifications for discontinued operations (see Note 21). The adjustments resulted in a reduction in operating revenues of $10,728, a reduction in operations and maintenance of $1,457, a reduction in operating income of $1,357, a decrease in income taxes of $356, and a decrease in income from continuing operations of $1,043. |
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(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery). |
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