PINNACLE WEST CAPITAL CORP
ITEM 1. BUSINESS
Pinnacle West
Pinnacle West is a holding company that conducts business through its subsidiaries. We derive the majority of our revenues and earnings from our wholly-owned subsidiary, APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most 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.
Operating Revenues (in thousands):
Pinnacle West’s other first-tier subsidiaries are SunCor, APSES and El Dorado. Additional information related to these businesses is provided later in this report.
Our reportable business segments are the regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution, and the real estate segment, which consists of real estate development and investment activities in the western United States.
Due to the continuing distressed conditions in the real estate markets, in 2009 our real-estate subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. As a part of this plan to sell substantially all of SunCor’s assets, the real estate segment may no longer be a reporting segment in the future. See Note 17 for financial information of our business segments.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
APS currently provides electric service to approximately 1.1 million customers. We own or lease more than 6,280 MW of regulated generation capacity and we hold a mix of both long-term and short-term power purchase agreements for additional capacity, including a variety of agreements for the purchase of renewable energy. During 2009, no single purchaser or user of energy accounted for more than 1.1% of our electric revenues.
The following map shows APS’ retail service territory, including the locations of its generating facilities and principal transmission lines.
Energy Sources and Resource Planning
To serve its customers, APS obtains power through its various generation stations and through power purchase agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’ sources of energy by fuel type during 2009 were: coal - 36.3%; nuclear - 25.9%; purchased power - 20.6%; and gas, oil and other - 17.2%.
Generation Facilities
APS has ownership interests in or leases the coal, nuclear, gas, oil and solar generating facilities described below. For additional information regarding these facilities, see Item 2.
Coal Fueled Generating Facilities
Four Corners - Four Corners is a 5-unit coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS has a total entitlement from Four Corners of 785 MW. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” in Item 2 for additional information. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016.
Cholla - Cholla is a 4-unit coal-fired power plant located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates that unit for PacifiCorp. APS has a total entitlement from Cholla of 647 MW. APS purchases all of Cholla’s coal requirements from a coal supplier that mines all of the coal under long-term leases of coal reserves with the federal government and private landholders. The Cholla coal contract runs through 2024. APS has the ability under the contract to reduce its annual coal commitment and purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to purchase coal required for increased operating capacity. APS believes that the current fuel contracts and competitive fuel supply options ensure the continued operation of Cholla for its useful life. In addition, APS has a long-term coal transportation contract.
Navajo Generating Station - The Navajo Plant is a 3-unit coal-fired power plant located in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3. APS has a total entitlement from the Navajo Plant of 315 MW. The Navajo Plant’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Plant is under contract with its coal supplier through 2011, with options to extend through 2019. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” in Item 2 for additional information.
These coal plants face uncertainties related to existing and potential legislation and regulation that could significantly impact their economics and operations. See “Environmental Matters” below and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7 for environmental and climate change developments impacting these coal facilities. See Note 11 for information regarding APS’ coal mine reclamation obligations.
Nuclear
Palo Verde Nuclear Generating Station - Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1% combined interest in that Unit. APS has a total entitlement from Palo Verde of 1,146 MW.
Palo Verde Leases - In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases or to purchase the property for fair market value at the end of the lease terms. APS must give notice to the respective lessors between December 31, 2010 and December 31, 2012 if it wishes to exercise, or not exercise, either of these options. We are analyzing these options. See Notes 9 and 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
Palo Verde Operating Licenses - Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power. On December 15, 2008, APS applied for renewed operating licenses for the Palo Verde units for a period of 20 years beyond the expirations of the current licenses. The current NRC schedule for the applications estimates a final decision in the fall of 2011. APS is making preparations to secure resources necessary to operate the plant for the period of extended operation.
Palo Verde Fuel Cycle - The fuel cycle for Palo Verde is comprised of the following stages:
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mining and milling of uranium ore to produce uranium concentrates;
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conversion of uranium concentrates to uranium hexafluoride;
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enrichment of uranium hexafluoride;
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fabrication of fuel assemblies;
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utilization of fuel assemblies in reactors; and
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storage and disposal of spent nuclear fuel.
The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates through 2011. New contracts are currently being negotiated that would meet the plant’s conversion services needs through 2011, taking into account available inventory. The participants have also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo Verde’s fuel assembly fabrication services until at least 2015.
Spent Nuclear Fuel and Waste Disposal - Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, through 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation. If uncertainties regarding the United States government’s obligation to accept and store used fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation. See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of spent nuclear fuel and waste disposal.
NRC Inspection -On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) due to electrical output issues with the Unit 3 emergency diesel generator that occurred in 2006. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), subjecting it to an enhanced NRC inspection regime. Although only Palo Verde Unit 3 was in NRC’s Column 4, in order to adequately assess the need for improvements, APS’ management conducted site-wide assessments of equipment and operations.
On March 24, 2009, the NRC informed APS that it was removing Palo Verde Unit 3 from Column 4, removing Units 1 and 2 from the “one degraded cornerstone” column (“Column 3”) of the NRC’s Action Matrix, and returning all three units of the plant to “Column 1” routine inspection and oversight by the NRC. This notification followed the NRC’s completion of its inspections of the corrective actions taken by Palo Verde to address the performance deficiencies that caused the NRC to place Unit 3 into Column 4 and Units 1 and 2 into Column 3.
Nuclear Decommissioning Costs - APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’ ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge, which allows APS to maintain its external sinking fund mechanism. See Note 12 for additional information about APS’ nuclear decommissioning costs.
Palo Verde Liability and Insurance Matters - See “Palo Verde Nuclear Generating Station - Nuclear Insurance” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
Natural Gas and Oil Fueled Generating Facilities
APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; and Yucca, located near Yuma. Several of the units at Saguaro and Yucca run on either gas or oil. APS has one oil power plant, Douglas, located in the town of Douglas, Arizona. APS owns and operates each of these plants with the exception of one combustion turbine unit and one steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District. APS has a total entitlement from these plants of 3,389 MW. Gas for these plants is acquired through APS’ hedging program. APS has long-term gas transportation agreements with three different companies, which provide APS with fuel delivery through 2024. Fuel oil is acquired under short-term purchases delivered primarily to West Phoenix, where it is distributed to APS’ other oil power plants by truck.
Solar Facilities
APS owns and operates more than thirty on-grid and off-grid small solar systems around the state. Together they have the capacity to produce about 6 MW of renewable energy. This fleet of solar systems is anchored by a 3 MW facility located at the Prescott Airport and a 1 MW facility located at APS’ Saguaro power plant.
Purchased Power Contracts
In addition to its own available generating capacity, APS purchases electricity under various arrangements, including long-term contracts and purchases through short-term markets to supplement its owned or leased generation and hedge its energy requirements. A substantial portion of APS’ purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. (See Note 18.) APS continually assesses its need for additional capacity resources to assure system reliability. APS does not expect to require new conventional generation sources sooner than 2017, due to planned additions of renewable resources and energy efficiency initiatives.
Purchased Power Capacity - APS’ purchased power capacity under long-term contracts, including its renewable energy portfolio, is summarized in the tables below. All capacity values are based on net capacity unless otherwise noted.
CONVENTIONAL AGREEMENTS:
(a)
The capacity under this agreement varies by month, with a maximum capacity of 90 MW.
(b)
The amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually. This contract is being replaced with a purchase agreement for approximately 36MW starting June 15, 2010 and ending June 14, 2020.
(c)
This is a seasonal capacity exchange agreement under which APS receives electricity during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity during the winter season (from October 15 to February 15).
(d)
The capacity under this agreement increases in a phased manner over the first three years to reach the 100 MW level by the summer of 2012.
RENEWABLE AGREEMENTS:
(a)
Represents contracted capacity.
(b)
Details of these agreements have not yet been publicly announced.
Current and Future Resources
Current Demand and Reserve Margin
Electric power demand is generally seasonal. In Arizona, demand for power peaks during the hot summer months. APS’ 2009 peak one-hour demand on its electric system was recorded on July 27, 2009 at 7,218 MW, compared to the 2008 peak of 7,026 MW recorded on August 1, 2008. APS’ operable generating capacity, together with firm purchases totaling 2,657 MW, including short-term seasonal purchases and unit contingent purchases, resulted in an actual reserve margin, at the time of the 2009 peak demand, of 15.6%. The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned plant and transmission outages and technical problems.
Future Resources and Resource Plan
On January 29, 2009, APS submitted a Resource Plan Report to the ACC proposing a diverse portfolio of generation resources to address the projected 60% increase in customer peak demand by 2025, which equates to approximately 6,500 MW of new capacity resources and accounts for both new resources needed to meet growing customer loads as well as resources that will be needed to replace expiring long-term purchases.
On December 15, 2009, the ACC approved a modified resource planning rule that requires APS to file by April 1st of each even year its resource plans for the next fifteen-year period. The ACC’s modified rule also requires APS to file its first resource plan within 120 days after the rule becomes effective. APS believes the modified rule will likely become effective by mid-2010, requiring APS to file a revised resource plan by the Fall of 2010, which will supercede the January 2009 filing. The modified rule also requires the ACC to issue an order with its acknowledgment of APS’ resource plan within approximately nine months following its submittal.
Renewable Energy Standard
In connection with its ongoing resource planning efforts, APS continues to focus on increasing the percentage of its energy that is produced by renewable resources. In 2006, the ACC adopted the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard” or “RES”). Under the Renewable Energy Standard, 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. The renewable energy requirement is 2.5% of retail electric sales in 2010 and increases annually until it reaches 15% in 2025. In APS’ recent retail rate case settlement agreement, APS committed to, among other things, an interim renewable energy target of 10% by year-end 2015, which is double the existing RES target of 5% for that year. (See Note 3.) A component of the original RES is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties). Accordingly, under the original RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed energy requirement is 20% of the overall RES requirement of 2.5% in 2010 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. The following table summarizes these requirement standards and their timing:
APS has a diverse portfolio of renewable resources including wind, geothermal, solar and biomass, which currently collectively generates over 210 MW of renewable energy for its customers via owned or contracted renewable generation facilities and an additional installed capacity of 21 MW equivalent of customer-sited distribution energy systems in operation. These current renewable generation projects are either APS-owned solar facilities, as described under “Generation Facilities - Solar Facilities” above, are acquired through long-term purchased power agreements, as described under “Purchased Power Contracts” above, or are partially funded by renewable incentives we offer to our customers. APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.
Demand Side Management and Energy Efficiency
Arizona regulators are placing an increased focus on energy efficiency and demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. In December 2009, the ACC initiated Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% annual energy savings by 2020. An ambitious standard, such as that proposed, will likely increase participation by APS customers in these conservation and energy efficiency programs, which in turn will likely impact Arizona’s future energy resource needs. Energy Efficiency Rules are expected to be formally adopted in 2010. (See Note 3 for demand side management and energy efficiency obligations resulting from APS’ recent retail rate case settlement.)
Economic Stimulus Projects
Through the American Recovery and Reinvestment Act of 2009 (“ARRA”), the Federal government is making a number of programs available for utilities to develop renewable resources, improve reliability and create jobs from the availability of economic stimulus funding. Certain programs are also available through the State of Arizona.
In 2009, the DOE announced an ARRA commitment to fund the majority of a carbon dioxide emission reduction research and development project in the amount of $70.5 million, which will be located at our Cholla power plant. It also announced a commitment to fund, subject to final negotiations, a $3.3 million high penetration photovoltaic generation study related to a proposed APS community power project in Flagstaff, Arizona. These funding amounts are contingent upon meeting certain project milestones, including DOE-established budget parameters, over the next four years.
APS has also been selected by the State of Arizona’s Department of Commerce as a sub-recipient under the State’s ARRA award for the implementation of various distributed energy and energy efficiency programs in Arizona. The State is in final negotiations to provide APS with approximately $3.7 million from the State’s ARRA grant so that APS can implement certain solar water heater, photovoltaic and/or wind energy related community projects.
APS intends to continue to evaluate additional funding opportunities under the ARRA programs that may be of benefit to APS’ business, operations or community activities.
Competitive Environment and Regulatory Oversight
Retail
The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer or encumbrance of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.
APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements. This practice is becoming more popular with customers installing or having installed products such as roof top solar panels to meet or supplement their energy needs.
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to review the Court of Appeals decision.
To date, the ACC has taken no further or substantive action on either the rules or the prior orders authorizing competitive electric service providers in response to the final Court of Appeals decision. However, as a result of a new request for authorization to provide competitive retail electric service by Sempra Energy Solutions, LLC, the ACC directed the ACC staff to investigate whether such retail competition was in the public interest and what legal impediments remain to competition in light of the Court of Appeals decision referenced above. The ACC staff’s report on the results of its investigation is due to be filed with the ACC on April 1, 2010. At present, only limited electric retail competition exists in Arizona and only with certain entities not regulated by the ACC.
Currently, there are two matters pending with the ACC that involve a business model where customers pay solar vendors for the installation and operation of solar facilities based on the amount of energy produced. The ACC must make a determination whether these entities would be considered “public service corporations” under the Arizona Constitution, causing them to be regulated by the ACC. Use of such products by customers within our territory would result in some level of competition; however, at this time we do not feel this would materially impact our financial results. APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’ service territory.
Wholesale
The FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’ transmission rates.) During 2009, approximately 4.8% of APS’ electric operating revenues resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel and purchased power risks in connection with the costs of serving retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS markets, hedges and trades in electricity and fuels.
Environmental Matters
Climate Change
Legislative and Regulatory Initiatives. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. On June 26, 2009, the House of Representatives approved the American Clean Energy and Security Act of 2009, H.R. 2454. In addition to establishing clean energy programs, H.R. 2454 would establish a greenhouse gas emission cap-and-trade system starting in 2012 applicable to about 85% of all emission sources in the nation. A similar bill (Kerry-Boxer Bill, S. 1733) is pending before the Senate. Both of these bills would allocate a certain number of allowances to local distribution companies (such as APS) through 2030.
To the extent APS’ emissions exceed the allowances allocated to it under these proposed bills, APS would have an “allowance gap.” APS would have to purchase enough allowances from the market to fill these gaps. The table below illustrates the estimated cost impacts to APS in 2012 to acquire allowances to fill its allowance gap, and the associated retail rate impacts to customers under H.R. 2454 and S. 1733. For purposes of this illustration, the table provides three assumed allowance prices of $20, $50 and $75 per metric ton.
The actual economic and operational impact of this or any similar legislation on the Company depends on a variety of factors, none of which can be fully known until such legislation passes and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed emissions; whether the permitted emissions allowances will be allocated to source operators free of cost or auctioned; the cost to reduce emissions or buy allowances in the marketplace; and the availability of offsets and mitigating factors to moderate the costs of compliance. At the present time, we cannot predict what form of legislation, if any, will ultimately pass.
The EPA recently determined that greenhouse gas emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act. The recent endangerment finding could result in the EPA issuing new regulatory requirements under the Clean Air Act for new and modified major greenhouse gas emitting sources, including power plants. On September 30, 2009, the EPA announced a proposed rule under the Clean Air Act requiring certain new and modified stationary sources, including power plants, to use the best available control technology to minimize greenhouse gas emissions. Several groups have filed lawsuits challenging the EPA’s endangerment finding. At the present time we cannot predict whether the proposed stationary source rule will be adopted in its current or a revised form, what other rules or regulations may ultimately result from the EPA’s finding, whether the parties challenging the endangerment finding will be successful, and what impact the proposed rule and potential other rules or regulations will have on APS’ operations.
In anticipation of potential future regulation of greenhouse gases under the Clean Air Act as described above, on September 22, 2009, the EPA issued a mandatory greenhouse gas reporting rule. The rule applies to direct greenhouse gas emissions from facilities such as APS’ power plants. We expect that our incremental costs to comply with this rule will be immaterial since APS already routinely reports CO2 and other greenhouse gas emissions from its plants.
In addition to federal legislative initiatives, state specific initiatives may also impact our business. While Arizona has not yet enacted any state specific legislation regarding greenhouse gas emissions, the California legislature enacted AB 32 and SB 1368 in 2006 to address greenhouse gas emissions and New Mexico is currently considering proposed legislation to address these issues. We are monitoring these and other state legislative developments to understand the extent to which they may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to continue their participation in certain coal-fired power plants.
If any emission reduction legislation or regulations are enacted, we will assess our compliance alternatives, which may include replacement of existing equipment, installation of additional pollution control equipment, purchase of allowances, retirement or suspension of operations at certain coal-fired facilities, or other actions. Although associated capital expenditures or operating costs resulting from greenhouse gas emission regulations or legislation could be material, we believe that we would be able to recover the costs of these environmental compliance initiatives through our rates.
Regional Initiative. In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (“WCI”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also joined WCI. WCI participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. After soliciting public comment, in September 2008 WCI issued the design of a cap-and-trade program for greenhouse gas emissions. Due in part to the recent activity at the federal level discussed above, the initiative’s momentum and the movement toward detailed proposed rules has slowed. On February 2, 2010, Arizona’s Governor issued an executive order stating that Arizona will continue to be a member of WCI to monitor its advancements in this area, but it will not implement the WCI regional cap-and-trade program. As a result, while we continue to monitor the progress of WCI, at the present time we do not believe it will have a material impact on our operations.
Company Response to Climate Change Initiatives. We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates that promote energy conservation, renewable energy use and energy efficiency, and implementation of an active technology innovation effort to evaluate potential emerging new technologies. APS currently has a diverse portfolio of renewable resources including wind, geothermal, solar and biomass and we are focused on increasing the percentage of our energy that is produced by renewable resources.
On May 18, 2009, we submitted a comprehensive Climate Change Management Plan to the ACC to comply with an ACC order that directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. The Climate Change Management Plan details scientific, legislative and policy issues, potential physical and financial risks to APS, greenhouse gas emission inventory, APS technology innovation and greenhouse gas reduction efforts, and our companies’ strategic approach to climate change management.
In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily joined the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. APS will not participate in the Climate Registry after 2009 because we will be reporting substantially the same information under the new EPA reporting rule. Pinnacle West has also reported, and will continue to report, greenhouse gas emissions in its annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). In addition to emissions data, the report provides information related to the Company, its approach to sustainability and its workplace and environmental performance, as well as a copy of our Climate Change Management Plan discussed above. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.
Climate Change Lawsuits. 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. 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 court in November 2009. We believe the action is without merit and intend to continue to defend against the claims.
Similar nuisance lawsuits are currently pending in the 2nd and 5th Circuits. In the fall of 2009, the U.S. Courts of Appeals for each of these Circuits reversed lower court decisions and ruled that the plaintiffs in both cases could bring common law nuisance lawsuits against coal-burning utilities allegedly contributing to global warming. Both cases, as well as the Kivalina case, raise political and legal considerations, including whether the courts can or should be making climate change policy decisions. We are not a party to either of these two lawsuits, but will monitor these developments and their potential industry impacts.
EPA Environmental Regulation
Regional Haze Rules. Over a decade ago, the EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas. The rules require states (or, for sources located on tribal land, the EPA) to determine what pollution control technologies constitute the “best available retrofit technology” (“BART”) for certain older major stationary sources. The EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis.
ADEQ is currently undertaking a rulemaking process to address the Clean Air Visibility Rule requirements. ADEQ’s rules were due to EPA Region 9 in December 2007, but are expected to be submitted in 2010. As part of the rulemaking process, ADEQ required APS to perform a BART analysis for Cholla. APS completed a BART analysis for Cholla and submitted its BART recommendations to ADEQ on February 4, 2008. The recommendations include the installation of certain pollution control equipment that APS believes constitutes BART. Once APS receives ADEQ’s final determination as to what constitutes BART for Cholla, we will have five years to complete the installation of the equipment and to achieve the emission limits established by ADEQ. However, in order to coordinate with the plant’s other scheduled activities, APS is currently implementing portions of its recommended plan for Cholla on a voluntary basis. Costs related to the implementation of these portions of our recommended plan are included in our environmental expenditure estimates (see “Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7).
EPA Region 9 requested that APS, as the operating agent for Four Corners, and SRP, as the operating agent for the Navajo Plant, perform a BART analysis for Four Corners and the Navajo Plant, respectively. APS and SRP each submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for these plants. Based on the analyses and comments received through EPA’s rulemaking process, the EPA will determine what it believes constitutes BART for each plant.
The EPA recently issued an Advanced Notice of Proposed Rulemaking (ANPR) seeking public comments on what constitutes BART for each plant. The public comment period expired in October, 2009, but the EPA has extended the comment period until March 20, 2010 for the Navajo and Hopi Tribes. We expect that the EPA will issue proposed and final BART determinations for Four Corners and the Navajo Plant in 2010. The participant owners of Four Corners and the Navajo Plant will have five years after the EPA issues its final determination to achieve compliance with their respective BART requirements. In addition, on February 16, 2010, a group of environmental organizations filed a petition with the Departments of Interior and Agriculture requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners.
APS’ recommended plan for Four Corners includes the installation of combustion control equipment, with an estimated cost to APS, based on preliminary engineering estimates and APS’ Four Corners ownership interest, of approximately $50 million. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $422 million for Four Corners. SRP’s recommended plan for the Navajo Plant includes the installation of combustion control equipment, with an estimated cost to APS of approximately $6 million based on APS’ Navajo ownership interest. If the EPA determines that post-combustion controls are required, APS’ total costs could be up to approximately $93 million for Navajo. The Four Corners and Navajo Plant participants’ obligations to comply with the EPA’s final BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.
In order to coordinate with each plant’s other scheduled activities, the plants are currently implementing portions of their recommended plans described above on a voluntary basis. APS’ share of the costs related to the implementation of these portions of the recommended plans are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7).
Mercury and other Hazardous Air Pollutants. In early 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the Clean Air Mercury Rule (“CAMR”), which was adopted by the EPA to regulate mercury emissions from coal fired power plants. As a result, the law in effect prior to the adoption of the CAMR became the applicable law, and the EPA is now required to adopt final maximum achievable control technology emissions (“MACT”) standards. Under a proposed consent decree, the EPA has agreed to issue final MACT standards for mercury and other hazardous air pollutants by November 2011. If the consent decree is finalized in its current form, APS will have three years after the EPA issues its final rule to achieve compliance, which would likely require APS to install additional pollution control equipment.
APS has installed, and continues to install, certain of the equipment necessary to meet the anticipated standards. The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7).
Federal Implementation Plan (“FIP”). In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Plant, which it later revised in 2006. The FIP for Four Corners was finalized in 2009, and we do not believe compliance with its required limits will have a material adverse impact on our financial position, results of operations or cash flows. The proposed FIP for the Navajo Plant is still pending. APS cannot currently predict the effect of this proposed FIP on its financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.
Coal Combustion Waste. The EPA is expected to issue proposed regulations governing the handling and disposal of coal combustion byproducts (“CCBs”), such as fly ash and bottom ash. APS currently disposes of CCBs in ash ponds and dry storage areas at Cholla and Four Corners, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete production. The EPA is evaluating options that include regulation of CCBs under non-hazardous waste standards, hazardous waste standards, or a combination of both, and a potential phase out of the disposal of CCBs through the use of ash ponds. A proposed rule is expected during the first quarter of 2010. We do not know when the EPA will issue a final rule, including required compliance dates. While APS continues to advocate for the regulation of CCBs as non-hazardous waste, we cannot currently predict the outcome of the EPA’s actions and whether such actions will have a material adverse impact on our financial position, results of operations or cash flows.
Section 114 Request. On April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the Clean Air Act (“NSR”). Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits by the EPA. APS has responded to the EPA’s request and is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“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, Operable Unit 3 (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. APS estimates that its costs related to this investigation and study will be approximately $1.2 million, which is reserved as a liability on its financial statements. 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.
By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric utility companies, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from APS and four other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to APS, we do not expect that the resolution of this matter will have a material adverse impact on APS’ financial position, results of operations, or cash flows.
Manufactured Gas Plant Sites. Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.
Navajo Nation Environmental Issues
Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Energy Sources and Planning - Generation - Coal Fueled Generating Facilities” above for additional information regarding these plants.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.
On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the Courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.
Water Supply
Assured supplies of water are important for APS’ generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.
Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set in this matter.
APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, cash flows or liquidity.
The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
BUSINESS OF OTHER SUBSIDIARIES
SunCor
SunCor has been a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. Due to the continuing distressed conditions in the real estate markets, in 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt.
At December 31, 2009, SunCor had total assets of about $166 million. At December 31, 2008, SunCor had total assets of about $547 million. The reduction in SunCor’s assets is primarily due to 2009 real estate impairment charges of $266 million and 2009 asset sales. SunCor’s remaining assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor’s remaining projects include master-planned communities and commercial and residential projects. Four of the master-planned communities and the commercial and residential projects are in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.
SunCor’s operating revenues were approximately $103 million in 2009, $75 million in 2008, and $190 million in 2007. SunCor’s net loss attributable to common shareholders was approximately $279 million in 2009, which includes $266 million (pre-tax) in real estate impairment charges. In 2009, income tax benefits related to SunCor operations were recorded by Pinnacle West in accordance with an intercompany tax sharing agreement. SunCor’s net loss attributable to common shareholders in 2008 was $26 million, which included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was approximately $24 million in 2007. Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income. (See Notes 22 and 23.)
See “Liquidity - Other Subsidiaries - SunCor” in Item 7 for a discussion of SunCor’s long-term debt, liquidity and capital requirements, and the SunCor-related risk factor in
ITEM 1A. RISK FACTORS
In addition to the factors affecting specific business operations identified in connection with the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results. Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.
REGULATORY RISKS
Our financial condition depends upon APS’ ability to recover costs in a timely manner from customers through regulated rates and otherwise execute its business strategy.
APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business, liquidity, results of operations and its ability to fully recover costs from utility customers in a timely manner. The ACC regulates APS’ retail electric rates and the FERC regulates rates for wholesale power sales and transmission services. While approved electric rates are intended to permit APS to recover its costs of service and earn a reasonable rate of return, the profitability of APS is affected by the rates it may charge. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS retail rate proceedings and ancillary matters which may come before the ACC and the FERC. In connection with its recent rate case settlement agreement, APS agreed not to request its next general retail rate increase to be effective prior to July 1, 2012. The ACC must also approve APS’ issuance of securities and any transfer of APS property used to provide retail electric service, and must approve or receive prior notification of certain transactions between us, APS and our respective affiliates. Decisions made by the ACC and the FERC could have a material adverse impact on our financial condition, results of operations or cash flows.
APS’ ability to conduct its business operations and avoid fines and penalties depends upon compliance with federal, state or local statutes and regulations, and obtaining and maintaining certain regulatory permits, approvals and certificates.
APS must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of agencies that regulate APS’ business, including the FERC, the NRC, the EPA and state and local governmental agencies. These agencies regulate many aspects of APS’ utility operations, including safety and performance, emissions, siting and construction of facilities, customer service and the rates that APS can charge retail and wholesale customers. Failure to comply can subject APS to, among other things, fines and penalties. For example, under the Energy Policy Act of 2005, the FERC can impose penalties (up to one million dollars per day per violation) for failure to comply with mandatory electric reliability standards. APS underwent its first mandatory regularly-scheduled triennial audit for compliance with these standards in early 2010 and expects to receive its results by mid-2010. In addition, APS is required to have numerous permits, approvals and certificates from these agencies. APS believes the necessary permits, approvals and certificates have been obtained for its existing operations and that APS’ business is conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of new or revised laws or regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.
The operation of APS’ nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. APS was subject to this heightened scrutiny until March 2009, when it exited the NRC’s enhanced inspection regime. The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements, may adversely affect APS’ financial condition, results of operations and cash flows.
APS is subject to numerous environmental laws and regulations, and changes in, or liabilities under, existing or new laws or regulations may increase APS’ cost of operations or impact its business plans.
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash and air pollution control wastes. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require APS to obtain and comply with a wide variety of environmental licenses, permits, and other approvals. If there is a delay or failure to obtain any required environmental regulatory approval, or if APS fails to obtain, maintain or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses. In addition, failure to comply with applicable environmental laws and regulations could result in civil liability or criminal penalties. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. APS cannot predict the outcome (financial or operational) of any related litigation that may arise.
Environmental Clean Up. APS has been named as a PRP for a Superfund site in Phoenix, Arizona and it could be named a PRP in the future for other environmental clean up at sites identified by a regulatory body. APS cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
Regional Haze. APS is currently awaiting final rulemaking from the EPA that could impose new requirements on Four Corners and the Navajo Plant. APS is also awaiting final rulemaking from ADEQ that could impose new requirements on Cholla. The EPA and ADEQ will require these plants to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plants. Depending upon the agencies’ final determinations of what constitutes BART for these plants, the financial impact of installing the required pollution control equipment could jeopardize the economic viability of the plants or the ability of individual participants to continue their participation in these plants.
Coal Ash. Recently Congress directed the EPA to propose new federal regulations governing the disposal of CCBs, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. APS currently disposes of CCBs in ash ponds and dry storage areas at Four Corners and Cholla, and also sells a portion of its fly ash for beneficial reuse as a constituent in concrete products. If the EPA regulates CCBs as a hazardous solid waste or phases out APS’ ability to dispose of CCBs through the use of ash ponds, APS could incur significant costs for CCB disposal and may be unable to continue its sale of fly ash for beneficial reuse.
New Source Review. The EPA has taken the position that many projects electric utilities have performed are major modifications that trigger NSR requirements under the Clean Air Act. The utilities generally have taken the position that these projects are routine maintenance and did not result in emissions increases, and thus are not subject to NSR. APS received and responded to a request from the EPA regarding projects and operations of Four Corners. If the EPA seeks to impose NSR requirements at Four Corners or any other APS plant, either through a lawsuit or a Notice of Violation, significant capital investments could be required to install new pollution control technologies. The EPA could also seek civil penalties.
Mercury and other Hazardous Air Pollutants. The EPA is required to adopt maximum achievable control technology emissions standards for mercury and other hazardous air pollutants by November 2011. Depending on the compliance requirements contained in the final rule, APS may need to make significant capital investments to install additional pollution control equipment to meet these new standards.
APS cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to it. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’ customers, could have a material adverse effect on its financial condition, results of operations or cash flows.
APS faces physical and operational risks related to climate change, and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit greenhouse gas emissions.
Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gases, including a lawsuit filed by the Native Village of Kivalina and the City of Kivalina, Alaska against us and several other utilities seeking damages related to climate change, which was dismissed but has been appealed.
Physical and Operational Risks. Projections for the Southwest United States from climate change models include an increase in the number of extreme hot days in the summer, less precipitation in the form of snow and the earlier runoff of snowmelt, increased wildfire potential, and the potential for water shortages. Assuming that the primary physical and operational risks to APS from climate change are increased potential for drought or water shortage, and a mild to moderate increase in ambient temperatures, APS believes it is taking the appropriate steps at this time to respond to these risks. Weather extremes such as drought and high temperature variations are common occurrences in the Southwest’s desert area, and these are risk factors that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperature due to climate change could require evaluation of certain materials used within its system and represents a greater challenge.
Financial Risks - Potential Legislation and Regulation. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. The House of Representatives approved a bill that would establish a greenhouse gas emission cap-and-trade system, and the Senate is currently considering proposed legislation. There is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect to greenhouse gas emissions.
If the United States Congress, or individual states or groups of states in which APS operates, ultimately pass legislation regulating the emissions of greenhouse gases, any resulting limitations on generation facility CO2 and other greenhouse gas emissions could result in the creation of substantial additional capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades and could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal-fired facilities, which constitute approximately 28% of APS’ generation capacity). A cap-and-trade program may also result in counterparty credit risk and financial liquidity risk since collateral is typically exchanged between counterparties as a means of mitigating risk in the event of a counterparty default.
At the state level, the California legislature enacted legislation to address greenhouse gas emissions. This legislation and other state-specific initiatives may affect APS’ business, including sales into the impacted states or the ability of its out-of-state power plant participants to continue their participation in certain coal-fired power plants, including Four Corners following expiration of the current lease term in 2016.
In addition, the EPA recently determined that greenhouse gas emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act. The recent endangerment finding could result in the EPA issuing new regulatory requirements under the Clean Air Act, beyond those related to motor vehicle emissions, which could impact APS’ power plants and result in substantial additional costs. Excessive costs to comply with future legislation or regulations could force APS and other similarly-situated electric power generators to retire or suspend operations at certain coal-fired facilities.
If APS cannot meet or maintain the level of renewable energy required under Arizona’s increasing Renewable Energy Standards or the higher commitment levels established in the settlement agreement, APS may be subject to penalties or fines for non-compliance.
The Renewable Energy Standard and Tariff (“RES”) requires APS to supply an increasing percentage of renewable energy each year, so that the amount of retail electricity sales from eligible renewable resources is at least 2.5% of total retail sales by 2010. This amount increases annually to 15% by 2025. In its recent retail rate case settlement agreement, APS agreed to exceed these standards and committed to an interim renewable energy target of 10% by year end 2015. A portion of this total renewable energy requirement must be met with an increasing percentage of distributed energy resources (generally, small scale renewable technologies located on customers’ properties). The distributed energy requirement is 20% of the overall RES requirement of 2.5% in 2010 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. If APS fails to implement any of its annual ACC-approved renewable resource plans, it may be subject to penalties imposed by the ACC, including APS’ inability to recover certain costs. Compliance with the distributed resource requirement is contingent upon customer participation. The development of any renewable generation facilities resulting from the RES is subject to many other risks, including risks relating to financing, permitting, technology, fuel supply, and the construction of sufficient transmission capacity to support these facilities.
Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on APS’ business and its results of operations.
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, APS cannot predict if, when, and the extent to which, additional competitors may re-enter APS’ service territory.
Currently, there are two matters pending with the ACC that involve a business model where customers pay solar vendors for the installation and operation of solar facilities based on the amount of energy produced. The ACC must make a determination whether these entities would be considered “public service corporations” under the Arizona Constitution, causing them to be regulated by the ACC. Use of such products by customers within APS’ territory would result in some level of competition.
As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect APS’ load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase, which could adversely affect our business.
OPERATIONAL RISKS
APS’ results of operations can be adversely affected by various factors impacting demand for electricity.
Weather Conditions. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, APS’ overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish APS’ results of operations and harm its financial condition.
Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires. Forest fires could threaten APS’ communities and electric transmission lines. Any damage caused as a result of forest fires could negatively impact APS’ results of operations.
Effects of Energy Conservation Measures and Distributed Energy. The ACC has initiated a rulemaking regarding energy efficiency, which includes a proposed 22% annual energy savings requirement by 2020. If adopted, this will likely increase participation by APS customers in energy efficiency and conservation programs and demand-side management efforts, which in turn would impact the demand for electricity. The proposed rules also include a requirement for the ACC to review and address financial disincentives, recovery of fixed costs and the recovery of net lost income/revenue that would result from lower sales due to increased energy efficiency requirements. The retail rate case settlement agreement establishes energy efficiency goals for APS that begin in 2010, subjecting APS to energy efficiency requirements in advance of the proposed rules described above.
APS must also meet certain distributed energy requirements. A portion of APS’ total renewable energy requirement must be met with an increasing percentage of distributed energy resources (generally, small scale renewable technologies located on customers’ properties). The distributed energy requirement is 20% of the overall RES requirement of 2.5% in 2010 and increases to 30% of the applicable RES requirement in 2012 and subsequent years. Customer participation in distributed energy programs would result in lower demand, since customers would be meeting some or all of their own energy needs. Reduced demand due to these energy efficiency and distributed energy requirements, unless offset through regulatory mechanisms, could have a material adverse impact on APS’ financial condition, results of operations or cash flows.
The operation of power generation facilities involves risks that could result in unscheduled power outages or reduced output, which could materially affect APS’ results of operations.
The operation of power generation facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications, occur from time to time and are an inherent risk of APS’ business. If APS’ facilities operate below expectations, especially during its peak seasons, it may lose revenue or incur additional expenses, including increased purchased power expenses.
The lack of access to sufficient supplies of water could have a material adverse impact on APS’ business and results of operations.
Assured supplies of water are important for APS’ generating plants. Water in the southwestern United States is limited and various parties have made conflicting claims regarding the right to access and use such limited supply of water. Both groundwater and surface water in areas important to APS’ generating plants have been the subject of inquiries, claims and legal proceedings. In addition, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS’ inability to access sufficient supplies of water could have a material adverse impact on our business and results of operations.
The ownership and operation of power generation and transmission facilities on Indian lands could result in uncertainty related to continued easements and rights-of-way, which could have a significant impact on our business.
Certain APS power plants, including Four Corners, and portions of the transmission lines that carry power from these plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. APS is currently unable to predict the outcome of discussions with the appropriate Indian tribes with respect to future renewal of these easements and rights-of-way.
There are inherent risks in the ownership and operation of nuclear facilities, such as environmental, health, fuel supply, spent fuel disposal, regulatory and financial risks and the risk of terrorist attack.
APS has an ownership interest in and operates, on behalf of a group of owners, Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to obtain adequate supplies of nuclear fuel; the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; and unscheduled outages due to equipment and other problems. APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage. In addition, APS may be required under federal law to pay up to $103 million (but not more than $15 million per year) of liabilities arising out of a nuclear incident occurring not only at Palo Verde, but at any other nuclear power plant in the United States. Although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. In December 2008, APS applied for renewed operating licenses for all three Palo Verde units for 20 years beyond the expirations of the current licenses. APS does not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.
APS’ operations include managing market risks related to commodity prices. APS is exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas and coal to the extent that unhedged positions exist. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions 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 commodity. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time and financial losses that negatively impact our results of operations.
Congress is considering legislation to impose restrictions on the use of over-the-counter derivatives, including energy derivatives, which could subject APS to governmental regulation relating to these hedging transactions. If such legislation becomes law, APS could potentially face higher costs to hedge its risks, fewer potential counterparties still active in the newly-regulated marketplace and increased liquidity requirements.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, which could result in a material adverse impact on our earnings for a given period.
Changes in technology may adversely affect APS’ business.
Research and development activities are ongoing to improve alternative technologies to produce power, including fuel cells, micro turbines, clean coal and coal gasification, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these, or other technologies could reduce the cost of power production, making APS’ generating facilities less competitive. In addition, advances in technology could reduce the demand for power supply, which could adversely affect APS’ business.
APS is pursuing and implementing advanced technologies, including smart grid transmission and distribution systems and advanced meters for use in customers’ homes and businesses. Many of the products and processes resulting from these and other alternative technologies have not yet been widely used or tested, and their use on large-scale systems is not as advanced and established as APS’ existing technologies and equipment. Uncertainties and unknowns related to these and other advancements in technology and equipment could adversely affect APS’ business if national standards develop that do not embrace the current technologies or if the technologies and equipment fail to perform as expected.
FINANCIAL RISKS
Financial market disruptions may increase our financing costs or limit our access to the credit markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:
•
continuation of the current economic downturn;
•
terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies;
•
mergers among financial institutions and the overall health of the banking industry; or
•
the overall health of the utility industry.
In addition, the credit commitments of our lenders under our bank facilities may not be satisfied for a variety of reasons, including unexpected periods of financial distress affecting our lenders, which could materially adversely affect the adequacy of our liquidity sources.
Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:
•
increasing the cost of future debt financing;
•
reducing our credit ratings;
•
increasing our vulnerability to adverse economic and industry conditions; and
•
requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes.
A reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.
Our current ratings are set forth in “Pinnacle West Consolidated - Liquidity and Capital Resources - Credit Ratings” in Item 7. We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade or withdrawal could adversely affect the market price of Pinnacle West’s and APS’ securities, limit our access to capital and increase our borrowing costs, which would diminish our financial results. We would be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade would also require us to provide substantial additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could completely eliminate any possible future access to the commercial paper market. We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.
Market performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase our related obligations, resulting in significant additional funding that could negatively impact our business.
Disruptions in the capital markets may adversely affect the values of fixed income and equity investments held in our employee benefit plan trusts and nuclear decommissioning trusts. We have significant obligations in these areas and hold substantial assets in these trusts. A decline in the market value of these trusts may increase our funding requirements. Additionally, the pension plan and other postretirement benefit liabilities are impacted by the discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates impact the discount rate, and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. A significant portion of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices. Our inability to fully recover these costs in a timely manner or any increased funding obligations could negatively impact our financial condition, results of operations or cash flows.
We may be required to adopt International Financial Reporting Standards (“IFRS”). The ultimate adoption of such standards could negatively impact our business, financial condition or results of operations.
IFRS is a comprehensive series of accounting standards published by the International Accounting Standards Board that is being considered by the SEC to replace accounting principles generally accepted in the United States of America (“GAAP”) for use in preparation of financial statements. If the SEC requires mandatory adoption of IFRS, we may lose our ability to use regulatory accounting treatment, and would follow IFRS rather than GAAP for the preparation of our financial statements beginning in 2014. The implementation and adoption of these new standards and the inability to use regulatory accounting could negatively impact our business, financial condition or results of operations.
Our cash flow largely depends on the performance of our subsidiaries.
We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.
The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. An ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. The common equity ratio, as defined in the ACC order, is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt.
Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.
Because we are structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their assets and cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.
The market price of our common stock may be volatile.
The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:
•
variations in our quarterly operating results;
•
operating results that vary from the expectations of management, securities analysts and investors;
•
changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;
•
developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries;
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announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
•
announcements by third parties of significant claims or proceedings against us;
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favorable or adverse regulatory or legislative developments;
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our dividend policy;
•
future sales by the Company of equity or equity-linked securities; and
•
general domestic and international economic conditions.
In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.
Certain provisions of our articles of incorporation and bylaws and of Arizona law make it difficult for shareholders to change the composition of our board and may discourage takeover attempts.
These provisions, which could preclude our shareholders from receiving a change of control premium, include the following:
•
restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who owns 10% or more of our outstanding voting power or any of our affiliates or associates) or any affiliate or associate of an interested shareholder, unless specific conditions are met;
•
anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;
•
the ability of the Board of Directors to increase the size of the Board and fill vacancies on the Board, whether resulting from such increase, or from death, resignation, disqualification or otherwise; and
•
the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval.
While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of our shareholders might believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors.
SunCor’s business and financial results would be adversely affected if it is unable to extend, modify or renew its credit facilities or repay its debt through sales of its remaining assets.
At December 31, 2009, SunCor had borrowings of approximately $57 million under its principal loan facility (the "Secured Revolver"). The Secured Revolver matured on January 30, 2010 and SunCor and the agent bank for the Secured Revolver are discussing an extension of the maturity date to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the Secured Revolver, at December 31, 2009, SunCor had approximately $43 million of outstanding debt under other credit facilities ($9 million of which has matured since December 31, 2009 and remains outstanding).
If SunCor is unable to obtain an extension or renewal of the Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor's business and financial position and impair its ongoing viability.
SunCor intends to apply the proceeds of its planned asset sales to the repayment of its outstanding debt. If it is unable to locate suitable buyers and close certain asset sales or obtain sufficient proceeds from these sales to maintain or pay off its existing debt, it may be unable to satisfy obligations under its credit facilities, resulting in the immediate repayment obligations described above.
SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt. SunCor's ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.
The Company has not guaranteed any SunCor indebtedness. As a result, we do not believe that SunCor's inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West's cash flows or liquidity. Any resulting SunCor losses would be reflected in Pinnacle West's consolidated financial statements. If SunCor were required to seek protection under federal bankruptcy laws, Pinnacle West could be exposed to the uncertainties and complexities inherent for parent companies in such proceedings.
During 2008 and 2009 the real estate market weakened significantly resulting in lower land and home sales and depressed real estate prices. As a result, in 2008 and 2009 SunCor recognized certain impairment charges. SunCor may be required to record additional impairments.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2009 fiscal year and that remain unresolved.
ITEM 2. PROPERTIES
Generation Facilities
APS’ portfolio of owned and leased generating facilities is provided in the table below:
(a)
100% unless otherwise noted.
(b)
See “Business of Arizona Public Service Company - Generation - Nuclear” in Item 1 for details regarding leased interests in Palo Verde. The other owners are Salt River Project (17.5%), Southern California Edison (15.8%), El Paso Electric (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.9%), and Los Angeles Department of Water & Power (5.7%).
(c)
The other owners are Salt River Project (10%), Public Service Company of New Mexico (13%), Southern California Edison (48%), Tucson Electric Power Company (1%) and El Paso Electric (1%).
(d)
The other owners are Salt River Project (21.7%), Nevada Power Company (11.3%), the United States Government (24.3%), Tucson Electric Power Company (7.5%) and Los Angeles Department of Water & Power (21.2%).
See “Business of Arizona Public Service Company - Environmental Matters” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ generating facilities.
See “Business of Arizona Public Service Company” in Item 1 for a map detailing the location of APS’ major power plants and principal transmission lines.
Transmission and Distribution Facilities
Current Facilities. APS’ transmission facilities consist of approximately 5,946 pole miles of overhead lines and approximately 49 miles of underground lines, 5,723 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 11,362 miles of overhead lines and approximately 17,308 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2009:
Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’ 2010 plan, APS projects it will invest approximately $520 million in new transmission over the next ten years, which includes 270 miles of new lines. This investment will increase the import capability into metropolitan Phoenix by approximately 26% and will increase the import capability into the Yuma area by approximately 38%. One significant project presently under construction is the Morgan - Pinnacle Peak project, which consists of 26 miles of 500kV and 230kV lines. APS completed two major substation projects in 2009. The Dugas substation (500/69kV) will provide system voltage support and capacity for the Verde Valley area and the Sugarloaf substation (500/69kV) will provide system voltage support and capacity for the Show Low and Snowflake areas, and will also support renewable energy development in that area.
APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities. Two such projects, which are included in APS’ 2010 transmission plan, are the Delany to Palo Verde line and the North Gila to Palo Verde line, both of which are intended to support the transmission of renewable energy to Phoenix and California.
Plant and Transmission Line Leases and Easements on Indian Lands
The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under easements from the federal government. The easement and lease for the Navajo Plant expire in 2019 and the easement and lease for Four Corners expire in 2016. Each of the leases contains an option to extend for an additional 25-year period from the end of the existing lease term, for a rental amount tied to the original rent payment adjusted based on an index. The easements do not contain an express renewal option and it is unclear what conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal of the Navajo Plant and Four Corners leases and easements is uncertain. The coal contracted for use in these plants is also located on Indian reservations.
Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the future and renewal action by the applicable tribe will be required at that time. The majority of our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and Navajo Plant leases provide Navajo Nation consent to certain of the rights-of-way for transmission lines related to those plants at a specified rental rate for the original term of the rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to the leases provides a formula for calculating payments for certain new and renewal rights-of-way. However, some of our rights-of-way are not covered by the leases, or are granted by other Indian tribes. In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way or that are typical for similar permits across non-Indian lands; however, we are unaware of the underlying agreements and/or specific circumstances surrounding these renewals. The ultimate cost of renewal of the rights-of-way for our transmission lines is uncertain. We are monitoring these rights-of-way and easement issues and have initiated discussions with the Navajo Nation regarding them. We are currently unable to predict the outcome of this matter.
Real Estate Segment Properties
See “Business of Other Subsidiaries - SunCor ” in Item 1 for information regarding SunCor’s remaining properties. Substantially all of SunCor’s debt is collateralized by interests in its real property.
ITEM 3. LEGAL PROCEEDINGS
See “Business of Arizona Public Service Company - Environmental Matters” in Item 1 with regard to pending or threatened litigation and other disputes.
See Note 3 for the resolution of APS’ general retail rate case and other matters before the ACC.
See Note 11 with regard to a lawsuit brought by APS on behalf of itself and the other Palo Verde owners against the DOE, for information relating to the FERC proceedings on California and Pacific Northwest energy market issues and for information regarding the bankruptcy proceeding involving the landlord for our corporate headquarters building.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
EXECUTIVE OFFICERS OF PINNACLE WEST
Pinnacle West’s executive officers are elected no less often than annually and may be removed by the Board of Directors at any time. The executive officers, their ages at February 19, 2010, current positions and principal occupations for the past five years are as follows:
PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange. At the close of business on February 15, 2010, Pinnacle West’s common stock was held of record by approximately 28,216 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE STOCK SYMBOL: PNW
APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’ common stock.
The chart below sets forth the dividends paid on APS’ common stock for each of the four quarters for 2009 and 2008.
Common Stock Dividends
(Dollars in Thousands)
The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. As of December 31, 2009, APS did not have any outstanding preferred stock.
Issuer Purchases of Equity Securities
The following table contains information about our purchases of our common stock during the fourth quarter of 2009.
(1)
Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.
ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION - CONSOLIDATED
(a)
Includes a $157 million after tax real estate impairment charge in 2009 (see Note 23). Also includes regulatory disallowance of $8 million after tax in 2007 and $84 million after tax in 2005.
(b)
Amounts primarily related to SunCor’s real estate impairment charges (see Note 23), Silverhawk Power Station (“Silverhawk”) and APSES discontinued operations (see Note 22).
SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 of this report. For information on the broad factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most 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 substantially all of our revenues and earnings, and is expected to continue to do so.
Areas of Business Focus
Operational Performance and Reliability.
Nuclear. Palo Verde experienced strong performance during 2009, with its three units achieving a combined year-end capacity factor of 89%. With a focus on safely and efficiently generating electricity for the long-term, APS applied for twenty-year renewals of its operating licenses for each of the three Palo Verde units, and is making preparations to secure necessary resources to operate the plant during this extended period of time. Palo Verde’s 2009 accomplishments also included the installation of a new reactor vessel head, upgraded equipment and processes designed to substantially reduce the time required to defuel and refuel the reactor during refueling outages, and the successful implementation of a comprehensive improvement plan, which allowed Palo Verde Unit 3 to exit the NRC’s enhanced inspection regime (“Column 4”) earlier than anticipated, in March of 2009.
Coal and Related Environmental Matters. APS’ coal plants, Four Corners and Cholla, achieved net capacity factors of 88% and 77%, respectively, in 2009. APS is focused on developing legislation and increased regulation concerning greenhouse gas emissions, and the potential impacts on our coal fleet. Recent concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants. APS is closely monitoring our long range capital management plans, understanding that the resulting legislation and regulation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to fund any such equipment upgrades. See “Business of Arizona Public Service Company - Environmental Matters - Climate Change” in Item 1 and climate change-related risks described in Item 1A for additional climate change developments and risks facing APS.
Transmission and Delivery. In the area of transmission and delivery to its customers, APS also ranked favorably during 2009, with top quartile performance for average customer outage time. During 2009, APS undertook several significant transmission projects, including the Morgan to Pinnacle Peak transmission line scheduled for completion at the end of 2010, and the completion of two switchyards, one of which will support capacity for renewable energy projects. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. APS is also working to establish and expand smart grid technology throughout its service territory designed to provide a variety of benefits both to APS and its customers. This technology should allow customers to better monitor their energy use and needs, minimize system outage durations and the number of customers that experience outages, and facilitate cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.
Renewable Energy. APS is committed to increasing the amount of energy produced by renewable energy resources, which was a significant focus in APS’ recent rate case settlement described below. APS and the other parties to the rate case worked with the ACC Commissioners to address a wide range of customer needs and to secure a clean, sustainable energy future for Arizona. The ACC adopted a renewable energy standard several years ago, recognizing the importance of renewable energy to our state. In the rate case settlement agreement, APS agreed to exceed these standards, committing that 10% of APS’ resources will come from renewable energy by the year 2015. A variety of other provisions in the settlement agreement reinforce APS’ dedication to renewable energy through initiatives to build a photovoltaic solar plant, install solar rooftop panels on schools and seek an Arizona wind generation project.
During 2009, APS filed its annual RES implementation plan that included a request for ACC approval of the “AZ Sun Program.” As proposed in its plan, APS would invest an estimated $500 million to develop at least 100 MW of photovoltaic solar plants. It currently anticipates that this solar capacity would be placed into service in the 2011 to 2014 timeframe. The ultimate timing depends on the outcome of current and future procurement processes. See Note 3 for additional details regarding this program, including the estimated timing of the ACC’s determination on the matter and the related cost recovery. APS also issued two requests for proposal (“RFP”) for renewable resources in early 2010. These RFP’s are part of the process for procuring the additional renewable resources required under the rate case settlement. The first RFP is for utility-scale solar photovoltaic projects between 15 and 50 MW. Assuming ACC approval of the AZ Sun Program as proposed, this RFP will serve as the first procurement step for implementing that program. The second RFP is for wind projects between 15 and 100 MW to be located within Arizona.
Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the end of 2009, the ACC approved a settlement agreement entered into by APS and twenty-one of the twenty-three other parties to APS’ general retail rate case, with modifications that did not materially affect the overall economic terms of the agreement. The rate case settlement should strengthen APS’ financial condition by allowing for rate stability and a greater level of cost recovery and return on investment. It also authorizes and requires equity infusions into APS of at least $700 million prior to the end of 2014. The settlement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office (RUCO) and other intervenors to the rate case, and establishes a future rate case filing plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual rate cases. See Note 3 for a detailed discussion of the settlement agreement terms and information on APS’ FERC rates.
APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its energy efficiency, demand-side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.
Financial Strength and Flexibility. Despite the volatility and disruption of the credit markets, Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities, ensuring adequate liquidity for each company. In early February 2010, APS entered into a $500 million revolving credit facility, replacing its $377 million revolving credit facility that would have otherwise terminated in December 2010. At that same time, Pinnacle West entered into a $200 million revolving credit facility that replaces its $283 million facility that also would have otherwise terminated in December 2010.
SunCor Real Estate Operations. As a result of the continuing distressed conditions in the real estate markets, during 2009 SunCor undertook a program to dispose of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. This resulted in impairment charges of approximately $266 million, or $161 million after income taxes, for 2009. See “Pinnacle West Consolidated - Liquidity and Capital Resources - Other Subsidiaries - SunCor” below for a discussion of SunCor’s outstanding debt and related matters, Note 23 for a further discussion of impairment charges and the SunCor-related risk factor in Item 1A.
Subsidiaries. Our other first tier subsidiaries, El Dorado and APSES, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2007 through 2009, retail electric revenues comprised approximately 94% of our total electric operating revenues. Our electric operating revenues are affected by customer growth, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including competition, demand and prices.
Customer and Sales Growth. Customer growth in APS’ service territory for the year ended December 31, 2009 was 0.6% compared with the prior year. For the three years 2007 through 2009, APS’ customer growth averaged 1.8% per year. We currently expect customer growth to average about 1% per year for 2010 through 2012 due to economic conditions both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for 2009 declined 2.4% compared to the prior year, reflecting the poor economic conditions in 2009 and the effects of our energy efficiency programs. For the three years 2007 through 2009, APS’ actual retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, grew at an average annual rate of 0.3%. We currently estimate that total retail electricity sales in kilowatt-hours will remain flat on average per year during 2010 through 2012, including the effects of APS’ energy efficiency programs, but excluding the effects of weather variations. A continuation of the economic downturn, or the failure of the Arizona economy to rebound in the near future, could further impact these estimates. The customer and sales growth referred to in this paragraph apply to Native Load customers.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns, impacts of energy efficiency programs and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.
Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and PSA deferrals and the amortization thereof.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of regulated electricity segment operating revenues) and other factors. In its recent retail rate case settlement, APS committed to operational expense reductions from 2010 through 2014 and received approval to defer certain pension and other postretirement benefit cost increases to be incurred in 2011 and 2012.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. The “Capital Expenditures” section below provides information regarding the planned additions to our facilities. We have also applied to the NRC for renewed operating licenses for each of the Palo Verde units. If the NRC grants the extension, we estimate that our annual pretax depreciation expense will decrease by approximately $34 million at the later of the license extension date or January 1, 2012.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 7.5% of the assessed value for 2009, 7.8% of the assessed value for 2008 and 8.3% of the assessed value for 2007. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities described below under “Capital Additions”) and as we improve our existing facilities.
Income Taxes. Income taxes are affected by the amount of pre-tax book income, income tax rates, and certain non-taxable items, such as the allowance for equity funds used during construction. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6.) The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.
PINNACLE WEST CONSOLIDATED - RESULTS OF OPERATIONS
Our results of operations, provided below, are based upon our two reportable business segments:
•
our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and investment activities.
Operating Results - 2009 Compared with 2008
Our consolidated net income attributable to common shareholders for 2009 was $68 million, compared with net income of $242 million for the prior year. The decrease in net income was primarily due to 2009 real estate impairment charges recorded by SunCor, the Company’s real estate subsidiary.
In addition, regulated electricity segment net income decreased approximately $13 million from the prior year primarily due to lower retail sales resulting from lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to the interim rate increase effective January 1, 2009 and transmission rate increases.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
(a)
See Note 23 for additional information on real estate impairment charges.
(b)
Includes activities related to marketing and trading, APSES and El Dorado. Income for 2008 includes income from discontinued operations of $8 million related to the resolution of certain tax issues associated with the sale of Silverhawk in 2005. None of these segments is a reportable segment.
Regulated electricity segment
This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.
Operating revenues less fuel and purchased power expenses
Regulated electricity segment operating revenues less fuel and purchased power expenses were $127 million higher for the year ended 2009 compared with the prior year. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $66 million for the year ended 2009 compared with the prior year primarily because of:
•
An increase of $62 million related to renewable energy and demand-side management programs, which are offset in operating revenues;
•
An increase of $29 million in generation costs, including more planned maintenance, partially offset by lower costs at Palo Verde due to cost efficiency measures; and
•
A decrease of $25 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.
Depreciation and amortization Depreciation and amortization expenses increased $17 million for the year ended 2009 compared with the prior year primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.
Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $28 million for the year ended 2009 compared with the prior year primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated - Liquidity and Capital Resources” below). Interest charges, net of capitalized financing costs are comprised of the regulated electricity segment portions of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Consolidated Statements of Income.
Other income (expenses), net Other income (expenses), net improved $19 million for the year ended 2009 compared with the prior year primarily because of improved investment gains. Other income (expenses), net is comprised of the regulated electricity segment portions of the line items other income and other expense from the Consolidated Statements of Income.
Income taxes Income taxes were $50 million higher for the year ended 2009 compared with the prior year primarily because of $30 million of income tax benefits related to prior years recorded in 2008 and higher pretax income. See Note 4.
Real estate segment
During the first quarter of 2009, we decided to restructure SunCor through the sale of substantially all of its assets. The real estate segment net loss attributable to common shareholders was $141 million higher for the year ended 2009 compared with the prior year primarily because of:
•
An increase in real estate impairment charges of $213 million (see Note 23 for details of the impairment charges);
•
A decrease of $20 million in income from other real estate operations primarily due to 2008 income from a commercial property sale; and
•
An increase in income tax benefits of $92 million primarily because of a higher net loss.
All Other
All other earnings were $20 million lower for the year ended 2009 compared with the prior year primarily because of planned reductions of marketing and trading activities and the absence of the 2008 resolution of certain tax issues associated with the sale of Silverhawk in 2005.
Operating Results - 2008 Compared with 2007
Our consolidated net income attributable to common shareholders for 2008 was $242 million, compared with net income of $307 million for the prior year. The decrease in net income was primarily due to lower results recorded by SunCor, the Company’s real estate subsidiary.
In addition, regulated electricity segment net income decreased approximately $18 million from the prior year primarily due to higher operations and maintenance expenses; lower retail sales due to the effects of weather; higher depreciation and amortization expenses; and higher interest charges, net of capitalized financing costs. These negative factors were partially offset by increased revenues due to the rate increase effective July 1, 2007; transmission rate increases; and income tax benefits related to prior years recorded in 2008.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
(a)
See Note 23 for additional information on real estate impairment charges.
(b)
Includes activities related to marketing and trading, APSES and El Dorado. Income for 2008 includes income from discontinued operations of $8 million related to the resolution of certain tax issues associated with the sale of Silverhawk in 2005. None of these segments is a reportable segment.
Regulated electricity segment
This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.
Operating revenues less fuel and purchased power expenses
Regulated electricity segment operating revenues less fuel and purchased power expenses were $66 million higher for the year ended 2008 compared with the prior year. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $87 million for the year ended 2008 compared with the prior year primarily because of:
•
An increase of $30 million related to customer service and other costs including distribution system reliability;
•
An increase of $18 million in generation costs, including more planned maintenance;
•
An increase of $14 million related to renewable energy programs, which are offset in operating revenues;
•
An increase of $9 million associated with employee severance costs in 2008; and
•
An increase of $16 million due to other miscellaneous factors.
Depreciation and amortization Depreciation and amortization expenses increased $18 million for the year ended 2008 compared with the prior year primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.
Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $15 million for the year ended 2008 compared with the prior year primarily because of higher rates on certain APS pollution control bonds and higher short-term debt balances. Interest charges, net of capitalized financing costs, are comprised of the regulated electricity segment portions of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the Consolidated Statements of Income.
Other income (expenses), net Other income (expenses), net reduced earnings by an additional $14 million for the year ended 2008 compared with the prior year primarily because of losses on investments and lower interest income. Other income (expenses), net is comprised of the regulated electricity segment portions of the line items other income and other expense from the Consolidated Statements of Income.
Income taxes Income taxes were $47 million lower for the year ended 2008 compared with the prior year primarily because of $17 million of increased income tax benefits related to prior years resolved in 2008 and 2007 and lower pre-tax income. See Note 4.
Real estate segment
The real estate segment net income attributable to common shareholders was $49 million lower for the year ended 2008 compared with the prior year primarily because of:
•
Real estate impairment charges of $53 million (see Note 23) without comparable charges in the prior year;
•
A decrease of $27 million from other real estate operations primarily due to decreased land parcel sales in the 2008 period as a result of the weak real estate market; and
•
An increase in income tax benefits of $31 million primarily because of the net loss recorded in 2008.
PINNACLE WEST CONSOLIDATED -
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table presents net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2009, 2008 and 2007 (dollars in millions):
2009 Compared with 2008
The increase of approximately $217 million in net cash provided by operating activities is primarily due to a reduction of collateral and margin cash required as a result of changes in commodity prices and a 2009 income tax refund (see Note 4).
The decrease of approximately $110 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions (see table and discussion below), partially offset by lower real estate sales primarily due to a commercial property sale in 2008.
The increase of approximately $337 million in net cash used for financing activities is primarily due to repayments of short-term borrowings, partially offset by APS’ issuance of $500 million of unsecured senior notes (see Note 6).
2008 Compared with 2007
The increase of approximately $156 million in net cash provided by operating activities is primarily due to lower current income taxes; lower real estate investments resulting from the weak real estate market; and increased retail revenue related to higher Base Fuel Rates, partially offset by increased collateral and margin cash provided as a result of changes in commodity prices.
The decrease of approximately $58 million in net cash used for investing activities is primarily due to a real estate commercial property sale in 2008; lower levels of capital expenditures (see table and discussion below); and increased contributions in aid of construction related to changes in 2008 in APS’ line extension policy (see Note 3), partially offset by lower cash proceeds from the net sales and purchases of investment securities.
The decrease of approximately $134 million in net cash provided by financing activities is primarily due to the use of the proceeds from the sale of a real estate commercial property to pay down long-term debt in 2008, partially offset by higher levels of short-term debt borrowings.
Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for 2007, 2008 and 2009 and estimated capital expenditures for the next three years:
CAPITAL EXPENDITURES
(dollars in millions)
(a)
Generation includes nuclear fuel expenditures of approximately $60 million to $80 million per year for 2010, 2011 and 2012.
(b)
Primarily information systems and facilities projects.
(c)
Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Environmental expenditures for the years 2010, 2011 and 2012 are approximately $20 million, $80 million and $220 million, respectively. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures. (See “Business of Arizona Public Service Company - Environmental Matters - EPA Environmental Regulation - Regional Haze Rules and Mercury and other Hazardous Air Pollutants” in Item 1.)
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems.
Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
On January 20, 2010, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 1, 2010, to shareholders of record on February 1, 2010.
Our primary sources of cash are dividends from APS, external debt and equity financings. For the years 2007 through 2009, total distributions from APS were $510 million and total distributions received from SunCor were $5 million. For 2009, cash distributions from APS were $170 million and there were no distributions from SunCor.
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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2009, APS’ common equity ratio, as defined, was 50%. Its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.8 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same.
The credit and liquidity markets experienced significant stress beginning the third quarter of 2008. Since the fourth quarter of 2008, Pinnacle West and APS have not accessed the commercial paper market due to negative market conditions. They have both been able to access existing credit facilities, ensuring adequate liquidity.
At December 31, 2009, Pinnacle West had a $283 million revolving credit facility that was scheduled to terminate in December 2010. The revolver was available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. The parent company had $149 million of borrowings outstanding under its revolving credit facility and no letters of credit at December 31, 2009.
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. The new revolving credit facility terminates in February 2013. Pinnacle West may 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. Pinnacle West will use the facility for general corporate purposes, repayment of long-term debt, and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. In addition, because of the downsized revolving credit facility, the Company is in the process of reducing the size of its commercial paper program to $200 million from $250 million.
Pinnacle West expects to recognize approximately $125 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 23), which will not be realized until the asset sale transactions are completed. Approximately $105 million of these benefits were recorded in 2009 as reductions to income tax expense related to the current impairment charges. The additional $20 million of tax benefits were recorded as reductions to income tax expense related to the SunCor impairment charge recorded in the fourth quarter of 2008.
The $91 million income tax receivable (current and long-term) on the Consolidated Balance Sheets represents the anticipated cash refunds related to an APS tax accounting method change approved by the United States Internal Revenue Service (“IRS”) in the third quarter of 2009 and the expected tax benefits related to the SunCor strategic asset sales that closed in 2009.
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made no contribution to our pension plan in 2009. We currently estimate that our pension contributions could average around $100 million for several years, assuming the discount rate remains at approximately current levels. In January 2010, we made a voluntary contribution of approximately $50 million to our pension plan and we expect to make an additional voluntary contribution of $50 million later in 2010. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.
See Note 3 for information regarding the recent retail rate case settlement, which includes ACC authorization and requires equity infusions into APS of at least $700 million by December 31, 2014. Pinnacle West intends to issue equity to provide most of the funds for the equity infusions into APS. Such equity issuances may occur at any time in the period through 2014, in Pinnacle West’s discretion.
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
APS
APS’ capital requirements consist primarily of capital expenditures and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, equity infusions from Pinnacle West and external financings. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
On February 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019. Net proceeds from the sale of the notes were used to repay short-term borrowings under two committed revolving lines of credit incurred to fund capital expenditures and for general corporate purposes.
During 2009, APS refinanced approximately $343 million of its $656 million pollution control bonds. As a result of these refinancings, the terms of which are described in detail in Note 6, APS no longer has any outstanding debt securities in auction rate mode.
On September 11, 2008, APS purchased all of the approximately $27 million of the Coconino Pollution Control Revenue Bonds, Series 1996A and Series 1999 due December 2031 and April 2034 and held them as treasury bonds. On September 22, 2009, Coconino issued approximately $27 million of Coconino Pollution Control Revenue Refunding Bonds, 2009 Series B due April 2038 to redeem the existing bonds. APS used the funds received from the issuance to repay certain existing indebtedness under a revolving line of credit drawn upon by APS to fund its purchase of the 1996A and 1999 Series Bonds in 2008. The 2009 Series B Bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino. According to the indenture of the bonds, the interest rate of the 2009 Series B Bonds could be reset daily, weekly, monthly, or at other time intervals. The initial rate period selected for the 2009 Series B Bonds is a daily rate period. At December 31, 2009, the daily interest rate was 0.26%. The daily rates are variable rates set by a remarketing agent. Concurrently with the issuance of the 2009 Series B Bonds, the Company entered into a two year letter of credit and reimbursement agreement to provide credit support for the 2009 Series B Bonds.
At December 31, 2009, APS had two committed revolving credit facilities totaling $866 million, of which $377 million was scheduled to terminate in December 2010 and $489 million terminates in September 2011. The revolvers were available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At December 31, 2009, APS had no borrowings and no letters of credit under its revolving lines of credit.
On February 12, 2010, APS refinanced its $377 million revolving credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2013. 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 for general corporate purposes and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.
Other Financing Matters - See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
See Note 3 for information regarding the recent retail rate case settlement, which includes ACC authorization and requires equity infusions into APS of at least $700 million by December 31, 2014.
See Note 18 for information related to the change in our margin accounts.
Other Subsidiaries
SunCor - SunCor's principal loan facility, the SunCor Secured Revolver, is secured primarily by an interest in land, commercial properties, land contracts and homes under construction. At December 31, 2009, SunCor had borrowings of approximately $57 million under the Secured Revolver (see Note 6). The revolver matured on January 30, 2010. SunCor and the agent bank for the Secured Revolver are discussing an extension of the maturity date to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the Secured Revolver, at December 31, 2009, SunCor had approximately $43 million of outstanding debt under other credit facilities ($9 million of which has matured since December 31, 2009 and remains outstanding) (see Notes 5 and 6). SunCor intends to apply the proceeds of planned asset sales (see Note 23) to the repayment of its outstanding debt.
Real estate impairment charges recorded throughout 2009 (see Note 23) resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor's other credit facilities. The lenders have taken no enforcement action related to the covenant defaults.
If SunCor is unable to obtain an extension or renewal of the Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor's business and financial position and impair its ongoing viability.
SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt. SunCor's ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.
Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor's inability to obtain waivers or similar relief from SunCor's lenders would have a material adverse impact on Pinnacle West's cash flows or liquidity.
As of December 31, 2009, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not materially affect Pinnacle West's ability to meet its ongoing capital requirements.
El Dorado - El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
APSES - APSES expects minimal capital expenditures over the next three years.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2009, the ratio was approximately 52% for Pinnacle West and 48% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.6 times under APS’ bank financing agreements as of December 31, 2009. 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’ 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 financial agreements contain a pricing grid in which the interest costs we pay 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’ 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 revolver borrowings.
See Notes 5 and 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 17, 2010 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and limit access to capital. It may also require substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient liquidity to cover a downward revision to our credit ratings.
(a)
Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements 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 assume the debt associated with the transactions, make specified payments to the equity participants, 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, 2009, APS would have been required to assume approximately $152 million of debt and pay the equity participants approximately $153 million.
SunCor is the primary beneficiary of certain land development arrangements and, accordingly, consolidates the variable interest entities. The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $29 million at December 31, 2009 and at December 31, 2008.
See Note 2 for a discussion of amended accounting guidance relating to VIEs adopted on January 1, 2010.
Guarantees and Letters of Credit
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries.
Our parental guarantees for APS relate to commodity energy products. In addition, Pinnacle West has obtained approximately $8 million of surety bonds related to APS’ operations, which primarily relate to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At December 31, 2009, we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2009 (dollars in millions):
(a)
The long-term debt matures at various dates through 2038 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2009 (see Note 6).
(b)
The short-term debt is primarily related to bank borrowings at Pinnacle West under its revolving line of credit (see Note 5).
(c)
Our purchased power and fuel commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Notes 3 and 11).
(d)
Relates to the Palo Verde sale leaseback and other items (see Note 9).
(e)
Contracts to purchase renewable energy credits in compliance with the Renewable Energy Standard.
(f)
These contractual obligations include commitments for capital expenditures and other obligations.
This table excludes $209 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an 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 applicable regulatory environment changes and recent rate orders 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 had $782 million of regulatory assets and $766 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2009.
Included in the balance of regulatory assets at December 31, 2009 is a regulatory asset of $532 million for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2009 reported pension liability on the Consolidated Balance Sheets and our 2009 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2009 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2009 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)
This assumes a 1% change in the initial and ultimate health care cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)) and the ineffective portion is recognized in current earnings.
See “Market Risks - Commodity Price Risk” below for quantitative analysis. See “Fair Value Measurements” below for additional information on valuation. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.
Fair Value Measurements
We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value, and the significance of a particular input determines how the instrument is classified in the fair value hierarchy. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within the fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 14 for further fair value measurement discussion, Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.
Our nuclear decommissioning trusts invest in fixed income securities and equity securities. The fair values of these securities are based on observable inputs for identical or similar assets. See Note 12 for further discussion of our nuclear decommissioning trusts.
Real Estate Investment Impairments
We had real estate investments of $120 million and $3 million of home inventory on our Consolidated Balance Sheets at December 31, 2009. For purposes of evaluating impairment, in accordance with guidance on the impairment and disposal of long-lived assets, we classify our real estate assets, such as land under development, land held for future development, and commercial property, as “held and used.” When events or changes in circumstances indicate that the carrying value of real estate assets considered held and used may not be recoverable, we compare the undiscounted cash flows that we estimate will be generated by each asset to its carrying amount. If the carrying amount exceeds the undiscounted cash flows, we adjust the asset to fair value and recognize an impairment charge. The adjusted value becomes the new book value (carrying amount) for held and used assets. We may have real estate assets classified as held and used with fair values that are lower than their carrying amounts, but are not deemed to be impaired because the undiscounted cash flows exceed the carrying amounts.
Real estate home inventory is considered to be held for sale for the purposes of evaluating impairment. Home inventories are reported at the lower of carrying amount or fair value less cost to sell. Fair value less cost to sell is evaluated each period to determine if it has changed. Losses (and gains not to exceed any cumulative loss previously recognized) are reported as adjustments to the carrying amount.
We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific to each project and may vary among projects. The discount rates we used to determine fair values at December 31, 2009 ranged from 11% to 29%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could differ from those estimates. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairments.
OTHER ACCOUNTING MATTERS
See Note 2 for a discussion of recently adopted accounting standards and new standards to be adopted in the future.
In June 2009, the FASB issued amended guidance on the consolidation of variable interest entities. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling financial interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. The new guidance requires an enterprise with a variable interest in a VIE to perform a qualitative assessment in determining whether it has a controlling financial interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, the amended guidance requires companies to continually evaluate VIEs for consolidation. This guidance was effective for us on January 1, 2010. We are continuing to evaluate the impact this new guidance may have on our financial statements.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 12). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2009 and 2008. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2009 and 2008 (dollars in thousands):
Pinnacle West - Consolidated
The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2009 and 2008. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2009 and 2008 (dollars in thousands):
APS
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our 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 commodities.
The following table shows the net pretax changes in mark-to-market of our derivative positions in 2009 and 2008 (dollars in millions):
(a)
The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2009 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2009 and 2008 (dollars in millions):
(a)
These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 18 for a discussion of our credit valuation adjustment policy.
ARIZONA PUBLIC SERVICE COMPANY - RESULTS OF OPERATIONS
Regulatory Matters
See Note 3 for information about rate matters affecting APS.
Operating Results - 2009 Compared with 2008
APS’ net income for 2009 was $251 million, compared with net income of $262 million for the comparable prior-year period.
APS’ net income decreased approximately $11 million from the prior-year period primarily due to lower retail sales resulting from lower usage per customer; higher interest charges, net of capitalized financing costs; higher depreciation and amortization expenses; and the absence of income tax benefits related to prior years recorded in 2008. These negative factors were partially offset by increased revenues due to the interim rate increase effective January 1, 2009 and transmission rate increases.
The following table presents net income compared with the prior-year period:
Operating revenues less fuel and purchased power expenses
Electric operating revenues less fuel and purchased power expenses were $127 million higher for 2009 compared with the prior-year period. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $66 million for 2009 compared with the prior-year period primarily because of:
•
An increase of $62 million related to renewable energy and demand-side management programs, which are offset in operating revenues;
•
An increase of $29 million in generation costs, including more planned maintenance, partially offset by lower costs at Palo Verde due to cost efficiency measures; and
•
A decrease of $25 million associated with cost saving measures and other factors, including the absence of employee severance costs in 2009.
Depreciation and amortization Depreciation and amortization expenses increased $16 million for 2009 compared with the prior-year period primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.
Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $30 million for 2009 compared with the prior-year period primarily because of higher debt balances, partially offset by the effects of lower interest rates (see discussion related to APS’ debt issuances in “Pinnacle West Consolidated - Liquidity and Capital Resources” above). Interest charges, net of capitalized financing costs are comprised of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the APS’ Statements of Income.
Other income (expenses), net Other income (expenses), net improved $17 million for 2009 compared with the prior-year period primarily because of improved investment gains. Other income (expenses), net is comprised of the line items other income and other expense from the APS’ Statements of Income.
Income taxes Income taxes were $45 million higher for 2009 compared with the prior-year period primarily because of $29 million of income tax benefits related to prior years recorded in 2008 and higher pretax income. See Note S-1.
Operating Results - 2008 Compared with 2007
APS’ net income for the year ended 2008 was $262 million, compared with net income of $284 million for the comparable prior-year period. The decrease in net income was primarily due to higher operations and maintenance expenses; lower retail sales due to the effects of weather; higher depreciation and amortization expenses; and higher interest charges, net of capitalized financing costs. These negative factors were partially offset by increased revenues due to the rate increase effective July 1, 2007; transmission rate increases; and income tax benefits related to prior years recorded in 2008.
The following table presents net income compared with the prior-year period:
Operating revenues less fuel and purchased power expenses
Electric operating revenues less fuel and purchased power expenses were $59 million higher for the year ended 2008 compared with the prior year. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $77 million for the year ended 2008 compared with the prior year primarily because of:
•
An increase of $30 million related to customer service and other costs including distribution system reliability;
•
An increase of $18 million in generation costs, including more planned maintenance;
•
An increase of $14 million related to renewable energy programs, which are offset in operating revenues;
•
An increase of $9 million associated with employee severance costs in 2008; and
•
An increase of $6 million due to other miscellaneous factors.
Depreciation and amortization Depreciation and amortization expenses increased $18 million for the year ended 2008 compared with the prior year primarily because of increases in utility plant in service. The increases in utility plant in service are the result of various improvements to APS’ existing fossil and nuclear generating plants and distribution and transmission infrastructure additions and upgrades.
Interest charges, net of capitalized financing costs Interest charges, net of capitalized financing costs increased $13 million for the year ended 2008 compared with the prior year primarily because of higher rates on certain APS pollution control bonds and higher short-term debt balances. Interest charges, net of capitalized financing costs, are comprised of the line items interest expense, capitalized interest and allowance for equity funds used during construction from the APS Statements of Income.
Other income (expenses), net Other income (expenses), net reduced earnings by an additional $20 million for the year ended 2008 compared with the prior year primarily because of lower interest income. Other income (expenses), net is comprised of the line items other income and other expense from the APS Statements of Income.
Income taxes Income taxes were $43 million lower for the year ended 2008 compared with the prior year primarily because of $18 million of increased income tax benefits related to prior years resolved in 2008 and 2007. See Note S-1.
ARIZONA PUBLIC SERVICE COMPANY - LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table presents APS’ net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2009, 2008 and 2007 (dollars in millions):
2009 Compared with 2008
The increase of approximately $174 million in net cash provided by operating activities is primarily due to a reduction of collateral and margin cash required as a result of changes in commodity prices.
The decrease of approximately $141 million in net cash used for investing activities is primarily due to lower levels of capital expenditures net of contributions.
The increase of approximately $286 million in net cash used for financing activities is primarily due to repayments of short-term borrowings partially offset by APS’ issuance of $500 million of unsecured senior notes (see Note 6).
2008 Compared with 2007
The increase of approximately $19 million in net cash provided by operating activities is primarily due to lower current income taxes and increased retail revenue related to higher Base Fuel Rates, partially offset by increased collateral and margin cash provided as a result of changes in commodity prices.
The decrease of approximately $2 million in net cash used for investing activities is primarily due to lower levels of capital expenditures (see table and discussion above) and increased contributions in aid of construction related to changes in 2008 in our line extension policy (see Note 3), substantially offset by lower cash proceeds from the net sales and purchases of investment securities.
The increase of approximately $28 million in net cash provided by financing activities is primarily due to higher levels of short-term borrowings, partially offset by decreased equity infusions from Pinnacle West and the repurchase of pollution control bonds (see Note 6).
Liquidity
For a discussion of APS’ capital requirements and liquidity, see “APS” under “Pinnacle West Consolidated - Liquidity and Capital Resources.”
Contractual Obligations
The following table summarizes contractual requirements for APS as of December 31, 2009 (dollars in millions):
(a)
The long-term debt matures at various dates through 2038 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2009 (see Note 6).
(b)
APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Notes 3 and 11).
(c)
Relates to the Palo Verde sale leaseback and other items (see Note 9).
(d)
Contracts to purchase renewable energy credits in compliance with the Renewable Energy Standard.
(e)
These contractual obligations include commitments for capital expenditures and other obligations.
This table excludes $208 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
Page
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)
Report of Independent Registered Public Accounting Firm
Pinnacle West Consolidated Statements of Income for 2009, 2008 and 2007
Pinnacle West Consolidated Balance Sheets as of December 31, 2009 and 2008
Pinnacle West Consolidated Statements of Cash Flows for 2009, 2008 and 2007
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2009, 2008 and 2007
Notes to Pinnacle West’s Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)
Report of Independent Registered Public Accounting Firm
APS Statements of Income for 2009, 2008 and 2007
APS Balance Sheets as of December 31, 2009 and 2008
APS Statements of Cash Flows for 2009, 2008 and 2007
APS Statements of Changes in Common Stock Equity for 2009, 2008 and 2007
Supplemental Notes to APS’ Financial Statements
Financial Statement Schedules for 2009, 2008 and 2007
Pinnacle West Schedule I - Condensed Statements of Income for 2009, 2008 and 2007
Pinnacle West Schedule I - Condensed Balance Sheets as of December 31, 2009 and
Pinnacle West Schedule I - Condensed Statements of Cash Flows for 2009, 2008 and 2007
Pinnacle West Schedule II - Reserve for Uncollectibles for 2009, 2008 and 2007
APS Schedule II - Reserve for Uncollectibles for 2009, 2008 and 2007
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.
February 19, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2009 and 2008 and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 19, 2010
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado and Pinnacle West Marketing & Trading. Intercompany accounts and transactions between the consolidated companies have been eliminated.
APS 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. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. In 2008, APSES discontinued its commodity-related energy services (see Note 22). El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.
In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2009 through the date the financial statements were issued on February 19, 2010.
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 and Consolidated Balance Sheets in accordance with accounting requirements for reporting discontinued operations (see Note 22), and amended accounting guidance on reporting noncontrolling interests in consolidated financial statements (see Note 2). We have also presented certain line items in more detail in the Consolidated Balance Sheets than was presented at December 31, 2008. The prior year amounts were reclassified to conform to the current year presentation. Customer advances, coal mine reclamation and unrecognized tax benefits are presented as separate line items instead of the previously reported single line item of other deferred credits.
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. Customer and other receivables and accrued utility revenues are presented as separate line items instead of the previously reported single line item of customer and other receivables. Accrued taxes and income tax receivable-net and other current liabilities are presented as separate line items instead of the previously reported single line item of other current liabilities. Change in other regulatory liabilities is reported separately from change in other long-term liabilities. These reclassifications had no impact on total net cash flow provided by operating activities.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter 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 that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. See Note 18 for additional information about our derivative accounting policies.
Fair Value Measurements
We determine and disclose the fair value of certain assets and liabilities in accordance with fair value guidance. 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 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 actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use prices for similar instruments or other corroborative market information or prices provided by other external sources. For options, long-term contracts and other contracts for which price quotes 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. Our structured activities are hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.
See Note 14 for additional information about fair value measurements.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 applicable regulatory environment changes and recent rate orders 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.
A component of our regulatory assets and liabilities is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund approximately 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters. See Note 3.
Also included in the balance of regulatory assets at December 31, 2009 is a regulatory asset for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
The detail of regulatory assets is as follows (dollars in millions):
(a)
Subject to a carrying charge.
(b)
There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
(b)
Subject to a carrying charge.
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
•
capitalized interest or an 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2009 were as follows:
•
Fossil plant - 18 years;
•
Nuclear plant - 17 years;
•
Other generation - 29 years;
•
Transmission - 44 years;
•
Distribution - 32 years; and
•
Other - 8 years.
For the years 2007 through 2009, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.06% for 2009, 3.08% for 2008 and 3.11% for 2007. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 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 12 for more information on these investments.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.4% for 2009, 5.2% for 2008 and 5.8% for 2007. Capitalized interest ceases when construction is complete.
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. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. 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 5.9% for 2009, 7.0% for 2008 and 8.2% for 2007. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 purchased power and fuel costs.
Effective January 1, 2010, electric revenues will also include proceeds for line extension payments for new or upgraded service in accordance with the ACC Settlement Agreement (see Note 3). This revenue treatment will continue through 2012 or until new rates are established in APS’ 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.
Real Estate Revenues
SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectability of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method in accordance with accounting guidance relating to sales of real estate. SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, capitalized interest and property taxes directly associated with the acquisition and development of each project. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Homes under construction are classified as “real estate investments” on the Consolidated Balance Sheets; upon completion of construction they are transferred to “home inventory” with the expectation that they will be sold in a timely manner.
For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets, we classify our real estate assets, including land under development, land held for future development, and commercial property as “held and used.” When events or changes in circumstances indicate that the carrying values of real estate assets considered held and used may not be recoverable, we compare the undiscounted cash flows that we estimate will be generated by each asset to its carrying amount. If the carrying amount exceeds the undiscounted cash flows, we adjust the asset to fair value and recognize an impairment charge. The adjusted value becomes the new book value (carrying amount) for held and used assets. Our internal models use inputs that we believe are consistent with those that would be used by market participants.
Real estate home inventory is considered to be held for sale for purposes of evaluating impairment in accordance with the provisions of accounting for impairment or disposal of long-lived assets. Home inventories are reported at the lower of carrying amount or fair value less costs to sell. Fair value less costs to sell is evaluated each period to determine if it has changed. Losses (and gains not to exceed any cumulative loss previously recognized) are reported as adjustments to the carrying amount.
Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated, but are accounted for using the equity method of accounting. In addition, see Note 22 and Note 23.
Cash and Cash Equivalents
We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.
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 12 for information on nuclear decommissioning costs.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’ software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $35 million in 2009, $33 million in 2008 and $37 million in 2007. Estimated amortization expense on existing intangible assets over the next five years is $33 million in 2010, $27 million in 2011, $23 million in 2012, $18 million in 2013 and $13 million in 2014. At December 31, 2009, the weighted average remaining amortization period for intangible assets was 7 years.
2. New Accounting Standards
Variable Interest Entities
In June 2009, the FASB issued amended guidance on the consolidation of variable interest entities. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling financial interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. The new guidance requires an enterprise with a variable interest in a VIE to perform a qualitative assessment in determining whether it has a controlling financial interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, the amended guidance requires companies to continually evaluate VIEs for consolidation. This guidance was effective for us on January 1, 2010. We are continuing to evaluate the impact this new guidance may have on our financial statements. See Note 20.
Fair Value Measurements and Disclosures
We adopted guidance relating to fair value measurements and disclosures for our non-financial assets on January 1, 2009. This guidance was adopted for our financial assets on January 1, 2008.
On April 1, 2009, we adopted new fair value accounting provisions on the following topics:
•
Determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly.
•
The recognition and presentation of other-than-temporary impairments.
•
Interim disclosures about fair value of financial instruments.
On October 1, 2009, we adopted new fair value accounting provisions on the following topics:
•
Measuring fair value of liabilities, which provides additional guidance on how fair value measurements of liabilities should be determined.
•
Measuring fair value of certain alternative investments. This guidance provides clarification on the measurement and disclosure of investments in entities that calculate net asset value.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The adoption of fair value measurement and disclosure guidance has not had a significant impact on our financial statement results. See Note 14 for fair value discussions and related disclosures.
In January 2010 guidance was issued that amends the fair value disclosure requirements. This guidance adds new fair value disclosures and clarifies existing disclosure requirements. This amended guidance is effective for us during the first quarter of 2010. The adoption of this new guidance will not have an impact on our financial statement results.
Derivative Instruments
We adopted amended guidance on disclosures about derivative instruments and hedging activities on January 1, 2009. See Note 18 for additional information and related disclosures. Since this guidance provides only disclosure requirements, the adoption of this standard did not impact our financial statement results.
Noncontrolling Interests
We adopted amended guidance on reporting noncontrolling interests in consolidated financial statements on January 1, 2009. This guidance provides accounting and reporting standards for noncontrolling interests in a consolidated subsidiary and clarifies that noncontrolling interests should be reported as equity on the consolidated financial statements. As a result of adopting this guidance, we have disclosed on the face of our financial statements the portion of equity and net income attributable to the noncontrolling interests in consolidated subsidiaries. Additionally, we reclassified $47 million of noncontrolling interests from other deferred credits to equity on the December 31, 2008 Consolidated Balance Sheets. Prior year’s net income attributable to noncontrolling interests was not material to our Consolidated Statements of Income and was not reclassified. The adoption of this guidance modified our financial statement presentation, but did not have an impact on our financial statement results.
Employers’ Disclosure about Postretirement Benefit Plan Assets
In December 2008, the FASB issued guidance on employers’ disclosures about postretirement benefit plan assets. This guidance requires enhanced disclosures about employers’ plan assets of a defined benefit pension or other postretirement plan including fair value related disclosures. We adopted this guidance during the fourth quarter of 2009. See Note 8 for the related disclosures. The adoption of this guidance expanded certain disclosures but did not have an impact on our financial statement results.
Subsequent Events
In May 2009, the FASB issued guidance which established general standards of accounting for and disclosure of subsequent events. Subsequent events are events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this guidance during the second quarter of 2009. The adoption of this guidance expanded certain disclosures but did not have an impact on our financial statement results.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Regulatory Matters
2008 General Retail Rate Case Decision
On December 30, 2009, the ACC issued an order approving a settlement agreement (“Settlement Agreement”) entered into by APS and twenty-one other parties to its general retail rate case, which was originally filed in March 2008. The ACC approved the Settlement Agreement with modifications and obligations for APS that did not materially affect the overall economic terms of the settlement.
The Settlement Agreement includes a net retail rate increase of $207.5 million, which represents a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the existing PSA to base rates. The new rates were effective January 1, 2010.
The parties also agreed to a rate case filing plan in which APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless certain extraordinary events occur. Subject to the foregoing, APS may not request its next general retail rate increase to be effective prior to July 1, 2012. The parties agreed to use good faith efforts to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a rate case.
Other key provisions of the Settlement Agreement, effective January 1, 2010, include the following:
•
A non-fuel base rate increase in annual pretax revenues of $196.3 million;
•
A net increase in annual pretax revenues of $11.2 million for fuel and purchased power costs reflected in base rates that would not otherwise have been recoverable under the PSA;
•
A Base Fuel Rate of $0.0376 per kWh (compared to the prior Base Fuel Rate of $0.0325 per kWh);
•
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’ next general rate case, if that is before the end of 2012), resulting in present estimates of increased revenues of $23 million, $25 million and $49 million, respectively;
•
An authorized return on common equity of 11.0%;
•
A capital structure comprised of 46.2% debt and 53.8% common equity;
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•
A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;
•
Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014; 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 supportive 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 Arizona Renewable Energy Standard and Tariff (“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 an RES surcharge on 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 the upcoming year’s RES funding amount.
During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe and requesting 2010 RES funding approval. The plan provides for the acquisition of renewable generation in compliance with requirements through 2014, and requests RES funding of $86.7 million for 2010. APS also seeks various other determinations in its plan, including approval of the AZ Sun program, which provides for 100 MW of utility-owned solar resources through 2014 and recovery of associated costs through the RES adjustor until such costs can be recovered through APS’ base rates or alternative mechanisms. At its December open meeting, the ACC approved APS’ 2010 RES funding request, and deferred action on other portions of APS’ plan including the AZ Sun matter. On February 10, 2010, the ACC staff issued a recommendation that the ACC approve APS’ request on the AZ Sun matter. It is expected that the ACC will make a determination on this matter in March 2010.
Demand-Side Management Adjustor Charge. The Settlement Agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency Implementation Plan, requesting approval by the ACC of programs and program elements for which APS has estimated a budget in the amount of $49.9 million for 2010. In order to recover these estimated amounts for use on certain demand-side management programs, a surcharge would be added to customer bills similar to that described above under the RES. The surcharge will offset energy efficiency expenses and allow for the recovery of any earned incentives. APS received ACC approval of all but one of its proposed programs and expects to receive a determination from the ACC on the remaining program in the near future.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The ACC approved recovery of the 2010 Energy Efficiency budget less some $1.0 million, which reflected a recalculation of the incentive payment due to APS under the Energy Efficiency Implementation Plan and not a reduction in allowed program costs. The ACC also 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 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 spread over a three-year period.
PSA Mechanism and Balance. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, and which was modified by the ACC in 2007, 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 purchase 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;
•
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 will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); and
•
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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2009 and 2008 (dollars in millions):
The PSA rate for the PSA Year that began February 1, 2010 was set at ($0.0045) per kWh. The $87 million regulatory liability at December 31, 2009 reflected lower average prices and the seasonal nature of fuel and purchased power costs. These overcollected fuel cost deferrals during the 2009 PSA Year were refunded through the historical component of the PSA rate for the PSA Year beginning February 1, 2010. Since this 2010 PSA adjustment was a reduction of the PSA rate, the ACC accelerated the 2010 adjustment from February 1st to January 1st to coincide with the increase in retail rates resulting from the ACC’s decision in the general retail rate case, causing a minimal net impact on residential bills. This accelerated 2010 adjustment will remain in effect until February 1, 2011.
The PSA rate for the PSA Year that began February 1, 2009 was $0.0053 per kWh. The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
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 the costs that APS incurs in providing transmission services. The formula rate is updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. A large portion of the rate represents charges for transmission services to serve APS’ 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 under the TCA mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.
In 2009, APS was authorized to implement an increase in its annual transmission revenues based on calculations filed with the FERC using data for its 2008 fiscal year. Increases in APS’ annual transmission revenues of $22.8 million became effective June 1, 2009. Of this amount, $21 million represents an increase in Retail Transmission Charges, which was approved by the ACC on July 29, 2009 and allows APS to reflect the related increased Retail Transmission Charges in its retail rates through the TCA effective August 1, 2009.
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 current income tax rates.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
Pinnacle West expects to recognize approximately $125 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 23) which will not be realized until the asset sale transactions are completed. Approximately $105 million of these benefits were recorded in 2009 as reductions to income tax expense related to the current impairment charges. The additional $20 million of tax benefits were recorded as reductions to income tax expense related to the SunCor impairment charge recorded in the fourth quarter of 2008.
The $91 million income tax receivables on the Consolidated Balance Sheets represent the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009 and the current year tax benefits related to the SunCor strategic asset sales that closed in 2009.
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 period that are included in accrued taxes and unrecognized tax benefits on the Consolidated Balance Sheets (dollars in thousands):
Included in both balances of unrecognized tax benefits at December 31, 2009 and 2008 were approximately $16 million of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2005 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 before 1999.
Within the next 12 months, it is reasonably possible that the Company will reach a settlement with the IRS with regard to the examination of tax returns for years ended December 31, 2005 through 2007. As a result of these anticipated settlements, and the expiration of certain statutes of limitations, the Company believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $70 million.
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 $2 million for 2009 and pre-tax benefit of $51 million for 2008.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The total amount of accrued liabilities for interest recognized in the consolidated balance sheets related to unrecognized tax benefits was $8 million as of December 31, 2009 and $6 million as of December 31, 2008. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2009, we have recognized $1 million of interest expense to be paid on the underpayment 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):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Lines of Credit and Short-Term Borrowing
Pinnacle West and APS maintain credit facilities in order to enhance liquidity and provide credit support. The credit and liquidity markets experienced significant stress beginning in the third quarter of 2008. Since the fourth quarter of 2008, Pinnacle West and APS have not accessed the commercial paper market due to negative market conditions. They have both been able to access existing credit facilities, ensuring adequate liquidity. The table below presents the consolidated lines of credit available and outstanding as of December 31, 2009 (dollars in millions):
The PNW revolver is available to support the issuance of up to $250 million in commercial paper or bank borrowings, including issuances of letters of credit up to $94 million.
The APS revolvers are available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $583 million. See Note 21 for discussion of APS’ letters of credit. At December 31, 2009, APS had no borrowings and no letters of credit under its revolving lines of credit.
The table below presents the consolidated lines of credit available and outstanding as of December 31, 2008 (dollars in millions):
Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2008. Credit commitments totaling approximately $17 million from Lehman Brothers were no longer available. The remaining $283 million was available to support the issuance of up to $250 million in commercial paper or bank borrowings, including issuances of letters of credit up to $94 million of which $7 million was outstanding.
APS had committed lines of credit totaling $900 million at December 31, 2008. Credit commitments totaling approximately $34 million from Lehman Brothers were no longer available. The remaining capacity of $866 million under the APS revolvers was available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $583 million.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. The new revolving credit facility terminates in February 2013. Pinnacle West may 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. Pinnacle West will use the facility for general corporate purposes, repayment of long-term debt, and for the issuance of letters of credit. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. In addition, because of the downsized revolving credit facility, the Company is in the process of reducing the size of its commercial paper program to $200 million from $250 million.
On February 12, 2010, APS refinanced its $377 million revolving credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2013. 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 for general corporate purposes and for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.
Although provisions in APS’ 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’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’ 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.
See discussion about SunCor’s Secured Revolver in Note 6.
Other Short-term Borrowings
Neither Pinnacle West nor APS had commercial paper borrowings or other short-term debt at December 31, 2009 or December 31, 2008. SunCor had other short-term notes of approximately $5 million at December 31, 2009 and December 31, 2008 with variable interest rates based on LIBOR plus 2.5%.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. Long-Term Debt and Liquidity Matters
Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2009 and 2008 (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 0.25% at December 31, 2009 and 8.30% at December 31, 2008. The 2008 weighted average rate included rates associated with debt securities in auction rate mode. See discussion of the refinancing of pollution control bonds below.
(c)
The bonds’ fixed rate of interest range from 5.00% to 6.00% and are subject to mandatory tender dates. Refer to the discussion below on Pollution Control Bonds.
(d)
On February 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019.
(e)
The weighted-average interest rate was 5.50% at December 31, 2009 and 5.51% at December 31, 2008.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(f)
APS’ long-term debt less current maturities was $3.180 billion at December 31, 2009 and $2.850 billion at December 31, 2008. APS’ current maturities of long-term debt was $197 million at December 31, 2009 and $1 million at December 31, 2008.
(g)
SunCor had $57 million outstanding at December 31, 2009 and $120 million at December 31, 2008 under its secured revolver that matured on January 30, 2010. The weighted-average interest rates were 5.00% at December 31, 2009 and 4.19% at December 31, 2008. At December 31, 2009 and December 31, 2008 approximately $39 million and $63 million of other debt remained outstanding under other long-term credit facilities. The remaining debt which is primarily classified as current maturities of long-term debt consisted of multiple notes with variable interest rates of prime plus 2.0% and LIBOR plus 1.70%, 2.0%, 2.25% and 2.50% at December 31, 2009. At December 31, 2008, the remaining debt consisted of multiple notes with variable interest rates of prime plus 1.75% and 2.00% and LIBOR plus 1.70%, 2.00%, 2.25%, 2.50% and a fixed rate note of 4.25%. See below for further discussion of SunCor debt.
(h)
The weighted-average interest rate was 4.9% at December 31, 2009 and 6.2% at December 31, 2008.
Debt Issuances
Unsecured Senior Notes
On February 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019. Net proceeds from the sale of the notes were used to repay short-term borrowings under two committed revolving lines of credit incurred to fund capital expenditures and for general corporate purposes.
Pollution Control Bonds
During 2009, APS refinanced approximately $343 million of its $656 million pollution control bonds. As a result of these refinancings, which are described in the following table, APS no longer has any outstanding debt securities in auction rate mode. Each series of bonds, described below, is payable solely from revenues obtained from APS pursuant to a loan agreement between APS and the respective pollution control corporation. The interest rates on these bonds are fixed through the applicable interest reset dates as presented in the table below. At the interest reset dates, we will be required to purchase the bonds and will have the opportunity to remarket the bonds in daily, weekly, monthly or other interest rate modes at that time. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
Issued to redeem all of approximately $166 million of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2004 Series A-E, due 2034.
(2)
Issued to redeem all of approximately $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2004 Series A, due 2034.
(3)
Issued to redeem all of approximately $164 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds 2005 Series A-E, due 2029.
On September 11, 2008, APS purchased all of the approximately $27 million of the Coconino County, Arizona Pollution Control Corporation (“Coconino”) Pollution Control Revenue Bonds, Series 1996A and Series 1999 due December 2031 and April 2034 and held them as treasury bonds. On September 22, 2009, Coconino issued approximately $27 million of Coconino Pollution Control Revenue Refunding Bonds, 2009 Series B due April 2038 to redeem the existing bonds. APS used the funds received from the issuance to repay certain existing indebtedness under a revolving line of credit drawn upon by APS to fund its purchase of the 1996A and 1999 Series Bonds in 2008. The 2009 Series B Bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino. According to the indenture of the bonds, the interest rate of the 2009 Series B Bonds could be reset daily, weekly, monthly, or at other time intervals. The initial rate period selected for the 2009 Series B Bonds is a daily rate period. At December 31, 2009, the daily interest rate was 0.26%. The daily rates are variable rates set by a remarketing agent. Concurrently with the issuance of the 2009 Series B Bonds, the Company entered into a two year letter of credit and reimbursement agreement to provide credit support for the 2009 Series B Bonds. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2009.
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Approximately $196 million of pollution control bonds were classified as current maturities of long-term debt at December 31, 2009. Currently, interest rates on these bonds are set daily by a remarketing agent. Additionally, the bonds are backed by letters of credit that expire in 2010, at which time the letters of credit will have to be replaced, renewed or extended, or the bonds will have to be remarketed in a different interest rate mode. The bond holders will have to surrender the bonds back to APS if APS decides to remarket them in a different interest rate mode.
The interest rate on the remaining $90 million of pollution control bonds with senior notes is fixed for life, and the bonds are also backed by insurance. The bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2009.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2009, the ratio was approximately 52% for Pinnacle West and 48% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.6 times under APS’ bank financing agreements as of December 31, 2009. 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’ 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 financing agreements contain a pricing grid in which the interest costs we pay 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’ 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 revolver 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 common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2009, APS common equity ratio, as defined, was 50%. Its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.8 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.7 billion, assuming APS’ total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SunCor - SunCor's principal loan facility, the SunCor Secured Revolver, is secured primarily by an interest in land, commercial properties, land contracts and homes under construction. At December 31, 2009, SunCor had borrowings of approximately $57 million under the Secured Revolver. The revolver matured on January 30, 2010. SunCor and the agent bank for the Secured Revolver are discussing an extension of the maturity date to allow time for SunCor to continue discussions concerning the potential sale of additional properties. In addition to the Secured Revolver, at December 31, 2009, SunCor had approximately $43 million of outstanding debt under other credit facilities ($9 million of which has matured since December 31, 2009 and remains outstanding). SunCor intends to apply the proceeds of planned asset sales (see Note 23) to the repayment of its outstanding debt.
Real estate impairment charges recorded throughout 2009 (see Note 23) resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor's other credit facilities. The lenders have taken no enforcement action related to the covenant defaults.
If SunCor is unable to obtain an extension or renewal of the Secured Revolver or its other matured debt, or if it is unable to comply with the mandatory repayment and other provisions of any new or modified credit agreements, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such an immediate repayment obligation would have a material adverse impact on SunCor's business and financial position and impair its ongoing viability.
SunCor cannot predict the outcome of negotiations with its lenders or its ability to sell assets for sufficient proceeds to repay its outstanding debt. SunCor's ability to generate sufficient cash from operations while it pursues lender negotiations and further asset sales is uncertain.
Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. While there can be no assurances as to the ultimate outcome of this matter, Pinnacle West does not believe that SunCor's inability to obtain waivers or similar relief from SunCor's lenders would have a material adverse impact on Pinnacle West's cash flows or liquidity.
As of December 31, 2009, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not materially affect Pinnacle West's ability to meet its ongoing capital requirements.
The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2009, 2008 and 2007 is as follows (dollars in thousands):
(a)
Represents shares of common stock withheld from certain stock awards for tax purposes.
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension 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.
We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide 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 plans, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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 or billed to electric plant participants) (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2009 and 2008 (dollars in thousands):
The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2009 and 2008 (dollars in thousands):
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2009 and 2008 (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2009 and 2008 (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 2010 (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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2010, we are assuming an 8.25% 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 have a significant effect on the amounts reported for the health care plans. In selecting our health care trend rate, 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 obligation. To achieve this objective, the Plans’ investment policies provide for a mix of investments in 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 prohibition of investments in Pinnacle West securities and the external management of the Plans’ assets.
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 2009 year-end long-term fixed income asset strategy focused on investments in corporate bonds of primarily investment-grade U.S. issuers, with total long-term fixed income assets representing 45% of total pension plan assets and 40% 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 2009 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 2009 year-end return-generating assets represented 55% of total pension plan assets and 60% of other benefit plans assets.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
See Note 14 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2009, by asset category, are as follows (dollars in thousands):
(a)
Represents netting under master netting arrangements and Plan receivables and payables.
(b)
This category consists primarily of municipality issued debt securities, but also includes U.S. Treasuries and asset-backed securities such as collaterized mortgage obligations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2009 (dollars in thousands):
Contributions
The required minimum contribution to our pension plan is zero in 2010 and approximately $100 million in 2011. In January 2010, we made a voluntary contribution of approximately $50 million to our pension plan and we expect to make an additional voluntary contribution of $50 million later in 2010. The contribution to our other postretirement benefit plans in 2010 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.
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 expected future other benefit payments take into account the Medicare Part D subsidy.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2009, costs related to APS’ employees represented 97% 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 $9 million for 2009, $8 million for 2008 and $7 million for 2007.
9. Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases or to purchase the property for fair market value at the end of the lease terms. APS must give notice to the respective lessors between December 31, 2010 and December 31, 2012 if it wishes to exercise, or not exercise, either of these options. We are analyzing these options. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.
In addition, 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 $73 million in 2009, $74 million in 2008 and $73 million in 2007. APS’ lease expense was $64 million in 2009, $67 million in 2008 and $66 million in 2007.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2010 to 2015.
Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2009 (dollars in thousands):
(a)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(b)
Weighted average of interests.
11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim. In August 2008, the United States Court of Appeals for the Federal Circuit issued decisions in three damages actions brought by other nuclear utilities that resulted in APS revising its damages claim prior to trial. The trial in the APS matter began on January 28, 2009, and closing arguments were heard in late May 2009. The court has not indicated when it will reach its decision in the matter. In January 2010, on appeal of another utility’s damages case in which the DOE successfully raised the unavoidable delays defense, the Court of Appeals for the Federal Circuit reversed the lower court’s decision and concluded that the Court of Federal Claims, the court handling the APS matter, is bound by the November 1997 D.C. Circuit decision that prevents the DOE from excusing its delay in performance.
APS currently estimates it will incur $132 million (in 2009 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, 2009, APS had a regulatory liability of $34 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’ interest in the three Palo Verde units, APS’ 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 $19 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 $52 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fuel and Purchased Power Commitments
Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2010 and 2042 that include required purchase provisions. Pinnacle West and APS estimate the contract requirements to be approximately $444 million in 2010; $336 million in 2011; $351 million in 2012; $457 million in 2013; $490 million in 2014; and $6.4 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 $721 million. The total net present value of these commitments is approximately $501 million.
Renewable Energy Credits
APS has entered into contracts to purchase renewable energy credits to comply with the Renewable Energy Standard. APS estimates the contract requirements to be approximately $48 million in 2010; $15 million in 2011; $15 million in 2012; $15 million in 2013; $15 million in 2014; and $142 million thereafter.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $92 million at December 31, 2009 and $91 million at December 31, 2008.
California Energy Market Issues and Refunds in the Pacific Northwest
In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. In addition, on March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including APS, failed to properly file rate information at the FERC in connection with sales to California from 2000 to March 2002 under market-based rates. Since 2004, the Ninth Circuit and the FERC have issued various decisions and orders involving the aforementioned issues, including decisions related to: entities subject to FERC jurisdiction and, therefore, potentially owing refunds; applicable refund
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
methodologies; the temporal scope and types of transactions that are properly subject to the refund orders; and the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings. A settlement, resolving APS’ issues with certain California parties for the current refund period, was approved by the FERC in an order issued on June 30, 2008. The resolution of the claims related to the parties involved in this settlement had no material adverse impact on our financial position, results of operations or cash flows. We currently believe the refund claims at the FERC related to the parties not involved in this settlement will have no material adverse impact on our financial position, results of operations or cash flows.
On July 25, 2001, the FERC also 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. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. 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, Operable Unit 3 (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 $1.2 million, which is reserved as a liability on our financial statements. 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.
Landlord Bankruptcy
On April 16, 2009, the landlord for our corporate headquarters building announced that it is seeking relief under Chapter 11 of the United States Bankruptcy Code. We currently have several assets on our books related to our landlord, the most significant of which is an asset related to levelized rent payments for the building of approximately $66 million. This amount will continue to increase to approximately $94 million as a result of the lease terms until 2015, when this amount will begin to decrease over the remaining life of the lease. We are monitoring this matter and, while there can be no assurances as to the ultimate outcome of the matter due to the complexity of the bankruptcy proceedings, we currently do not expect that it will have a material adverse effect on our financial position, results of operations, or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Asset Retirement Obligations and Nuclear Decommissioning Trust
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. 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’ 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 generation sites are strategically located to serve APS Native Load customers. The asset retirement obligations associated with our non-regulated assets are immaterial.
The following schedule shows the change in our asset retirement obligations for 2009 and 2008 (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 1.
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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 a tax efficient manner in fixed income securities and domestic 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. 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 recorded the offsetting amount of gains or losses on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2009 and December 31, 2008 (dollars in millions):
(a)
Net receivables relate to pending securities sales and purchases.
(a)
Net receivables 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, 2009 is as follows (dollars in millions):
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See Note 14 for a discussion of Fair Value Measurements.
13. Selected Quarterly Financial Data (Unaudited)
Consolidated quarterly financial information for 2009 and 2008 is as follows (dollars in thousands, except per share amounts):
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Earnings per share:
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14. Fair Value Measurements
We disclose the fair value of certain assets and liabilities according to a 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 - Quoted prices in active markets for identical assets or liabilities. 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 derivative instruments that are exchange-traded such as futures, cash equivalents invested in exchange-traded money market funds, exchange-traded equities, and nuclear decommissioning trust investments in Treasury securities.
Level 2 - 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. Derivative instruments in this category include nonexchange-traded contracts such as forwards, options, and swaps. This category also includes investments, in common and commingled funds that are redeemable and valued based on the funds’ net asset values. 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Level 3 - Model-derived valuations with 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, transactions in locations where observable market data does not exist, and common and collective trusts with significant restrictions on our ability to transact in the fund. 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.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. 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 and their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions.
For non-exchange traded 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 overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans (see Note 8). We may be required to record other assets at fair value on a nonrecurring basis. These nonrecurring fair value measurements typically involve write-downs of individual assets due to impairment.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Some of our derivative instrument transactions 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. 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 is not reflective of material inactive markets.
The nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. The commingled equity funds are valued based on the fund’s net asset value (“NAV”) and are classified within Level 2. We may transact in the fund on a semi-monthly basis. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. The trust fund investments have been established to satisfy APS’ nuclear decommissioning obligations (see Note 12).
The following table presents the fair value at December 31, 2009 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a)
Primarily represents netting under master netting arrangements, including margin and collateral. See Note 18.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value at December 31, 2008 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a)
Primarily represents netting under master netting arrangements, including margin and collateral. See Note 18.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2009 and 2008 (dollars in millions):
(a)
Earnings are recorded in regulated electricity segment revenue or regulated electricity segment fuel and purchased power.
(b)
Transfers in or out of Level 3 reflect the fair market value at the beginning of the period. Transfers are generally triggered by a change in the lowest significant input and are typically related to our long-dated energy transactions that extend beyond available quoted periods.
The following table represents the carrying amount and estimated fair value of our debt which is not carried at fair value on the balance sheet. The carrying value of our cash, net accounts receivable, accounts payable and short-term borrowings approximate fair value. 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. Our debt fair value estimates are based on quoted market prices of the same or similar issues (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We adopted guidance on fair value measurements and disclosures, for our nonfinancial assets and liabilities on January 1, 2009, and it did not have a material impact on our financial statements. We apply nonrecurring fair value measurements to certain real estate assets. These adjustments to fair value are the result of write-downs of individual assets due to impairment. Certain of our real estate assets have been impaired due to the distressed real estate market. We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. These fair value determinations require significant judgment regarding key assumptions. Due to these unobservable inputs, the valuation of real estate assets are considered Level 3 measurements.
As of December 31, 2009, the fair value of our impaired real estate assets that are measured at fair value on a nonrecurring basis was $46 million, all of which was valued using significant unobservable inputs (Level 3). Total impairment charges included in net income for the year ended December 31, 2009 were approximately $280 million (including net loss attributable to noncontrolling interests of $14 million before income taxes). Total impairment charges for the year ended December 31, 2008 were approximately $53 million. See Note 23 for additional information.
15. Earnings Per Share
The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2009, 2008 and 2007:
Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 103,000 shares in 2009, 274,000 shares in 2008 and 579,000 shares in 2007. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 101,263,795 shares in 2009, 100,964,920 shares in 2008 and 100,834,871 shares in 2007.
Options to purchase 572,301 shares of common stock at December 31, 2009 were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 687,375 at December 31, 2008 and 114,213 at December 31, 2007.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Stock-Based Compensation
We have a 2007 long-term incentive plan (“2007 Plan”) that allows the Company to grant restricted stock, restricted stock units, performance shares, stock grants, incentive and stock options, stock appreciation rights, performance share units, performance cash awards, dividend equivalents and stock to eligible individuals.
Restricted Stock Unit Awards and Stock Grants
Stock grants were issued to non-officer members of the Board of Directors in 2009, 2008 and 2007 under the 2007 Plan and were paid in fully transferable shares of stock. Restricted stock unit awards were granted to officers and key employees in 2009, 2008 and 2007 under the 2007 Plan. 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. Each restricted stock unit payable in cash represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock. Restricted stock unit awards vest and settle in annual installments over a four-year period. In addition, officers and key employees will receive a cash payment equal to the amount of dividends that they would have received if they had owned the stock to which the restricted stock units relate from the date of grant to the date of payment plus interest. For any employee that was eligible to retire before the settlement date, the employee’s restricted stock unit awards vest by retirement date and the compensation expense is recognized by retirement eligibility. As the restricted stock unit award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price.
Restricted stock unit awards were granted to a selected set of key employees of Pinnacle West on October 21, 2008, February 18, 2009, March 18, 2009, April 13, 2009 and July 29, 2009 under the 2007 Plan. The award of the restricted stock unit awards follows the same vesting schedule as the 2007 and 2008 restricted stock unit awards.
The following table is a summary of granted restricted stock units and stock grants and the weighted average fair value for the three years ended 2009, 2008 and 2007:
(a)
weighted average fair value
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2009 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 payment for the 2007 grant on February 20, 2009 and February 20, 2008 was $0.8 million and $1.0 million respectively. The amount of cash required to settle the payment for the 2008 grant on February 20, 2009 was $1.3 million.
Performance Share Awards
Performance share awards were granted to officers and key employees in 2009 and 2008 under the 2007 Plan. Performance share awards for 2008 contain performance criteria that affect the number of shares ultimately received. Generally, each recipient of performance shares is entitled to receive shares of common stock after the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based 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 rate of all relevant companies in a specified utilities index. Performance share awards for 2009 also contain performance criteria that affect the number of shares that ultimately vest, 50% of the award is based on the same percentile ranking as the 2008 award and the other 50% of the award is based on six separate performance metrics. For any employee that was eligible to retire before the settlement date, the employee’s performance share awards vest by retirement date and the compensation expense is recognized by retirement eligibility. As the performance share award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. Management also evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
Performance shares were granted to officers and key employees of Pinnacle West on October 21, 2008, February 18, 2009, March 18, 2009, April 13, 2009 and July 29, 2009 under the 2007 Plan. This award of performance shares follows the same vesting schedule as the prior performance shares awarded.
The following table is a summary of the Performance shares granted and the weighted average fair value for the three years ended 2009, 2008 and 2007:
(a)
weighted average grant date fair value
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the status of performance shares, as of December 31, 2009 and changes during the year:
Retention Units
Retention unit awards were granted to key employees in 2006 and 2007. Each retention unit award represents 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 vests and settles in equal annual installments over a four-year period. In addition, the employee will receive 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. 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. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’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 2009 was $1.1 million, 2008 was $1.3 million and 2007 was $1.6 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
We have issued stock options in the past, but have not granted stock options since 2004. The term of outstanding options cannot be longer than 10 years and options cannot be repriced during their terms.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the option activity under our equity incentive plans for the year ended December 31, 2009:
Cash received from options exercised under our share-based payment arrangements was $3 million for 2009, zero for 2008 and $8 million for 2007. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements were immaterial for 2009, zero for 2008 and $1 million for 2007.
The intrinsic value of options exercised was immaterial for 2009, zero for 2008 and $2 million for 2007.
As of December 31, 2009, there was $12 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 2009 was $10 million, 2008 was $5 million and $6 million for 2007.
We have reserved 8 million shares of common stock for issuance under the 2007 Plan. Under the 2007 Plan, any shares of stock that are potentially deliverable under the 2002 long term incentive plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company.
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $5 million in 2009, $8 million in 2008 and $6 million in 2007. The compensation cost that Pinnacle West has capitalized was immaterial in 2009, 2008 and 2007. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $2 million in 2009, $3 million in 2008 and $2 million in 2007. APS’ share of compensation cost that has been charged against income was $4 million in 2009, $7 million in 2008 and $6 million in 2007.
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 2010.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. Business Segments
Pinnacle West’s two reportable business segments are:
•
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; and
•
our real estate segment, which consists of SunCor’s real estate development and investment activities.
Financial data for 2009, 2008 and 2007 is provided as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a)
Due to the current and anticipated continuing distressed conditions in the real estate and credit markets, 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 reduce its outstanding debt (see Note 23). As a part of this plan to sell substantially all of SunCor’s assets, the real estate segment may no longer be a reporting segment in the future.
(b)
All other activities relate to APSES, Silverhawk and El Dorado. Income from discontinued operations for 2008 is primarily related to the resolution of certain tax issues associated with the sale of Silverhawk in 2005. None of these segments is a reportable segment.
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 these market fluctuations by utilizing various derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. Derivative instruments that are designated as cash flow hedges are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We may also invest in derivative instruments for trading purposes; however, for the year ended December 31, 2009, there was no material trading activity.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our derivative instruments are accounted for at fair value; see Note 14 for a discussion of fair value measurements. Derivative instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative instrument discussion and disclosures below.
We 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. Economic hedges not designated as accounting hedges are recorded at fair value on our balance sheet with changes in fair value recognized in the statement of income as incurred. These instruments are included in the “non-designated hedges” discussion and disclosure 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 between 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 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, 2009, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.
In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in 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 in our Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.
For its regulated operations, 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, 2009, we had the following outstanding gross notional amount of derivatives, which represent both purchases and sales (does not reflect net position):
(a)
“MMBTU” is one million British thermal units
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments in Designated Accounting Hedging Relationships
The following table provides information about gains and losses from derivative instruments in designated accounting hedging relationships and their impact on our Consolidated Statements of Income during the year ended December 31, 2009 (dollars in thousands):
(a)
During the year ended December 31, 2009, $192 thousand was reclassified from AOCI to earnings related to discontinued cash flow hedges.
During the next twelve months, we estimate that a net loss of $68 million before income taxes will be reclassified from accumulated other comprehensive income 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.
Derivative Instruments Not Designated as Accounting Hedges
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments and their impact on our Consolidated Statements of Income during the year ended December 31, 2009 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Values of Derivative Instruments in the Consolidated Balance Sheets
The following table provides information about the fair value of our derivative instruments, margin account and cash collateral 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, 2009 (dollars in thousands):
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 one counterparty for which our exposure represents approximately 31% of Pinnacle West’s $79 million of risk management assets as of December 31, 2009. This exposure relates to a long-term traditional wholesale contract with a counterparty that has very 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on December 31, 2009 was $283 million, for which we had posted collateral of $92 million in the normal course of business.
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), which would be a violation of the credit rating provisions. If the investment grade contingent features underlying these agreements had been triggered on December 31, 2009, after off-setting asset positions under master netting arrangements we would have been required to post approximately an additional $100 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. 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 $200 million if our debt credit ratings were to fall below investment grade.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2009, 2008 and 2007 (dollars in thousands):
(a)
Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20. Variable-Interest Entities
See Note 2 for a discussion of the amended accounting guidance relating to VIEs adopted on January 1, 2010. Our December 31, 2009 financial statements and the following disclosure do not reflect the adoption of this new guidance.
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements 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 assume the debt associated with the transactions, make specified payments to the equity participants, 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, 2009, APS would have been required to assume approximately $152 million of debt and pay the equity participants approximately $153 million.
We have certain long-term purchase power agreements where we purchase substantially all of an entity’s output from a specified facility for a specified period. We have evaluated these arrangements under the variable interest accounting guidance and have determined that these agreements do not represent variable interests. If these agreements had been deemed variable interests in these entities, we would not be considered the primary beneficiary of these entities and therefore would not consolidate the entities.
SunCor is the primary beneficiary of certain land development arrangements and, accordingly, consolidates the variable interest entities. The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $29 million at December 31, 2009 and December 31, 2008.
21. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries.
Our parental guarantees for APS relate to commodity energy products. In addition, Pinnacle West has obtained approximately $8 million of surety bonds related to APS’ operations, which primarily relate to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At December 31, 2009, we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2009 are as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2009, approximately $227 million of letters of credit were outstanding to support existing pollution control bonds of approximately $224 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $70 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Notes 9 and 20 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
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.
22. Discontinued Operations
SunCor (real estate segment) - In 2007, 2008 and 2009, SunCor sold properties that are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income. Prior year income statement amounts related to these properties were reclassified from operations to discontinued operations. The asset sales resulted in no gain for 2009, a $24 million after tax gain in 2008 and a $10 million after tax gain in 2007. In addition, see Note 23 - Real Estate Impairment Charge.
Silverhawk - Includes activities related to the resolution of certain tax issues in 2008 associated with the sale of Silverhawk in 2005.
APSES (other) - Includes activities related to the APSES discontinued commodity-related energy services in 2008, and the associated revenues and costs that were reclassified to discontinued operations in 2008 and 2007.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2009, 2008 and 2007 (dollars in millions):
(a)
APSES discontinued its commodity-related energy services in 2008 and the associated revenues and costs were reclassified to discontinued operations in 2008 and 2007.
(b)
Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $9 million for the year ended December 31, 2009.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
23. Real Estate Impairment Charge
During the first quarter of 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the then current and anticipated continuing 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. During 2009 we recorded impairment charges of approximately $266 million pre-tax and $161 million after income taxes. Of the total $266 million impairment charge for 2009, approximately $244 million related to held and used assets as of December 31, 2009, and $22 million is included in discontinued operations and is related to assets sold during 2009. We believe that most of the assets to be sold, which are classified as “Real Estate Investments - Net” on the Consolidated Balance Sheets, do not meet the held for sale and discontinued operations criteria as of December 31, 2009 because of the uncertainties related to the current market conditions and obtaining necessary approvals, we cannot assert that a sale of these properties within the upcoming year is probable. We recorded pre-tax impairment charges in 2008 of approximately $53 million or $32 million after income taxes. The detail of the impairment charge is as follows (dollars in millions, and before income taxes):
We estimate the fair value of our real estate assets primarily based on either the future cash flows that we estimate will be generated by each asset discounted at a rate we believe market participants would use, on independent appraisals, or other market information, including comparison to comparable properties. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific to each project and may vary among projects. The weighted average discount rates we used to estimate fair values during 2009 ranged from 11% to 29%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could differ from those estimates.
SunCor also recorded in 2009 $8 million of pretax severance and other charges relating to these actions. Pinnacle West does not expect that any of the impairment charges will result in future cash expenditures, other than immaterial disposition costs.
See Notes 5 and 6 for a discussion of SunCor’s debt and liquidity matters, and the impact of impairment charges on the SunCor Secured Revolver.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.
February 19, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2009 and 2008, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2009 and 2008and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 19, 2010
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
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’ 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 the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
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 period that are included in accrued taxes and unrecognized tax benefits on the Balance Sheets (dollars in thousands):
Included in both balances of unrecognized tax benefits at December 31, 2009 and 2008 were approximately $15 million of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2005 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 before 1999.
Within the next 12 months, it is reasonably possible that the Company will reach a settlement with the IRS with regard to the examination of tax returns for years ended December 31, 2005 through 2007. As a result of these anticipated settlements, and the expiration of certain statutes of limitations, the Company believes that it is reasonably possible that unrecognized tax benefits could be reduced by an amount up to $70 million.
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 Statement of Income related to unrecognized tax benefits was a pre-tax expense of $2 million for 2009 and a pre-tax benefit of $51 million for 2008.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was $8 million as of December 31, 2009 and $5 million as of December 31, 2008. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2009, we have recognized $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of APS’ 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.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following chart compares APS’ 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):
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars in thousands):
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2009 and 2008 is as follows (dollars in thousands):
S-3. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for 2009, 2008 and 2007 (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).
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)
(a)
Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.
(b)
In 2009, this is primarily the income tax benefit related to SunCor’s real estate impairment charges.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
(a)
Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2009. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2009. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) Management’s Annual Reports on Internal Control Over Financial Reporting
Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 81 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 150 of this report.
(c) Attestation Reports of the Registered Public Accounting Firm
Reference is made to “Report of Independent Registered Public Accounting Firm” on page 82 of this report and “Report of Independent Registered Public Accounting Firm” on page 151 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.
(d) Changes In Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2009 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE OF PINNACLE WEST
Reference is hereby made to “Information About Our Board and Corporate Governance,” “Proposal 1 - Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 19, 2010 (the “2010 Proxy Statement”) and to the “Executive Officers of Pinnacle West” section in Part I of this report.
Pinnacle West has adopted a Code of Ethics for Financial Executives that applies to financial executives including Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller, Treasurer, and persons holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Executives is posted on Pinnacle West’s website at www.pinnaclewest.com. Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Executives by posting such information on Pinnacle West’s website.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Director Compensation,” “Report of the Human Resources Committee,” “Executive Compensation,” “Overall Compensation Program” and “HR Committee Interlocks and Insider Participation” in the 2010 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” in the 2010 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2009 with respect to our compensation plans and individual compensation arrangements under which our equity securities are authorized for issuance.
EQUITY COMPENSATION PLAN INFORMATION
This amount includes shares subject to outstanding options as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.
The weighted average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.
Awards can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, dividend equivalents, and restricted stock units.
Equity Compensation Plans Approved By Security Holders
Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were approved by our shareholders: (a) the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no new stock awards may be granted; (b) the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the “2002 Plan”), under which no new stock awards may be granted; and (c) the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), which was approved by our shareholders at our 2007 annual meeting of shareholders. Although we cannot issue additional awards under the 2002 Plan, shares subject to outstanding awards under the 2002 Plan that expire or are cancelled or terminated will be available for issuance under the 2007 Plan. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
The Company does not have any equity compensation plans under which shares can still be issued that have not been approved by shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the 2010 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
Reference is hereby made to “Proposal 3 - Ratification of the Selection of Deloitte & Touche LLP as Independent Accountants of the Company - Audit Fees and - Pre-Approval Policies” in the 2010 Proxy Statement.
APS
The following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:
(1)
The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.
(2)
The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for an International Financial Reporting Standards Assessment for work performed in 2009 and employee benefit plan audits for work performed in 2008 and 2009.
(3)
The aggregate fees billed primarily for tax compliance and tax planning.
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ registered public accounting firm. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
3.1
Pinnacle West
Articles of Incorporation, restated as of May 21, 2008
3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-7-08
3.2
Pinnacle West
Pinnacle West Capital Corporation Bylaws, amended as of January 21, 2009
3.2 to Pinnacle West/APS December 31, 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-20-09
3.3
APS
Articles of Incorporation, restated as of May 25, 1988
4.2 to APS’ Form 18 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473
9-29-93
3.4
APS
Arizona Public Service Company Bylaws, amended as of December 16,
3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473
2-20-09
4.1
Pinnacle West
Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value
4.12 to Pinnacle West April 29, 2005 Form 8-K Report, File No. 1-8962
5-2-05
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
4.2
Pinnacle West
APS
Indenture dated as of January 1, 1995 among APS and The Bank of New York Mellon, as Trustee
4.6 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473
1-11-95
4.2a
Pinnacle West
APS
First Supplemental Indenture dated as of January 1, 1995
4.4 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473
1-11-95
4.3
Pinnacle West
APS
Indenture dated as of November 15, 1996 between APS and The Bank of New York, as Trustee
4.5 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473
11-22-96
4.3a
Pinnacle West
APS
First Supplemental Indenture dated as of November 15,
4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473
11-22-96
4.3b
Pinnacle West
APS
Second Supplemental Indenture dated as of April 1, 1997
4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473
4-9-97
4.3c
Pinnacle West
APS
Third Supplemental Indenture dated as of November 1, 2002
10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962
5-15-03
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
4.4
Pinnacle West
Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Unsecured Debt Securities
4.1 to Pinnacle West’s Registration Statement No. 333-52476
12-21-00
4.5
Pinnacle West
Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Subordinated Unsecured Debt Securities
4.2 to Pinnacle West’s Registration Statement No. 333-52476
12-21-00
4.6
Pinnacle West
APS
Indenture dated as of January 15, 1998 between APS and The Bank of New York Mellon Trust Company N.A. (successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank), as Trustee
4.10 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473
1-16-98
4.6a
Pinnacle West
APS
Fifth Supplemental Indenture dated as of October 1, 2001
4.1 to APS’ September 30, 2001 Form 10-Q, File No. 1-4473
11-6-01
4.6b
Pinnacle West
APS
Sixth Supplemental Indenture dated as of March 1, 2002
4.1 to APS’ Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report, File No. 1-4473
2-28-02
4.6c
Pinnacle West
APS
Seventh Supplemental Indenture dated as of May 1, 2003
4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473
5-9-03
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
4.6d
Pinnacle West
APS
Eighth Supplemental Indenture dated as of June 15, 2004
4.1 to APS’ Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473
6-28-04
4.6e
Pinnacle West
APS
Ninth Supplemental Indenture dated as of August 15, 2005
4.1 to APS’ Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473
8-22-05
4.6f
APS
Tenth Supplemental Indenture dated as of August 1, 2006
4.1 to APS’ July 31, 2006 Form 8-K Report, File No. 1-4473
8-3-06
4.6g
Pinnacle West
APS
Eleventh Supplemental Indenture dated as of February 26,
4.1 to APS’ February 23, 2009 Form 8-K Report, File Nos. 1-8962 and 1-4473
2-25-09
4.7
Pinnacle West
Amended and Restated Rights Agreement, dated as of March 26, 1999, between Pinnacle West Capital Corporation and BankBoston, N.A., as Rights Agent, including (i) as Exhibit A thereto the form of Amended Certificate of Designation of Series A Participating Preferred Stock of Pinnacle West Capital Corporation, (ii) as Exhibit B thereto the form of Rights Certificate and (iii) as Exhibit C thereto the Summary of Right to Purchase Preferred Shares
4.1 to Pinnacle West’s March 22, 1999 Form 8-K Report, File No. 1-8962
4-19-99
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
4.7a
Pinnacle West
Amendment to Rights Agreement, effective as of January 1, 2002
4.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
4.8
Pinnacle West
Second Amended and Restated Investor’s Advantage Plan dated as of June 23, 2004
4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962
8-9-04
4.8a
Pinnacle West
Third Amended and Restated Investors Advantage Plan dated as of November 25, 2008
4.1 to Pinnacle West’s Form 18 Registration Statement No. 333-155641
11-25-08
4.9
Pinnacle West
Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets
4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962
3-30-88
4.9a
Pinnacle West
APS
Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’ total assets
4.1 to APS’ 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.1.1
Pinnacle West
APS
Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee
10.2 to APS’ September 30, 1991 Form 10-Q Report, File No. 1-4473
11-14-91
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.1.1a
Pinnacle West
APS
Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994
10.1 to APS’ 1994 Form 10- K Report, File No. 1-4473
3-30-95
10.1.1b
Pinnacle West
APS
Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994
10.2 to APS’ 1994 Form 10-K Report, File No. 1-4473
3-30-95
10.1.1c
Pinnacle West
APS
Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1,
10.4 to APS’ 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.1.1d
Pinnacle West
APS
Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1,
10.6 to APS’ 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.1.1e
Pinnacle West
APS
Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002
10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.1f
Pinnacle West
APS
Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002
10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.1g
Pinnacle West
APS
Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003
10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.1.1h
Pinnacle West
APS
Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003
10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
10.1.1i
Pinnacle West
APS
Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1,
10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-9-07
10.1.1j
Pinnacle West
APS
Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1,
10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and
5-9-07
10.1.2
Pinnacle West
APS
Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2
10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962
3-26-92
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.1.2a
Pinnacle West
APS
First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992
10.2 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
10.1.2b
Pinnacle West
APS
Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994
10.3 to APS’ 1994 Form 10-K Report, File No. 1-4473
3-30-95
10.1.2c
Pinnacle West
APS
Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 20, 1996
10.1 to APS’ June 30, 1996 Form 10-Q Report, File No. 1-4473
8-9-96
10.1.2d
Pinnacle West
APS
Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of December 16, 1996
APS 10.5 to APS’ 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.1.2e
Pinnacle West
APS
Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000
10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.2f
Pinnacle West
APS
Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002
10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.1.2g
Pinnacle West
APS
Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003
10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
10.1.2h
Pinnacle West
APS
Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of April 1, 2007
10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962
2-27-08
10.2.1b
Pinnacle West
APS
Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987 respectively
10.4 to APS’ 1988 Form 10-K Report, File No. 1-4473
3-8-89
10.2.1ab
Pinnacle West
APS
Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993
10.3A to APS’ 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.2.1bb
Pinnacle West
APS
Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993
10.2 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473
11-10-94
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.2.1cb
Pinnacle West
APS
Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997
10.3A to APS’ 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.2.1db
Pinnacle West
APS
Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001
10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962
3-14-01
10.2.2b
Pinnacle West
APS
Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986
10.1 to APS’ June 30, 1986 Form 10-Q Report, File No. 1-4473
8-13-86
10.2.2ab
Pinnacle West
APS
Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993
10.2A to APS’ 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.2.2bb
Pinnacle West
APS
Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993
10.1 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473
11-10-94
10.2.2cb
Pinnacle West
APS
Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999
10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.2.3b
Pinnacle West
APS
Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1,
10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.3ab
Pinnacle West
APS
First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans
10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.4b
Pinnacle West
APS
Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996
10.10A to APS’ 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.2.4ab
Pinnacle West
APS
First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan
10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.2.4bb
Pinnacle West
APS
Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan
10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.4cb
Pinnacle West
APS
Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002
10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962
5-15-03
10.2.4db
Pinnacle West
APS
Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003
10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.2.5b
Pinnacle West
APS
Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended
10.3A to Pinnacle West 2002 Form 10-K Report, File No. 1-8962
3-31-03
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.2.6b
Pinnacle West
APS
Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.2.6 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-20-09
10.2.6ab
Pinnacle West
APS
First Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.3.1b
Pinnacle West
APS
Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003
10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
10.3.1ab
Pinnacle West
APS
Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003
10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.3.2b
Pinnacle West
APS
Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005
10.3.2 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-20-09
10.4.1b
Pinnacle West
APS
Letter Agreement dated December 21, 1993, between APS and William L. Stewart
10.6A to APS’ 1994 Form 10-K Report, File No. 1-4473
3-30-95
10.4.2b
Pinnacle West
APS
Letter Agreement dated August 16, 1996 between APS and William L. Stewart
10.8 to APS’ 1996 Form 10-K Report, File No. 1-4473
3-28-97
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.4.3b
Pinnacle West
APS
Letter Agreement dated October 3, 1997 between APS and William L. Stewart
10.2 to APS’ September 30, 1997 Form 10-Q Report, File No. 1-4473
11-12-97
10.4.4b
Pinnacle West
APS
Letter Agreement dated December 13, 1999 between APS and William L. Stewart
10.9A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.4.4ab
Pinnacle West
APS
Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart
10.1 to Pinnacle West’s June 30, 2002 Form 10-Q Report, File No. 1-8962
8-13-02
10.4.5b
Pinnacle West
APS
Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler
10.4A to Pinnacle West’s 2002 Form 10-K Report, File No. 1-8962
3-31-03
10.4.6b
APS
Letter Agreement dated December 20, 2006 between APS and Randall K. Edington
10.78 to Pinnacle West/APS 2006 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-28-07
10.4.7b
APS
Letter Agreement dated July 22, 2008 between APS and Randall K. Edington
10.3 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473
8-07-08
10.4.8b
Pinnacle West
APS
Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield
10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-07-08
10.4.9b
APS
Description of 2008 Palo Verde Specific Compensation Opportunity for Randall K. Edington
10.7 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473
8-07-08
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.4.10b
APS
Supplemental Agreement dated December 26, 2008 between APS and Randall K. Edington
10.4.10 to Pinnacle West/APS 2008 Form 10-K Report, File No. 1-4473
2-20-09
10.4.11 b
APS
Description of 2009 Palo Verde Specific Compensation Opportunity for Randall K. Edington
10.2 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File No. 1-4473
5-5-09
10.4.12 b
Pinnacle West
APS
Career Recognition Award Agreement dated April 14, 2009 between Pinnacle West Capital Corporation and William J. Post
10.1 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-5-09
10.4.13b
APS
Description of 2010 Palo Verde Specific Compensation Opportunity for Randall K. Edington
10.5.1bd
Pinnacle West
APS
Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries
10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.5.1abd
Pinnacle West
APS
Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
11-5-07
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.5.2bd
Pinnacle West
APS
Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
11-5-07
10.5.3bd
Pinnacle West
APS
Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.6.1b
Pinnacle West
APS
Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan, effective as of March 23, 1994
Appendix A to the Proxy Statement for the Plan Report for Pinnacle West’s 1994 Annual Meeting of Shareholders, File No. 1-8962
4-15-94
10.6.1ab
Pinnacle West
APS
First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan
10.12A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.6.2b
Pinnacle West
APS
Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.5A to Pinnacle West’s 2002 Form 10-K Report
3-31-03
10.6.2abd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473
12-15-05
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.6.2bbd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473
2-1-06
10.6.2cd
Pinnacle West
APS
Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.6.2dbd
Pinnacle West
APS
Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.99 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.6.2ebd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.6.2fbd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-5-09
10.6.3b
Pinnacle West
Pinnacle West Capital Corporation 2000 Director Equity Plan
99.1 to Pinnacle West’s Registration Statement on Form S-8 (No. 333-40796), File No. 1-8962)
7-3-00
10.6.4b
Pinnacle West
Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962
4-20-07
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.6.4ab
Pinnacle West
First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962
4-20-07
10.6.4bb
Pinnacle West
Description of Annual Stock Grants to Non-Employee Directors
10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962
11-5-07
10.6.4cb
Pinnacle West
Description of Stock Grant to W. Douglas Parker
10.2 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962
11-5-07
10.6.4db
Pinnacle West
Description of Annual Stock Grants to Non-Employee Directors
10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962
8-07-08
10.6.5bd
Pinnacle West
APS
Summary of 2010 CEO Variable Incentive Plan and Officer Variable Incentive Plan
10.7.1
Pinnacle West
APS
Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant
5.01 to APS’ Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.1a
Pinnacle West
APS
Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant
5.02 to APS’ Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.1b
Pinnacle West
APS
Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985
10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962
7-25-85
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.7.2
Pinnacle West
APS
Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site
5.04 to APS’ Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.2a
Pinnacle West
APS
Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985
10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962
7-25-85
10.7.3
Pinnacle West
APS
Application and Grant of Arizona Public Service Company rights- of-way and easements, Four Corners Plant Site
5.05 to APS’ Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.3a
Pinnacle West
APS
Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985
10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962
7-25-85
10.7.4
Pinnacle West
APS
Four Corners Project Co-Tenancy Agreement Amendment No. 6
10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962
3-14-01
10.8.1
Pinnacle West
APS
Indenture of Lease, Navajo Units 1, 2, and 3
5(g) to APS’ Form S-7 Registration Statement, File No. 2-36505
3-23-70
10.8.2
Pinnacle West
APS
Application of Grant of rights-of-way and easements, Navajo Plant
5(h) to APS Form S-7 Registration Statement, File No. 2-36505
3-23-70
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.8.3
Pinnacle West
APS
Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant
5(l) to APS’ Form S-7 Registration Statement, File No. 2-394442
3-16-71
10.8.4
Pinnacle West
APS
Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998
10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.8.5
Pinnacle West
APS
Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971
10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.9.1
Pinnacle West
APS
Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto
10. 1 to APS’ 1988 Form 10-K Report, File No. 1-4473
3-8-89
10.9.1a
Pinnacle West
APS
Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
10.1 to APS’ March 31, 1991 Form 10-Q Report, File No. 1-4473
5-15-91
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.9.1b
Pinnacle West
APS
Amendment No. 14 to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962
8-14-00
10.10.1
Pinnacle West
APS
Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18,
10.1 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473
8-8-91
10.10.2
Pinnacle West
APS
Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8,
10.2 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473
8-8-91
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.10.2a
Pinnacle West
APS
Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS
10.3 to APS’ 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.10.3
Pinnacle West
APS
Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995
10.4 to APS’ 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.10.4
Pinnacle West
APS
Contract among PacifiCorp, APS and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995
10.5 to APS’ 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.10.5
Pinnacle West
APS
Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994
10.6 to APS’ 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.11.1
Pinnacle West
APS
Amended and Restated Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, as Administrative Agent and Issuing Bank, dated as of July 22, 2002
10.100 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.11.2
Pinnacle West
APS
Three-Year Credit Agreement dated as of May 21, 2004 between APS as Borrower, and the banks, financial institutions and other institutional lenders and initial issuing banks listed on the signature pages thereof
10.101 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.11.3
Pinnacle West
APS
Three-Year Credit Agreement dated as of February 12, 2010 between APS, as Borrower, Wells Fargo Bank, National Association, as Agent, and the lenders and other parties thereto
10.11.4
Pinnacle West
$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28,
10.96 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962
3-13-06
10.11.5
Pinnacle West
Three-Year Credit Agreement dated as of February 12, 2010 among Pinnacle West Capital Corporation, as Borrower, Bank of America, N.A, as Agent, and the lenders and other parties thereto
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.11.5a
Pinnacle West
First Amendment to Amended and Restated Credit Agreement, dated as of May 15, 2006, supplementing and amending the Amended and Restated Credit Agreement, dated as of December 9, 2005, among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Agent and the other parties thereto
10.1 to Pinnacle West’s June 30, 2006 Form 10-Q Report, File No. 1-8962
8-8-06
10.11.6
Pinnacle West
APS
Credit Agreement dated as of October 19, 2004 among Pinnacle West, other lenders, and JPMorgan Chase Bank, as Administrative Agent
10.1 to Pinnacle West’s September 30, 2004 Form 10-Q Report, File No. 1-8962
11-8-04
10.11.7
APS
$500,000,000 Five-Year Credit Agreement dated as of September 28, 2006 among Arizona Public Service Company as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, The Bank of New York as Syndication Agent and Issuing Bank and the other parties thereto
10.1 to APS’ September 2006 Form 10-Q Report, File No. 1-4473
11-8-06
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.11.8
Pinnacle West
APS
Amended and Restated Reimbursement Agreement among Arizona Public Service Company, The Banks party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and Barclays Bank PLC, as Syndication Agent, dated as of May 19,
99.6 to PinnacleWest/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-9-05
10.12.1c
Pinnacle West
APS
Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
4.3 to APS’ Form 18 Registration Statement, File No. 33-9480
10-24-86
10.12.1ac
Pinnacle West
APS
Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
10.5 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473
12-4-86
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.12.1bc
Pinnacle West
APS
Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.3 to APS’ 1988 Form 10-K Report, File No. 1-4473
3-8-89
10.12.1cc
Pinnacle West
APS
Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.3 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
10.12.2
Pinnacle West
APS
Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
10.1 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473
1-20-87
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.12.2a
Pinnacle West
APS
Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
4.13 to APS’ Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473
8-24-87
10.12.2b
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.4 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
10.13.1
Pinnacle West
APS
Agreement No. 13904 (Option and Purchase of Effluent) with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23,
10.3 to APS’ 1991 Form 10-K Report, File No. 1-4473
3-19-92
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.13.2
Pinnacle West
APS
Agreement between Pinnacle West Energy Corporation and Arizona Public Service Company for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th day of April, 2001
10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.3
Pinnacle West
APS
Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001
10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.4
Pinnacle West
APS
Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP
10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.5
Pinnacle West
APS
Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP
10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
10.13.6
Pinnacle West
APS
Agreement for the Sale and Purchase of Wastewater Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4,
10.4 to APS’ 1991 Form 10-K Report, File 1-4473
3-19-92
10.14.1
Pinnacle West
APS
Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP
10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386
3-13-85
10.15.1
Pinnacle West
APS
Territorial Agreement between APS and Salt River Project
10.1 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.2
Pinnacle West
APS
Power Coordination Agreement between APS and Salt River Project
10.2 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.3
Pinnacle West
APS
Memorandum of Agreement between APS and Salt River Project
10.3 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.3a
Pinnacle West
APS
Addendum to Memorandum of Agreement between APS and Salt River Project dated as of May 19, 1998
10.2 to APS’ May 19, 1998 Form 8-K Report, File No. 1-4473
6-26-98
12.1
Pinnacle West
Ratio of Earnings to Fixed Charges
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
12.2
APS
Ratio of Earnings to Fixed Charges
12.3
Pinnacle West
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
21.1
Pinnacle West
Subsidiaries of Pinnacle West
23.1
Pinnacle West
Consent of Deloitte & Touche LLP
23.2
APS
Consent of Deloitte & Touche LLP
31.1
Pinnacle West
Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2
Pinnacle West
Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3
APS
Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
31.4
APS
Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1
Pinnacle West
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
APS
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1
Pinnacle West
APS
Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee
4.2 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.1a
Pinnacle West
APS
Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee
4.3 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.2c
Pinnacle West
APS
Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
28.1 to APS’ September 30, 1992 Form 10-Q Report, File No. 1-4473
11-9-92
99.2ac
Pinnacle West
APS
Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
10.8 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473
12-4-86
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.2bc
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
28.4 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.3c
Pinnacle West
APS
Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
4.5 to APS’ Form 18 Registration Statement, File No. 33-9480
10-24-86
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.3ac
Pinnacle West
APS
Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
10.6 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473
12-4-86
99.3bc
Pinnacle West
APS
Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee
4.4 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.4c
Pinnacle West
APS
Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.3 to APS’ Form 18 Registration Statement, File No. 33-9480
10-24-86
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.4ac
Pinnacle West
APS
Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
10.10 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473
12-4-86
99.4bc
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.6 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.5
Pinnacle West
APS
Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein
28.2 to APS’ September 30, 1992 Form 10-Q Report, File No. 1-4473
11-9-92
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.5a
Pinnacle West
APS
Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein
28.20 to APS’ Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473
8-10-87
99.5b
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein
28.5 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.6
Pinnacle West
APS
Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
10.2 to APS’ November 18, 1986 Form 10-K Report, File No. 1-4473
1-20-87
99.6a
Pinnacle West
APS
Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
4.13 to APS’ Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473
8-24-87
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.6b
Pinnacle West
APS
Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee
4.5 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.7
Pinnacle West
APS
Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
10.5 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473
1-20-87
99.7a
Pinnacle West
APS
Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.7 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.8c
Pinnacle West
APS
Indemnity Agreement dated as of March 17, 1993 by APS
28.3 to APS’ 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
Date
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Filed
99.9
Pinnacle West
APS
Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank
28.20 to APS’ Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473
8-10-87
99.10
Pinnacle West
APS
Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules
10.2 to APS’ September 30, 1999 Form 10-Q Report, File No. 1-4473
11-15-99
99.11
Pinnacle West
Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005
99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-9-05
a
Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b
Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.
c
An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d
Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Date: February 19, 2010 /s/ Donald E. Brandt
(Donald E. Brandt,
Chairman of the Board of Directors, President and
Chief Executive Officer)
Power of Attorney
We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint James R. Hatfield and David P. Falck, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Donald E. Brandt
(Donald E. Brandt,
Chairman of the Board of Directors, President
and Chief Executive Officer)
Principal Executive Officer and Director
February 19, 2010
/s/ James R. Hatfield
(James R. Hatfield,
Senior Vice President and Chief Financial Officer)
Principal Financial Officer
February 19, 2010
/s/ Barbara M. Gomez
(Barbara M. Gomez,
Vice President, Controller and
Chief Accounting Officer, position at December 31, 2009)
Principal Accounting Officer
(position at December 31, 2009)
February 19, 2010
Signature
Title
Date
/s/ Edward N. Basha, Jr.
(Edward N. Basha, Jr.)
Director
February 19, 2010
/s/ Susan Clark-Johnson
(Susan Clark-Johnson)
Director
February 19, 2010
/s/ Denis A. Cortese
(Denis A. Cortese)
Director
February 19, 2010
/s/ Michael L. Gallagher
(Michael L. Gallagher)
Director
February 19, 2010
/s/ Pamela Grant
(Pamela Grant)
Director
February 19, 2010
/s/ Roy A. Herberger, Jr.
(Roy A. Herberger, Jr.)
Director
February 19, 2010
/s/ William S. Jamieson
(William S. Jamieson)
Director
February 19, 2010
/s/ Humberto S. Lopez
(Humberto S. Lopez)
Director
February 19, 2010
/s/ Kathryn L. Munro
(Kathryn L. Munro)
Director
February 19, 2010
/s/ Bruce J. Nordstrom
(Bruce J. Nordstrom)
Director
February 19, 2010
/s/ W. Douglas Parker
(W. Douglas Parker)
Director
February 19, 2010
/s/ William J. Post
(William J. Post)
Director
February 19, 2010
/s/ William L. Stewart
(William L. Stewart)
Director
February 19, 2010
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Date: February 19, 2010 /s/ Donald E. Brandt
(Donald E. Brandt,
Chairman of the Board of Directors and
Chief Executive Officer)
Power of Attorney
We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint James R. Hatfield and David P. Falck, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Donald E. Brandt
(Donald E. Brandt,
Chairman of the Board of Directors and
Chief Executive Officer)
Principal Executive Officer and Director
February 19, 2010
/s/ James R. Hatfield
(James R. Hatfield,
Senior Vice President and Chief Financial Officer)
Principal Financial Officer and Principal Accounting Officer
February 19, 2010
Signature
Title
Date
/s/ Edward N. Basha, Jr.
(Edward N. Basha, Jr.)
Director
February 19, 2010
/s/ Susan Clark-Johnson
(Susan Clark-Johnson)
Director
February 19, 2010
/s/ Denis A. Cortese
(Denis A. Cortese)
Director
February 19, 2010
/s/ Michael L. Gallagher
(Michael L. Gallagher)
Director
February 19, 2010
/s/ Pamela Grant
(Pamela Grant)
Director
February 19, 2010
/s/ Roy A. Herberger, Jr.
(Roy A. Herberger, Jr.)
Director
February 19, 2010
/s/ William S. Jamieson
(William S. Jamieson)
Director
February 19, 2010
/s/ Humberto S. Lopez
(Humberto S. Lopez)
Director
February 19, 2010
/s/ Kathryn L. Munro
(Kathryn L. Munro)
Director
February 19, 2010
/s/ Bruce J. Nordstrom
(Bruce J. Nordstrom)
Director
February 19, 2010
/s/ W. Douglas Parker
(W. Douglas Parker)
Director
February 19, 2010
/s/ William J. Post
(William J. Post)
Director
February 19, 2010
/s/ William L. Stewart
(William L. Stewart)
Director
February 19, 2010