PINNACLE WEST CAPITAL CORP
ITEM 1. BUSINESS
Pinnacle West
Pinnacle West is a holding company that conducts business through its subsidiaries. We derive essentially all 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 remaining first-tier subsidiaries are SunCor and El Dorado. Additional information related to these businesses is provided later in this report.
Our reportable business segment is 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.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
APS currently provides electric service to approximately 1.1 million customers. We own or lease approximately 6,340 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity, including a variety of agreements for the purchase of renewable energy. During 2011, no single purchaser or user of energy accounted for more than 1.4% of our electric revenues.
The following map shows APS’s 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 purchased power agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’s sources of energy by fuel type during 2011 were as follows:
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 791 MW. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. 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.
On November 8, 2010, APS and SCE entered into an asset purchase agreement providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. If consummated, APS would acquire 739 MW from SCE. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is conditioned upon the receipt of regulatory approvals from the ACC, the California Public Utilities Commission and the FERC, the execution of a new coal supply contract, expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions.
APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the term of the Four Corners leasehold
interest from 2016 to 2041. Execution by the Navajo Nation of the lease amendments is a condition to closing of the purchase by APS of SCE’s interests in Four Corners. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which became effective in March 2011. The effectiveness of the amendments also requires the approval of the U.S. Department of the Interior (“DOI”), as does a related Federal rights-of-way grant, which the Four Corners participants will pursue. A Federal environmental review is underway as part of the DOI review process.
APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. These events would change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW.
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 2019. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.
These coal plants face uncertainties, including those 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 - Overview and Capital Expenditures” in Item 7 for developments impacting these coal facilities. See Note 11 for information regarding APS’s 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 ownership and leasehold interest in that Unit. APS has a total entitlement from Palo Verde of 1,146 MW.
Palo Verde Leases - In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back about 42% of its share of Palo Verde Unit 2 and certain common facilities. In accordance with the VIE accounting guidance, APS consolidates the lessor trust entities for financial
reporting purposes, and eliminates lease accounting for these transactions. The agreements have terms of 29.5 years (expiring at the end of 2015) and 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 lessor trusts 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 Note 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. 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. On April 21, 2011, the NRC approved APS’s application for renewed operating licenses for the Palo Verde Units, extending the licenses for Units 1, 2 and 3 to June 2045, April 2046, and November 2047, respectively.
Palo Verde Fuel Cycle - The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The fuel cycle for Palo Verde is comprised of the following stages:
· mining and milling of uranium ore to produce uranium concentrates;
· conversion of uranium concentrates to uranium hexafluoride;
· enrichment of uranium hexafluoride;
· fabrication of fuel assemblies;
· utilization of fuel assemblies in reactors; and
· storage and disposal of spent nuclear fuel.
The Palo Verde participants have contracted for 95% of Palo Verde’s requirements for uranium concentrates through 2015, 90% of its requirements in 2016 - 2017 and 80% of its requirements in 2018. The participants have also contracted for all of Palo Verde’s conversion services through 2015 and 95% of its requirements in 2016 - 2018, all of Palo Verde’s enrichment services through 2020 and all of Palo Verde’s fuel assembly fabrication services through 2016.
Spent Nuclear Fuel and Waste Disposal - The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to accept, transport, and dispose of spent nuclear fuel and high level waste generated by the nation’s nuclear power plants by 1998. The DOE’s obligations are reflected in a Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (“Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting Palo Verde’s spent nuclear fuel by 1998, and APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE’s breach of the Palo Verde Standard Contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.2 million in damages to the Palo Verde participants for costs incurred through December 2006.
The DOE had planned to meet its NWPA and Standard Contract disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In June 2008, DOE submitted its application to the NRC to authorize construction of the Yucca Mountain repository. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several
interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application. None of these lawsuits have been conclusively decided by the courts.
On January 26, 2012, the Blue Ribbon Commission on America’s Nuclear Future (the “Blue Ribbon Commission”) made recommendations on managing the back end of the nuclear fuel cycle. The Commission was established in early 2010 at the direction of President Obama. The President’s directive was based on his assessment that the nation’s approach to managing used nuclear fuel, primarily through the repository at Yucca Mountain, has proven to be ineffective.
The Blue Ribbon Commission’s report recommended a strategy with several key elements including: a new, consent-based approach to siting future nuclear waste management facilities; a new organization dedicated solely to implementing the waste management program; access to the funds nuclear utility ratepayers are providing for the purpose of nuclear waste management; prompt efforts to develop geologic disposal facilities, consolidated storage facilities and to prepare for the eventual large-scale transport of spent nuclear fuel and high-level waste to consolidated storage and disposal facilities. We are monitoring this matter, but cannot predict the proposed timing for implementation of the recommended strategy.
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, which ends in December 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, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent 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.
In addition to the spent fuel stored at Palo Verde’s on-site ISFSI, Palo Verde also generates certain types of low level radioactive waste that are stored on-site. Currently, the Class B and Class C waste (the higher radioactivity of the low level wastes) is stored on-site since industry access to a disposal site was eliminated several years ago. The NRC is considering regulations that would allow the industry to eliminate much of this waste by blending it with lower level Class A waste so that it can be disposed of at a facility such as the one Palo Verde utilizes in Utah.
Nuclear Decommissioning Costs - APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning 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’s ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge (paid by all retail customers taking service from the APS system). See Note 23 for additional information about APS’s 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.
Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry - On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Following these events, the NRC Commissioners launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force’s recommendations.
On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.
Until further action is taken by the NRC as a result of this event, we cannot predict any financial or operational impacts on Palo Verde or APS.
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 only power plant, Douglas, located in the town of Douglas, Arizona. APS owns and operates each of these plants with the exception of one oil only combustion turbine unit and one oil and gas 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’s hedging program. APS has long-term gas transportation agreements with three different companies, some of which are effective through 2024. Fuel oil is acquired under short-term purchases delivered primarily to West Phoenix, where it is distributed to APS’s other oil power plants by truck.
Solar Facilities
To date, APS has begun operation of 50 MW of utility scale solar through its AZ Sun Program, discussed below. These facilities are owned by APS and are located in multiple locations throughout Arizona.
Additionally, APS owns and operates more than forty small solar systems around the state. Together they have the capacity to produce about 5 MW of renewable energy. This fleet of solar systems includes a 3 MW facility located at the Prescott Airport, a 1 MW facility located at APS’s Saguaro power plant and 1 MW of small solar in various locations across Arizona. APS is in the final stages of developing solar photovoltaic distributed energy systems installed as part of the Community Power Project in Flagstaff, Arizona. The Community Power Project, approved by the ACC on April 1, 2010, is a pilot program through which APS will own, operate and receive energy from approximately 1.5 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona.
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’s 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.
Purchased Power Capacity - APS’s 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.
(a) The capacity under this agreement varies by month, with a maximum capacity of 104 MW.
(b) Up to 60 MW of capacity is available; however, the amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually.
(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 phases over the first three years to reach the 100 MW level by the summer of 2012.
(e) Renewable energy purchased power agreements are described in detail below under “Current and Future Resources - Renewable Energy Standard - Renewable Energy Portfolio.”
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’s 2011 peak one-hour demand on its electric system was recorded on August 24, 2011 at 7,087 MW, compared to the 2010 peak of 6,936 MW recorded on July 15, 2010. APS’s operable generating capacity, together with purchased power capacity, resulted in an actual reserve margin at the time of the 2011 peak demand of 28.7%. 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.
Future Resources and Resource Plan
Under the ACC’s resource planning rule, APS will file by April 1st of each even year its resource plans for the next fifteen-year period. The first resource plan filing will be due by April 1, 2012. The rule requires the ACC to issue an order with its acknowledgment of APS’s resource plan within approximately ten months following its submittal. The ACC’s acknowledgment of APS’s resource plan will consider factors such as the total cost of electric energy services, demand management, analysis of supply-side options, system reliability and risk management.
Renewable Energy Standard
In 2006, the ACC adopted the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement is 3.5% of retail electric sales in 2012 and increases annually until it reaches 15% in 2025. In APS’s 2009 retail rate case settlement agreement, APS committed to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be 3,400 GWh, or approximately 10% of retail sales, by year-end 2015, which is double the existing RES target of 5% for that year. A component of the 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 RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed energy requirement is 30% of the overall RES requirement of 3.5% in 2012. The following table summarizes these requirement standards and their timing:
Renewable Energy Portfolio. To date, APS has a diverse portfolio of existing and planned renewable resources totaling 946 MW, including wind, geothermal, solar, biomass and biogas. Of this portfolio, 423 MW are currently in operation and 523 MW are under contract for development or are under construction. Renewable resources in operation include 55 MW of facilities owned by APS, 232 MW of long-term purchased power agreements, and an estimated 136 MW of customer-sited, third-party owned distributed energy resources.
APS’s strategy to achieve its RES requirements includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS. APS continues to develop owned solar resources through the AZ Sun Program. The AZ Sun Program allows APS to own up to 200 MW of solar photovoltaic power plants across Arizona by investing up to $975 million through 2015. Under this program to date, APS has executed contracts for the development of 83 MW of new solar generation, representing an investment commitment of approximately $375 million. See Note 3 for additional details about the AZ Sun Program, including the related cost recovery.
The following table summarizes APS’s renewable energy sources currently in operation and under development. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.
(a) Subject to approval by the United States Department of Defense.
(b) Under the AZ Sun Program, 117 MW remains to be contracted.
(c) Represents contracted capacity.
(d) Details of these agreements have not yet been publicly announced.
(e) Distributed generation is produced in DC and is converted to AC for reporting purposes.
(f) Reflects Community Power Project.
(g) Achieved through incentive-based programs. Includes resources with production-based incentives that have terms of 10-20 years.
(h) Agreement ramps up to 40 MW over three years.
Demand Side Management
In recent years, Arizona regulators have placed an increased focus on energy efficiency and other 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 its Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. This standard was adopted and became effective on January 1, 2011. This ambitious standard will likely impact Arizona’s future energy resource needs. (See Note 3 for energy efficiency and other demand side management obligations resulting from the settlement agreement related to APS’s 2008 retail rate case.)
Economic Stimulus Projects
Through the American Recovery and Reinvestment Act of 2009 (“ARRA”), the Federal government made a number of programs available for utilities to develop renewable resources, improve reliability and create jobs by using economic stimulus funding. Certain programs are also available through the State of Arizona.
APS has two active awards with the DOE. The first is a $3 million high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona. Second, APS is a sub-recipient under an approximately $4 million ARRA award received through the State of Arizona for the implementation of various distributed energy and energy efficiency programs in Arizona. DOE funding for these awards will continue to be contingent upon APS meeting certain project milestones, including DOE-established budget parameters.
Competitive Environment and Regulatory Oversight
Retail
The ACC regulates APS’s retail electric rates and its issuance of securities. The ACC must also approve any significant transfer or encumbrance of APS’s 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’s 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’s customers. In 2000, the 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. In 2008, 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 was issued on August 12, 2010. The report stated that additional analysis, discussion and study of all aspects of the issue are required in order to perform a proper evaluation. While the report did not make any specific recommendations other than to conduct more workshops, the report did state that the current retail electric competition rules are incomplete and in need of modification.
On April 14, 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC. A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model. Use of such products by customers within our territory would result in some level of competition. APS cannot predict when, and the extent to which, additional electric service providers will enter or re-enter APS’s service territory.
Wholesale
The FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’s transmission rates.) During 2011, approximately 4.8% of APS’s electric operating revenues resulted from such sales and services. APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS hedges both electricity and fuels. The majority of these activities are undertaken to mitigate risk in APS’s portfolio.
Environmental Matters
Climate Change
Legislative Initiatives. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions. There have been no attempts by the 112th Congress to pass legislation that would regulate greenhouse gas emissions. With Congress’s focus on the economy, it is unclear when it will again consider a climate change bill. In the event climate change legislation is ultimately passed, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is enacted and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed emissions; whether any 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.
In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation and no proposed agency rule regulating greenhouse gases in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address greenhouse gas emissions. In October 2011, the California Air Resources Board approved final regulations that will establish a state-wide cap on greenhouse gas emissions beginning on January 1, 2013 and will establish a greenhouse gas allowance trading program under that cap. The first phase of the program, which will apply to, among other entities, electric utilities and importers of electricity, is scheduled to commence on January 1, 2013. In addition, in 2010 the New Mexico Environmental Improvement Board enacted a greenhouse gas cap-and-trade program, which was repealed on February 6, 2012, and an emissions cap, which is scheduled to become effective in 2013 but is undergoing further review.
We are monitoring Arizona regulatory activities 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. In particular, SCE, a participant in Four Corners, has indicated that SB 1368 may prohibit it from making emission control expenditures at the plant. (See “Energy Sources and Resource Planning - Generation Facilities - Coal Fueled Generating Facilities - Four Corners” above for details of the pending sale of SCE’s interest in Four Corners to APS.)
Regulatory Initiatives. In December 2009, the EPA 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. As a result of this “endangerment finding,” the EPA determined that the Clean Air Act required new regulatory requirements for new and modified major greenhouse gas emitting sources, including power plants. On June 3, 2010, the EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new greenhouse gas emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review” is a pre-construction permitting program under the Clean Air Act that requires analysis of pollution controls prior to building a new stationary source or making major modifications to an existing stationary source. The tailoring rule became effective on August 2, 2010 and it became applicable to power plants on January 2, 2011. Several groups have filed lawsuits challenging the EPA’s endangerment finding and the tailoring rule, and that litigation
continues. At the present time, we cannot predict whether the parties challenging the endangerment finding or the tailoring rule will be successful.
APS does not expect the tailoring rule to have a significant impact on its current operations. The rule will require APS to consider the impact of greenhouse gas emissions as part of its traditional New Source Review analysis for new sources and major modifications to existing plants.
On December 30, 2010, pursuant to its authority under the Clean Air Act, the EPA finalized a greenhouse gas Federal Implementation Plan (“FIP”) for Arizona relating to pre-construction permits for construction of new sources or major modifications of existing sources. As a result of this action, effective January 2, 2011, the EPA assumed responsibility for acting on permit applications for only the greenhouse gas portion of such pre-construction permits. State permitting authorities will continue to retain responsibility for the remaining parts of pre-construction permits that are unrelated to emissions of greenhouse gasses. To the extent Arizona seeks and receives from the EPA a delegation of permitting authority for greenhouse gas emissions, the state will assume responsibility for issuing both the greenhouse gas and non-greenhouse gas portions of pre-construction permits. The greenhouse gas FIP will remain in place until such time as the EPA approves a State Implementation Plan (“SIP”) that applies pre-construction permit requirements to greenhouse gas-emitting stationary sources in Arizona. APS does not expect the greenhouse gas FIP to have a significant impact on its current operations.
Pursuant to its authority under the Clean Air Act, the EPA has also drafted proposed New Source Performance Standards (“NSPS”) for greenhouse gas emissions from certain new and modified electric generating units. The proposed standards are currently under review at the White House Office of Management and Budget, and a final rule is expected in 2012. In addition, it is possible that the EPA will propose standards setting federal emission guidelines for existing electric generating facilities in 2012. The NSPS for greenhouse gas emissions are expected to apply to Four Corners, Cholla, and the Navajo Plant. We cannot currently predict the impact of these anticipated rules on APS’s operations.
At the present time, we cannot predict what other rules or regulations may ultimately result from the EPA’s endangerment finding and what impact other potential rules or regulations will have on APS’s operations. If any emission reduction legislation or additional 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.
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. (See “Energy Sources and Resource Planning - Current and Future Resources” above for details of these plans and initiatives.) 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.
Pinnacle West prepares an annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.
Climate Change Lawsuit. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010. On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.
On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants. However, the Court left open the issue of whether such claims may be available under state law. Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision. We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.
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.
The Four Corners and Navajo Plant participants’ obligations to comply with the EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s determinations), coupled with the financial impact of potential 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.
Cholla. In 2007, ADEQ required APS to perform a BART analysis for Cholla pursuant to the Clean Air Visibility Rule. APS completed the 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. ADEQ reviewed APS’s recommendations and submitted its proposed BART SIP for Cholla and other sources within the state on March 2, 2011. The EPA may accept the proposed SIP or reject part or all of it if the EPA determines the SIP is inadequate. If the EPA rejects the proposed SIP provisions applicable to Cholla,
it could issue a FIP for the plant that includes more stringent pollution control technology requirements and emission limits.
On December 2, 2011, the EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental organizations, which alleged that the EPA failed to promulgate FIPs for states that have not yet submitted all or part of the required BART SIPs. The proposed consent decree establishes proposed and final promulgation deadlines (May 15, 2012 and November 15, 2012, respectively) for the EPA to promulgate regional haze FIPs or approve regional haze SIPs for 34 states, including Arizona. On January 3, 2012, APS submitted comments to the EPA regarding the proposed consent decree.
Once APS receives a final determination as to what constitutes BART for Cholla, we will have up to five years to complete the installation of the equipment and to achieve the BART emission limits. 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).
Four Corners and the Navajo Plant. The EPA previously 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.
On October 6, 2010, the EPA issued its proposed BART determination for Four Corners. The proposed rule would require the installation of post-combustion controls on each of Units 1-5 at Four Corners to reduce nitrogen oxides (“NOx”) emissions. Current estimates indicate that APS’s total costs for these controls could be up to approximately $400 million for Four Corners. If APS’s purchase of SCE’s interest in Units 4 and 5 is consummated and Units 1-3 are closed, APS’s total costs for these controls would be approximately $300 million. (See “Energy Sources and Resource Planning - Generation Facilities - Coal Fueled Generating Facilities - Four Corners” for details of this proposed transaction.) The EPA also indicated in the proposal that it may require the installation of electrostatic precipitators or baghouses on Units 1, 2, and 3 to reduce particulate matter emissions. APS estimates that its total costs for such particulate removal equipment is approximately $220 million, which may also be required under the mercury rules. (See “Environmental Matters - Mercury and Other Hazardous Air Pollutants” below for additional information on these rules.) The EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.
On November 24, 2010, APS submitted a letter to the EPA proposing an alternative to the EPA’s October BART proposal. Specifically, APS proposed to close Four Corners Units 1, 2, and 3 by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that the EPA agrees to a contemporaneous resolution of Four Corners’ obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the New Source Review program, and NSPS programs of the Clean Air Act.
On February 10, 2011, the EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, the EPA proposed to find that a different alternative emission control strategy, based upon APS’s November 2010 proposal, would achieve more progress than the EPA’s October 2010 BART proposal. The Supplemental Notice proposes that Units 1, 2, and 3 would close by 2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by the EPA in October 2010. APS provided comments to the EPA on both proposals and continues to evaluate them.
The EPA has not yet issued a proposed rule for the Navajo Plant. 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’s Navajo Plant ownership interest. If the EPA determines that post-combustion controls are required, APS’s total costs could be up to approximately $93 million for the Navajo Plant. The Four Corners and the Navajo Plant participants will have up to five years after the EPA issues its final determinations to achieve compliance with their respective BART requirements.
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’s 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. On December 16, 2011, the EPA issued the final Mercury and Air Toxics Standards (“MATS”), which established maximum achievable control technology (“MACT”) standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. APS will have three (potentially four if the permitting authority grants a one-year extension) years after the effective date of the rule to achieve compliance.
The MATS will 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. APS estimates that the cost for equipment necessary to meet these standards is approximately $220 million for Four Corners Units 1-3 and $89 million for Cholla Units 1-3. The estimated costs for Four Corners Units 1-3 are not included in our current environmental expenditure estimates since our estimates assume the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3. Cholla’s estimated costs for the next three years 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 for details of our capital expenditure estimates). SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the MATS. If it is determined that the installation of polishing baghouses is required, APS’s total costs could be up to approximately $92 million for the Navajo Plant.
Cooling Water Intake Structures. The EPA issued its proposed cooling water intake structures rule on April 20, 2011, which provides national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the Clean Water Act. The proposed standards are intended to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). To minimize impingement mortality, the proposed rule would require
facilities, such as Four Corners and the Navajo Plant, to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity, and to take certain protective measures with respect to impinged fish. To minimize entrainment mortality, the proposed rule would also require these facilities to conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required. Additional studies and a peer review process will also be required at these facilities.
As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. APS is performing analyses to determine the costs of compliance with the proposed rule. APS filed comments on the proposed rule on July 21, 2011.
Coal Combustion Waste. On June 21, 2010, the EPA released its proposed regulations governing the handling and disposal of coal combustion residuals (“CCRs”), such as fly ash and bottom ash. APS currently disposes of CCRs 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 proposes regulating CCRs as either non-hazardous waste or hazardous waste and requested comments on three different alternatives. The hazardous waste proposal would phase out the use of ash ponds for disposal of CCRs. The other two proposals would regulate CCRs as non-hazardous waste and impose performance standards for ash disposal. One of these proposals would require retrofitting or closure of currently unlined ash ponds, while the other proposal would not require the installation of liners or pond closures. The EPA has not yet indicated a preference for any of the alternatives.
APS filed comments on the proposed rule during the public comment period, which ended on November 19, 2010. Although we do not know when the EPA will issue a final rule or by when compliance will ultimately be required, it is expected that the agency may take final action on the rule in 2012. We cannot currently predict the outcome of the EPA’s actions or whether such actions will have a material adverse impact on our financial position, results of operations, or cash flows.
Ozone National Ambient Air Quality Standards. In March 2008, the EPA adopted new, more stringent eight-hour ozone standards, known as national ambient air quality standards (“NAAQS”). In January 2010, the EPA proposed to adopt even more stringent eight-hour ozone NAAQS. However, on September 2, 2011, President Obama decided to withdraw the EPA’s revised ozone standards until at least 2013 when the EPA would be required to review them as part of its five-year NAAQS review process. As ozone standards become more stringent, our fossil generation units may come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds and/or to generate emission offsets for new projects or facility expansions. At this time, APS is unable to predict what impact the adoption of these standards may have on its financial position, results of operations, or cash flows.
New Source Review. 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. 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 responded to the EPA’s request in August 2009 and is currently unable to predict the timing or content of the EPA’s response, if any, or any resulting actions.
On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS believes the claims in this matter are without merit and will vigorously defend against them.
Endangered Species Act. On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats. The lawsuit requests the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA. Although we are not a party to the lawsuit, we continue to evaluate the lawsuit to determine its potential impact on plant operations.
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 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.
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 or cash flows.
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 Resource Planning - Generation Facilities - 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 Nation 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’s generating plants. At the present time, APS has adequate water to meet its needs. However, 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.
Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS operations.
San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s 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.
Gila River Adjudication. 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’s 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’s other power plants are also located within the geographic area subject to the summons. APS’s 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’s water rights claims has been set in this matter.
Little Colorado River Adjudication. 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’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’s water rights claims has been set in this matter.
A number of parties, including APS, the Navajo Nation, the Hopi Tribe, and other claimants in the Little Colorado River Adjudication have been engaged in settlement negotiations to resolve competing water claims. On June 3, 2011, counsel for all the parties to the settlement discussions, including APS, signed, on behalf of their respective clients, a document expressing their agreement to recommend that the settlement be approved by their respective clients. Negotiations among the parties continue. If ultimately approved by the parties, the United States Congress, and the Arizona legislature, APS believes this settlement would be beneficial in protecting APS’s interest through its resolution of any and all claims that the Navajo Nation and the Hopi Tribe may have to the Little Colorado River system and source in Arizona.
Although the above matters remain subject to further evaluation, APS does not expect that the described litigation or settlement will have a material adverse impact on its financial position, results of operations or cash flows.
BUSINESS OF OTHER SUBSIDIARIES
The operations of our other first-tier subsidiaries (described below) are not expected to contribute in any material way to our future financial performance nor will they require any material amounts of capital over the next three years. We continue to focus on our core utility business and streamlining the Company. In August 2011, we sold our competitive energy services subsidiary, APSES, for an after tax gain of $10 million.
El Dorado
El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. As of December 31, 2011, El Dorado had total assets of $20 million.
SunCor
SunCor was 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. As of December 31, 2011, SunCor had no existing bank debt and had total assets remaining on its books of $9 million, consisting of $7 million of intercompany receivables and $2 million of other assets. On February 24, 2012, SunCor filed for protection under the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Arizona to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.
Financial Summary
(a) All reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income. (See Note 21.)
(b) The 2009 amount includes a $266 million (pre-tax) real estate impairment charge.
OTHER INFORMATION
Pinnacle West, APS and Pinnacle West’s other first-tier subsidiaries are all incorporated in the State of Arizona. Additional information for each of these companies is provided below:
The APS number includes employees at jointly-owned generating facilities (approximately 3,050 employees) for which APS serves as the generating facility manager. Approximately 1,930 APS employees are union employees. APS entered into a new three-year collective bargaining agreement with union employees in the fossil generation, energy delivery and customer service business areas that expires in April 2014. The agreement with union employees serving as Palo Verde security officers expires in 2013.
WHERE TO FIND MORE INFORMATION
We use our website www.pinnaclewest.com as a channel of distribution for material Company information. The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”): Annual Reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports. Our board and committee charters, Code of Ethics for Financial Executives, Ethics Policy and Standards of Business Practices and other corporate governance information is also available on the Pinnacle West website. Pinnacle West will post any amendments to the Code of Ethics for Financial Executives and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its website. The information on Pinnacle West’s website is not incorporated by reference into this report.
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).
ITEM 1A. RISK FACTORS
In addition to the factors affecting specific business operations identified in 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’s 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’s retail electric rates and the FERC regulates rates for wholesale power sales and transmission services. The profitability of APS is affected by the rates it may charge and the timeliness of recovering costs incurred through its rates. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS rate proceedings and ancillary matters which may come before the ACC and the FERC. Arizona, like certain other states, has a statute that allows the ACC to reopen prior decisions and modify final orders under certain circumstances. The ACC must also approve APS’s 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 or the FERC could have a material adverse impact on our financial condition, results of operations or cash flows.
APS’s ability to conduct its business operations and avoid fines and penalties depends upon compliance with federal, state or local statutes, regulations and ACC requirements, 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’s business, including the FERC, the NRC, the EPA, the ACC and state and local governmental agencies. These agencies regulate many aspects of APS’s 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. In addition to penalties, APS may be unable to recover certain costs if, for example, it fails to implement any of its annual ACC-approved renewable implementation plans. APS is also 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’s 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’s 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. Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on existing and new facilities. As a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation. We cannot predict when or if the NRC will take formal action as a result of its review. The financial and/or operational impacts on Palo Verde and APS may be significant.
In the event of noncompliance with its requirements, 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. 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’s 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’s 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 a final rulemaking from the EPA that could impose new requirements on Four Corners and the Navajo Plant. APS is also awaiting the EPA’s issuance of a FIP or partial FIP 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 and operating 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, resulting in plant closures and asset impairments.
Coal Ash. The EPA released proposed regulations governing the disposal of CCRs, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. The EPA proposed regulating CCRs as either non-hazardous or hazardous waste. APS currently disposes of CCRs 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 CCRs as a hazardous solid waste or phases out APS’s ability to dispose of CCRs through the use of ash ponds, APS could incur significant costs for CCR 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 New Source Review 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 New Source Review. In 2009, APS received and responded to a request from the EPA regarding projects and operations of Four Corners. An environmental organization filed suit against the Four Corners participants for alleged violations of New Source Review and the NSPS programs of the Clean Air Act. If the EPA seeks to impose New Source Review requirements at Four Corners or any other APS plant, or if the citizens’ group prevails in its lawsuit, significant capital investments could be required to install new pollution control technologies. The EPA could also seek civil penalties.
APS cannot assure 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’s 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.
Financial Risks - Potential Legislation and Regulation. It is possible that some form of legislation or EPA action to regulate domestic greenhouse gas emissions may occur in the future at the
federal level. If the United States Congress, or individual states or groups of states in which APS operates, ultimately pass legislation, or if the EPA promulgates additional regulations regulating the emissions of greenhouse gases, any resulting limitations on 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’s generation capacity).
At the state level, the California legislature enacted legislation to address greenhouse gas emissions and the California Air Resources Board approved regulations that will establish a cap-and-trade program for greenhouse gas. This legislation, regulation and other state-specific initiatives may affect APS’s 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 2016.
Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the Southwest’s desert area, and these are risks that APS considers in the normal course of business in the engineering and construction of its electric system. Large increases in ambient temperatures could require evaluation of certain materials used within its system and represent a greater challenge.
Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on APS’s 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’s service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers. As a result, APS cannot predict if, when, and the extent to which, additional competitors may re-enter APS’s service territory.
In 2010, the ACC issued a decision holding that solar vendors that install and operate solar facilities for non-profit schools and governments pursuant to a specific type of contract that calculates payments based on the energy produced are not “public service corporations” under the Arizona Constitution, and are therefore not regulated by the ACC. A second matter is pending with the ACC to determine whether that ruling should extend to solar providers who serve a broader customer base under the same business model. The use of such products by customers within our territory would result in some level of competition. APS cannot predict whether the ACC will deem these vendors “public service corporations” subject to ACC regulation and when, and the extent to which, additional service providers will enter APS’s service territory, increasing the level of competition in the market.
OPERATIONAL RISKS
APS’s 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’s 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’s financial condition, results of operations and cash flows.
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’s communities and electric transmission lines. Any damage caused as a result of forest fires could negatively impact APS’s financial condition, results of operations or cash flows.
Effects of Energy Conservation Measures and Distributed Energy. The ACC has enacted rules regarding energy efficiency that mandate a 22% annual energy savings requirement by 2020. This will likely increase participation by APS customers in energy efficiency and conservation programs and other demand-side management efforts, which in turn will impact the demand for electricity. The 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. To that end, the proposed Settlement Agreement in APS’s current retail rate case includes a mechanism to address these matters. The 2009 retail rate case settlement agreement also established energy efficiency goals for APS that began in 2010 that extend through 2012, subjecting APS to energy efficiency requirements slightly greater for the first two of those years than required under the rules described above.
APS must also meet certain distributed energy requirements. A portion of APS’s 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 was 25% of the overall RES requirement of 3% in 2011 and increased to 30% of the applicable RES requirement for 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 ratemaking mechanisms, such as those proposed in the Settlement Agreement, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.
The operation of power generation facilities and transmission systems involves risks that could result in reduced output or unscheduled outages, which could materially affect APS’s results of operations.
The operation of power generation, transmission and distribution 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’s business. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the larger transmission power grid, and the operation or failure of our facilities could adversely affect the operations of others. If APS’s facilities operate below expectations, especially during its peak seasons, it may lose revenue or incur additional expenses, including increased purchased power expenses.
The inability to successfully develop or acquire generation resources to meet new or evolving standards and regulations could adversely impact our business.
Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain certain regulatory approvals create uncertainty surrounding our generation portfolio. For example, APS’s acquisition of SCE’s interest in Four Corners is contingent upon regulatory approval. If not approved, we could face increased costs for replacement power or the need to acquire or develop alternate resources. In addition, APS is required by the ACC to meet certain energy resource portfolio requirements and the RES. The development of any renewable generation facilities resulting from the RES is subject to many other risks, including risks related to financing, siting, permitting, technology, the construction of sufficient transmission capacity to support these facilities and stresses to generation and transmission resources from intermittent generation characteristics of renewable resources. APS’s inability to adequately develop or acquire the necessary generation resources to meet the required standards could have a material adverse impact on our business and results of operations.
The lack of access to sufficient supplies of water could have a material adverse impact on APS’s business and results of operations.
Assured supplies of water are important for APS’s 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’s generating plants have been and are the subject of inquiries, claims and legal proceedings. In addition, the region in which APS’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies. APS’s 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 leases, 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 leases, easements or other rights-of-way that are effective for specified periods. APS is currently unable to predict the final outcome of pending and future approvals by applicable governing bodies with respect to renewals of these leases, 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 participants, 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 $118 million (but not more than $18 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 and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
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’s 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.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was signed into law in July 2010, contains measures aimed at increasing the transparency and stability of the over-the counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict, among other things, trading positions in the energy futures markets, require different collateral or settlement positions, or increase regulatory reporting over derivative positions. Based on the provisions included in the Dodd-Frank Act and the implementation of regulations, these changes could, among other things, impact our ability to hedge commodity price and interest rate risk or increase the costs associated with our hedging programs.
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 APS’s 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 could create challenges for APS’s existing business.
Research and development activities are ongoing to assess alternative technologies that produce power or reduce power consumption, including clean coal and coal gasification, renewable technologies including photovoltaic (solar) cells, customer-sited generation (solar) and efficiency technologies, 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’s existing generating facilities less economical. In addition, advances in technology and equipment/appliance efficiency could reduce the demand for power supply, which could adversely affect APS’s business.
APS is pursuing and implementing smart grid technologies, including advanced transmission and distribution system technologies, digital meters enabling two-way communications between the utility and its customers, and electric usage monitoring devices for 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’s existing technologies and equipment. Uncertainties and unknowns related to these and other advancements in technology and equipment could adversely affect APS’s business if national standards develop that do not embrace the current technologies or if the technologies and equipment fail to perform as expected. In addition, widespread installation and acceptance of these devices could enable the entry of new market participants, such as technology companies, into the interface between APS and its customers.
We are subject to employee workforce factors that could adversely affect our business and financial condition.
Like most companies in the electric utility industry, our workforce is aging and a number of our employees will become eligible to retire within the next few years. Although we have undertaken efforts to recruit and train new employees, we may not be successful. We are subject to other employee workforce factors, such as the availability of qualified personnel, the need to negotiate collective bargaining agreements with union employees and potential work stoppages. Exposure to these or other employee workforce factors could negatively impact our business, financial condition or results of operations.
We are subject to information security risks and risks of unauthorized access to our systems.
In the regular course of our business we handle a range of sensitive security, customer and business systems information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or the inappropriate release of certain types of information, including confidential customer, employee, financial or system operating information, could have a material adverse impact on our financial condition, results of operations or cash flows.
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, our technology systems are vulnerable to disability, failures or unauthorized access. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems and physical assets could be targets of such unauthorized access. Failures or breaches of our systems could impact the reliability of our generation, transmission and distribution systems and also subject us to financial harm. If our technology systems were to fail or be breached and if we are unable to recover in a timely way, we may not be able to fulfill critical business functions and sensitive confidential data could be compromised, which could have a material adverse impact on our financial condition, results of operations or cash flows.
The implementation of security measures and cost of insurance addressing such activities could increase costs and have a material adverse impact on our financial results. These types of events could also require significant management attention and resources, and could adversely affect Pinnacle West’s and APS’s reputation with customers and the public.
FINANCIAL RISKS
Financial market disruptions or new financial rules or regulations 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 credit markets as a significant source of liquidity and the capital markets for capital requirements not satisfied by cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions or rules or regulations may increase our cost of borrowing generally, and/or otherwise adversely affect our ability to access the credit markets.
In addition, the credit commitments of our lenders under our bank facilities may not be satisfied for a variety of reasons, including periods of financial distress or liquidity issues affecting our lenders, which could materially adversely affect the adequacy of our liquidity sources.
Changes in economic conditions, monetary policy or other factors 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:
· causing a downgrade of our credit ratings;
· increasing the cost of future debt financing and refinancing;
· increasing our vulnerability to adverse economic and industry conditions; and
· requiring us to dedicate an increased 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 downgrade of our credit ratings could materially and adversely affect our business, financial condition and results of operations.
Our current ratings are set forth in “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’s 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 for future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under 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 severely limit 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.
Investment performance, changing interest rates and other economic factors could decrease the value of our benefit plan assets and nuclear decommissioning trust funds and increase the valuation of our related obligations, resulting in significant additional funding requirements. Any inability to fully recover these costs in our utility rates would negatively impact our financial condition.
We have significant pension plan and other postretirement benefits plan obligations to our employees and retirees and legal obligations to fund nuclear decommissioning trusts for Palo Verde. We hold and invest substantial assets in these trusts that are designed to provide funds to pay for certain of these obligations as they arise. Declines in market values or poor investment results may adversely affect the values of the fixed income and equity securities held in these trusts and increase our funding requirements. Additionally, the valuation of liabilities related to our pension plan and other postretirement benefit plans are impacted by a discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates decrease the discount rate, increase the valuation of the plan liabilities 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 and changes in other actuarial assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. The minimum contributions required under these plans have increased, and could continue to do so, resulting in significant cash funding obligations that could have a material impact on our financial position, results of operations or cash flows.
We recover most of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs in our regulated rates. Any inability to fully recover these costs in a timely manner would have a material negative impact on our financial condition, results of operations or cash flows.
We may be required to adopt 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 (“IASB”) 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 no earlier than 2015. In the meantime, the FASB and the IASB are working on several accounting standards jointly to converge certain accounting differences. 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 APS.
We conduct our operations primarily through our subsidiary, APS. Essentially all of our consolidated assets are held by APS. Accordingly, our cash flow and our ability to pay dividends on our common stock is dependent upon the earnings and cash flows of APS and its distributions to us. APS is a separate and distinct legal entity and has no obligation to make distributions to us.
APS’s debt agreements may restrict its ability to pay dividends, make distributions or otherwise transfer funds to us. In addition, 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 total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.
Pinnacle West’s ability to meet its debt service obligations could be adversely affected because its debt securities are structurally subordinated to the debt securities and other obligations of its subsidiaries.
Because Pinnacle West is 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. 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 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;
· 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;
· favorable or adverse regulatory or legislative developments;
· 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 continuing wind-down of its real estate business may give rise to various claims.
Since 2009, SunCor has been engaged in 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. SunCor is focusing on concluding an orderly wind-down of its business. This effort includes addressing contingent liabilities, such as warranty and construction claims that may be brought by property owners and potential funding obligations to local taxing districts that financed infrastructure at certain of its real estate developments.
Pinnacle West has not guaranteed any of SunCor’s obligations. SunCor’s remaining business operations, and its ability to generate cash from operations, are minimal. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. Pinnacle West could be exposed to the uncertainties and complexities inherent for parent companies in such proceedings.
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 2011 fiscal year and that remain unresolved.
ITEM 2. PROPERTIES
Generation Facilities
APS’s 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 - Energy Sources and Resource Planning - Generation Facilities - Nuclear” in Item 1 for details regarding leased interests in Palo Verde. The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso Electric Company (15.8%), Public Service Company of New Mexico (10.2%),
Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%). The plant is operated by APS.
(c) The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), SCE (48%), Tucson Electric Power Company (7%) and El Paso Electric Company (7%). The plant is operated by APS. As discussed under “Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal Fueled Generating Facilities - Four Corners” in Item 1, APS and SCE have entered into an agreement by which APS would acquire SCE’s interest in Units 4 and 5, after which APS would close Units 1, 2 and 3.
(d) The other participants 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%). The plant is operated by Salt River Project.
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’s generating facilities.
See “Business of Arizona Public Service Company” in Item 1 for a map detailing the location of APS’s major power plants and principal transmission lines.
Transmission and Distribution Facilities
Current Facilities. APS’s transmission facilities consist of approximately 5,866 pole miles of overhead lines and approximately 49 miles of underground lines, 5,643 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,376 miles of overhead lines and approximately 17,561 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’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2011:
Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’s 2012 plan, APS projects it will invest approximately $550 million in new transmission projects (115 kV and above) over the next ten years, which includes 269 miles of new lines. This investment will increase the import capability into metropolitan Phoenix and the Yuma area. One significant project currently under development is a new 500kV path that will span from the Palo Verde Hub around the western and northern edges of the Phoenix metropolitan area and terminate at a bulk substation in the northeast part of Phoenix. The project consists of four phases. The first phase, Morgan to Pinnacle Peak 500kV, is currently in-service. The second phase, Delaney to Palo Verde
500kV, is under construction. The third and fourth phases, Delaney to Sun Valley 500kV and Morgan to Sun Valley 500kV, have been permitted and are in various stages of final design and development. In total, the projects consist of over 100 miles of new 500kV lines, with many of those miles constructed as capable of stringing a 230kV line as a second circuit.
APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities. Two such projects, which are included in APS’s 2012 transmission plan, are the Delaney 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. On March 7, 2011, the Navajo Nation Council signed a resolution approving a 25-year extension to the existing Four Corners lease term and providing Navajo Nation consent to renewal of the related easements. APS is now preparing to file applications for renewal of these easements with the DOI. Before it may approve the Four Corners lease extension and issue the renewed easements, the United States must complete an analysis under the federal National Environmental Policy Act, the ESA and related statutes.
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. In March 2011, the Navajo Nation provided its consent to renew the easements for the transmission lines specified in the lease extension. However, some of our easements 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 not addressed in the lease extension is uncertain. We are monitoring these easement issues and have had extensive discussions with the Navajo Nation regarding the easements. We are currently unable to predict the outcome of this matter.
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 ACC and FERC-related matters.
See Note 11 for information relating to the FERC proceedings on Pacific Northwest energy market issues and matters related to a September 2011 power outage.
ITEM 4. MINE SAFETY DISCLOSURES
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 24, 2012, 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, 2012, Pinnacle West’s common stock was held of record by approximately 25,595 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW
APS’s 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’s common stock.
The chart below sets forth the dividends paid on APS’s common stock for each of the four quarters for 2011 and 2010.
Common Stock Dividends
(Dollars in Thousands)
The sole holder of APS’s common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. As of December 31, 2011, 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 2011.
(1) Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock and performance shares.
ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION - CONSOLIDATED
(a) Amounts primarily related to SunCor’s real estate impairment charges (see Note 22) and APSES discontinued operations (see Note 21).
SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY - CONSOLIDATED
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’s Consolidated 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 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. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.
Areas of Business Focus
Operational Performance, Reliability and Recent Developments.
Nuclear. In 2011, Palo Verde achieved its best generation year ever, producing over 31 million megawatt-hours, with an overall station capacity factor of 90.7%. In 2011, Palo Verde successfully refueled both Unit 1 and Unit 2. In April 2011, the NRC approved APS’s application for renewed operating licenses for the Palo Verde units, extending the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively. APS management is working closely with regulators and others in the nuclear industry to analyze the lessons learned and address any rulemaking or improvements resulting from the March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in Japan.
Coal and Related Environmental Matters. APS-operated coal plants, Four Corners and Cholla, achieved net capacity factors of 78% and 82%, respectively, in 2011. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning greenhouse gas emissions. 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 its long-range capital management plans, understanding that any resulting regulation and legislation 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.
In addition, SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is subject to the receipt of approvals by the ACC, the California Public Utilities Commission (the “CPUC”) and the FERC. APS and SCE filed applications with their respective commissions seeking requisite authority or approvals to complete the transaction. On February 17, 2012, the CPUC issued a proposed decision approving the sale, with a final decision expected in March. Closing is also conditioned on the execution of a new coal supply
contract, expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical closing conditions. Hearings at the ACC concluded on September 1, 2011. We expect the administrative law judge to issue a recommended decision in early 2012.
APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest from 2016 to 2041. Execution by the Navajo Nation of the lease amendments is a condition to closing of the purchase by APS of SCE’s interests in Four Corners. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which became effective in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related Federal rights-of-way grant which the Four Corners participants will pursue. A Federal environmental review is underway as part of the DOI review process.
APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. APS owns 100% of Units 1-3. These events will change the plant’s overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791 MW to 970 MW. When applying for approval to purchase Units 4 and 5, APS also requested from the ACC recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3. The proposed Settlement Agreement in APS’s current retail rate case allows for the case to remain open to allow APS to seek a rate adjustment to reflect the Four Corners transaction should the ACC allow APS to pursue the acquisition and should the transaction thereafter close.
APS cannot predict whether all of the conditions necessary to consummate the purchase of SCE’s interest will be met such that closing can occur, including whether the parties will receive satisfactory regulatory approvals.
Transmission and Delivery. In the area of transmission and delivery to its customers, APS had its best reliability year to date and ranked favorably during 2011, with top quartile performance for average annual customer outage time and average annual customer interruptions. APS’s 2012 Ten-Year Transmission Plan filed with the ACC in January 2012 projects that it will invest approximately $550 million in new transmission projects (115 kV and above) over the next ten years, adding 269 miles of new lines. The first three years of these additions are included in the capital expenditures table presented in the “Liquidity and Capital Resources” section below along with other transmission costs for upgrades and replacements. 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 long-term benefits both to APS and its customers. APS is piloting and deploying a variety of technologies that are intended to 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. The ACC approved the RES in 2006. The renewable energy requirement is 3.5% of retail electric sales in 2012 and increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to 1,700 GWh of new renewable resources to be in service by year-end 2015 in addition to its 2008 renewable resource commitments. Taken together, APS’s commitment is estimated to be 3,400 GWh, or approximately 10% of APS’s retail energy sales by year-end 2015, which is double the existing RES target of 5% for that year. A component of the RES is focused on stimulating development of
distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).
APS has a diverse portfolio of existing and planned renewable resources totaling 946 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 423 MW are currently in operation and 523 MW are under contract for development or are under construction. Renewable resources in operation include 55 MW of utility-scale facilities owned by APS, 232 MW of long-term purchased power agreements, and an estimated 136 MW of customer-sited, third-party owned distributed energy resources.
To achieve our RES requirements, as mentioned above, to date APS has entered into contracts for 523 MW of renewable resources that are planned, in development or under construction. APS’s strategy to procure these resources includes new facilities to be owned by APS, purchased power contracts for new facilities and ongoing development of distributed energy resources. Through the AZ Sun Program, APS plans to own up to 200 MW of solar photovoltaic power plants across Arizona by investing up to $975 million through 2015. Under this program, APS has executed contracts for the development of 83 MW of new solar generation, representing an investment commitment of approximately $375 million. See Note 3 for additional details of the AZ Sun Program, including the related cost recovery. APS has also entered into long-term purchased power agreements for 397 MW from solar, wind and biogas facilities currently planned, in development or under construction, and 93 MW from distributed energy resources. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.
On July 1, 2011, APS filed its annual RES implementation plan with the ACC, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 MW under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility-owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015. In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications. Under the ACC’S order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.
Demand Side Management. In recent years, Arizona regulators have placed an increased focus on energy efficiency and other 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% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. On July 27, 2010, the proposed Energy Efficiency Standard was adopted by the ACC, approved by the Arizona Attorney General and became effective on January 1, 2011. This ambitious standard will likely impact Arizona’s future energy resource needs. On June 1, 2011 APS filed its 2012 Energy Efficiency Implementation Plan with a proposed budget for 2012 of $90 million. APS expects a decision from the ACC prior to March 31, 2012. However, APS cannot predict whether the ACC will approve the plan as filed.
Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. On June 1, 2011, APS filed a rate case with the ACC requesting, among other things, an increase in retail rates to allow APS to continue to maintain and upgrade its electric systems for enhanced reliability, approval of recovery mechanisms, including a decoupling mechanism, and approval of other programs and mechanisms aimed at energy efficiency and renewable energy. On January 6, 2012, APS and other parties to the retail rate case entered into a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. The Settlement Agreement requires the approval of the ACC. As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties. The proposed Settlement Agreement demonstrates cooperation among APS, the ACC staff, the Residential Utility Consumer Office 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 details regarding the current rate case, the Settlement Agreement terms and for information on APS’s 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 demand-side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.
Financial Strength and Flexibility. 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 February 2011, APS entered into a $500 million revolving credit facility, replacing its $489 million revolving credit facility that would have otherwise terminated in September 2011. In November 2011, Pinnacle West and APS refinanced their $200 million and $500 million revolving credit facilities, respectively, that would have otherwise matured in February 2013.
In August 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011. In January 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. APS will use the net proceeds from the sale of the notes along with other funds to pay at maturity its $375 million aggregate principal amount of 6.50% unsecured senior notes that mature on March 1, 2012.
APSES. On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain of approximately $10 million.
Other Subsidiaries. The operations of El Dorado 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. As a result of the continuing distressed conditions in the real estate markets, during 2009 our other first-tier 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. At December 31, 2011, SunCor had total remaining assets of about $9 million, including $7 million of intercompany receivables, and no debt. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations or cash flows.
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 2009 through 2011, retail electric revenues comprised approximately 93% of our total electric operating revenues. Our electric operating revenues are affected by customer growth or decline, 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’s retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
Customer and Sales Growth. Retail customer growth in APS’s service territory for the year ended December 31, 2011 was 0.4% compared with the prior year. For the three years 2009 through 2011, APS’s customer growth averaged 0.6% per year. We currently expect annual customer growth to average about 1.6% for 2012 through 2014 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, for the year ended 2011 increased 0.6% compared with the prior year, reflecting mildly improving economic conditions, partially offset by the effects of our energy efficiency programs. For the three years 2009 through 2011, APS experienced annual declines in retail electricity sales averaging 0.9%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will remain flat on average during 2012 through 2014, including the effects of APS’s energy efficiency programs, but excluding the effects of weather variations. The failure of the Arizona economy to rebound in the near future could further impact these estimates.
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 related amortization.
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 the settlement agreement related to the 2008 retail rate case, 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. See “Capital Expenditures” below for information regarding the planned additions to our facilities. With the twenty-year extensions of the operating licenses for each of the Palo Verde units recently granted by the NRC, we estimate that our pretax depreciation expense will decrease by approximately $34 million per year starting on 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 in Arizona for APS, which owns essentially all of our property, was 9.0% of the assessed value for 2011, 8.0% for 2010 and 7.5% for 2009. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals proposed in the Settlement Agreement.)
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 AFUDC. 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, equity issuances and internally generated cash flow. An allowance for borrowed funds offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.
RESULTS OF OPERATIONS
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.
APSES’s and SunCor’s operations have been classified as discontinued operations. Pinnacle West sold its investment in APSES in August 2011.
Operating Results - 2011 compared with 2010
Our consolidated net income attributable to common shareholders for the year ended December 31, 2011 was $339 million, compared with net income of $350 million for the prior year. The $11 million net decrease consisted of a $14 million decrease in income from discontinued operations and a $3 million increase in income from continuing operations primarily related to the regulated electricity
segment. Regulated electricity segment results reflect increased revenues related to weather and higher retail transmission charges and decreased operations and maintenance expenses. These positive factors were offset by higher depreciation and amortization due to increased plant in service, higher property taxes due to increased property tax rates and higher income taxes, including income tax benefits recognized in the prior year.
In addition, income from discontinued operations for the year ended December 31, 2011 included a gain of approximately $10 million after income taxes related to the sale of our investment in APSES. Income from discontinued operations in the prior year was due to a $25 million gain after income taxes related to the sale of APSES’s district cooling business.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
(a) Includes effects of 2011 settlement of certain prior-period transmission rights-of-way related to Four Corners, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million. Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.
(b) Operating revenues less fuel and purchased power expenses includes amounts related to demand-side management, renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance.
(c) Includes activities related to APSES and SunCor.
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 $94 million higher for the year ended December 31, 2011 compared with the prior year. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $34 million for the year ended December 31, 2011 compared with the prior year primarily because of:
· An increase of $28 million for settlement of certain transmission rights-of-way, which was offset in operating revenues;
· An increase of $27 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which were offset in operating revenues;
· A decrease of $16 million related to employee benefit costs; and
· A decrease of $5 million due to other miscellaneous factors.
Depreciation and amortization Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2011 compared with the prior year primarily because of increased plant in service.
Taxes other than income taxes Taxes other than income taxes increased $13 million for the year ended December 31, 2011 compared with the prior year primarily because of higher property tax rates in the current period.
Income taxes Income taxes were $23 million higher for the year ended December 31, 2011 compared with the prior year. This increase was primarily due to the effects of higher pretax income in the current year and income tax benefits recognized in the prior year related to a reduction in the Company’s 2010 effective income tax rate.
Discontinued Operations
Income from discontinued operations for year ended December 31, 2011 included a gain of $10 million related to the sale of our investment in APSES. Income from discontinued operations for the year ended December 31, 2010 included an after tax gain of $25 million related to the sale of APSES’s district cooling business.
Operating Results - 2010 compared with 2009
Our consolidated net income attributable to common shareholders for 2010 was $350 million, compared with $68 million for the comparable prior-year period. The improved results were primarily due to lower real estate impairment charges recorded in 2010 compared with the prior-year period by SunCor.
In addition, regulated electricity segment net income increased approximately $82 million from the prior-year period due to increased revenues related to APS’s retail rate increases and other factors. Our consolidated results for 2010 also include a gain of $25 million after income taxes related to the sale of APSES’s district cooling business.
The following table presents net income (loss) attributable to common shareholders by business segment compared with the prior-year period:
(a) Operating revenues less fuel and purchased power expenses includes amounts related to demand-side management, renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance.
(b) Includes activities related to El Dorado.
(c) Income from discontinued operations for 2010 includes a gain of $25 million after income taxes related to the sale of APSES’s district cooling business.
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 $164 million higher for the year ended 2010 compared with the prior year. The following table describes the major components of this change:
Operations and maintenance Operations and maintenance expenses increased $48 million for the year ended 2010 compared with the prior year primarily because of:
· An increase of $25 million related to demand-side management and renewable energy programs, which are primarily offset in operating revenues;
· An increase of $18 million related to employee benefits costs; and
· An increase of $5 million related to other miscellaneous factors.
Depreciation and Amortization Depreciation and amortization expenses were $8 million higher for the year ended 2010 compared with the prior year primarily because of increased plant in service partially offset by lower depreciation rates.
Taxes other than income taxes Taxes other than income taxes increased $12 million for the year ended 2010 compared with the prior year primarily because of higher property tax rates in the current year.
Interest charges, net of allowance for funds used during construction Interest charges, net of allowance for funds used during construction, decreased $8 million for the year ended 2010 compared with the prior year primarily because of higher rates in the current year for the allowance for equity and borrowed funds used during construction, partially offset by higher interest charges due to higher debt balances. Interest charges, net of allowance for funds used during construction are comprised of the regulated electricity segment portions of the line items interest expense and allowance for equity and borrowed funds used during construction from the Consolidated Statements of Income.
Income taxes Income taxes were $19 million higher for the year ended 2010 compared with the prior year primarily because of higher pretax income in the current-year period, partially offset by $17 million of income tax benefits related to prior years that were resolved in the current year. See Note 4.
All other All other increased $6 million primarily as a result of higher other income due to investment losses at El Dorado in 2009.
Discontinued Operations
Real estate activities During the first quarter of 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s assets. This decision resulted in impairment charges of approximately $161 million after income taxes in 2009. As of December 31, 2010, all of SunCor’s operations have been reclassified to discontinued operations (see Note 21). The after-tax impacts of the $6 million loss from real estate activities for the year ended 2010 includes real estate impairment charges of approximately $10 million (see Note 22) and other costs of $6 million, partially offset by a gain from debt restructuring of approximately $10 million.
All other All other earnings from discontinued operations were $33 million higher for the year ended 2010 compared to the prior-year period primarily because of a gain of $25 million after income taxes related to the sale of APSES’s district cooling business in 2010.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration of our Board of Directors based on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external debt and equity issuances. An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2011, APS’s common equity ratio, as defined, was 55%. Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.2 billion. Under this order, APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.
Many of APS’s current capital expenditure projects qualify for bonus depreciation. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 includes provisions making qualified property placed into service after September 8, 2010 and before January 1, 2012 eligible for 100% bonus depreciation for federal income tax purposes. In addition, qualified property placed into service in 2012 is eligible for 50% bonus depreciation for federal income tax purposes. These provisions of the recent tax legislation are expected to generate approximately $425-475 million of cash tax benefits for APS through accelerated depreciation. It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized in 2012. The cash generated is an acceleration of tax benefits that APS would have otherwise received over 20 years.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2011, 2010 and 2009 (dollars in millions):
Pinnacle West Consolidated
Arizona Public Service Company
Operating Cash Flows
2011 Compared with 2010 Pinnacle West’s consolidated net cash provided by operating activities was $1,125 million in 2011, compared to $750 million in 2010, an increase of $375 million in net cash provided. The increase is primarily due to the $161 million change in collateral and margin posted, as a result of changes in commodity prices and expiration of prior hedge contracts, and a $200 million voluntary pension contribution in 2010 (approximately $40 million of which is reflected in capital expenditures). In addition, APS’s operating cash flows included income tax payments to the parent company of approximately $81 million in 2010.
2010 Compared with 2009 Pinnacle West’s consolidated net cash provided by operating activities was $750 million in 2010, compared to $1,067 million in 2009, a decrease of $317 million in net cash provided. The decrease is primarily due to voluntary pension contributions in 2010 of $200
million (approximately $40 million of which is reflected in capital expenditures), the $121 million change in collateral and margin cash provided as a result of changes in commodity prices, and other changes in working capital. In addition, APS’s operating cash flows included income tax payments to the parent company of approximately $81 million in 2010.
Other Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA 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. Under ERISA, the qualified pension plan was 89% funded as of January 1, 2011 and is estimated to be 85% funded as of January 1, 2012. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The required minimum contribution to our pension plan is $65 million in 2012, approximately $160 million in 2013 and approximately $160 million in 2014. The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year. In addition, see further discussion in “Critical Accounting Policies - Pension and Other Postretirement Benefit Accounting” below.
The $69 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.
Investing Cash Flows
2011 Compared with 2010 Pinnacle West’s consolidated net cash used for investing activities was $782 million in 2011, compared to $576 million in 2010, an increase of $206 million in net cash used. The increase in net cash used for investing activities is primarily due to an increase of $131 million in capital expenditures and a decrease of $126 million in net proceeds from the sales of our non-utility businesses (see Note 21), partially offset by $55 million of proceeds from the sale of life insurance policies in 2011.
2010 Compared with 2009 Pinnacle West’s consolidated net cash used for investing activities was $576 million in 2010, compared to $705 million in 2009, a decrease of $129 million in net cash used. The decrease in net cash used for investing activities is primarily due to $100 million of proceeds from the sale of the district cooling business in June 2010 and the increase in proceeds from the sale of commercial real estate investments of $29 million.
Capital Expenditures The following table summarizes the actual capital expenditures for 2009, 2010 and 2011 and estimated capital expenditures for the next three years:
Capital Expenditures
(dollars in millions)
(a) Primarily information systems and facilities projects.
Generation capital expenditures are comprised of various improvements to APS’s 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. Included under Renewables is the AZ Sun Program, which is a significant component of the increase in capital expenditures from 2010 to 2011. In addition, Renewables reflects capital funding from the 2012 RES implementation plan which was approved by the ACC on December 14, 2011. For purposes of this table, we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5, subject to ACC approval, and the subsequent shut down of Units 1-3, as discussed in the “Overview” section above. As a result, we included the $294 million purchase price plus adjustments under Generation and have not included environmental expenditures for Units 1-3. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Financing Cash Flows and Liquidity
2011 Compared with 2010 Pinnacle West’s consolidated net cash used for financing activities was $420 million in 2011, compared to $209 million in 2010, an increase of $211 million in
net cash used. The increase in net cash used for financing activities is primarily due to $78 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the issuance of equity in April 2010 (which was infused into APS), partially offset by $121 million lower repayments of short-term borrowings at Pinnacle West.
APS’s net cash used for financing activities was $374 million in 2011, compared to net cash provided of $31 million in 2010, an increase of $405 million in net cash used. APS’s increase in net cash used for financing activities is primarily due to $107 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the infusion of equity from Pinnacle West in April 2010. In addition, APS increased its dividend payment to Pinnacle West by $47 million in 2011.
2010 Compared with 2009 Pinnacle West’s consolidated net cash used for financing activities was $209 million in 2010, compared to $322 million in 2009, a decrease of $113 million in net cash used. The decrease in net cash used for financing activities is primarily due to lower repayments of short-term borrowings in 2010 due to lower short-term debt balances partially offset by lower net sources of equity and long-term debt financing, including the absence of proceeds of $253 million from the issuance of equity in April 2010 (which was infused into APS), and APS’s issuance of $500 million of unsecured senior notes in 2009.
APS’s net cash provided by financing activities was $31 million in 2010, compared to net cash used of $208 million in 2009, a decrease of $239 million in net cash used. The decrease in net cash used for financing activities is primarily due to $522 million of repayments of short-term borrowings in 2009, partially offset by lower net sources of equity and long-term debt financing, including the proceeds of $253 million from the infusion of equity from Pinnacle West in April 2010 and APS’s issuance of $500 million of unsecured senior notes in 2009.
Significant Financing Activities During the year ended December 31, 2011, Pinnacle West’s total dividend per share of common stock was $2.10 per share, which resulted in dividend payments of $222 million. On January 18, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 1, 2012, to shareholders of record on February 1, 2012.
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings, or, if unavailable, its long-term issuer ratings. As of December 31, 2011, $50 million of the $175 million term loan facility had been repaid.
On August 25, 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011.
On September 7, 2011, APS entered into a new letter of credit agreement supporting its approximately $27 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. The agreement expires September 22, 2016.
On December 8, 2011, APS extended a letter of credit agreement supporting its approximately $17 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project), 1998. The agreement expires December 8, 2016.
On January 10, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale along with other funds will be used to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes due March 1, 2012.
Available Credit Facilities Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.
On November 4, 2011, Pinnacle West refinanced its $200 million revolving credit facility that would have matured in February 2013, with a new $200 million facility. The new revolving credit facility terminates in November 2016. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings.
At December 31, 2011, the Pinnacle West credit facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2011, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.
On February 14, 2011, APS refinanced its $489 million credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility. The new revolving credit facility terminates in November 2016. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
At December 31, 2011, APS had two credit facilities totaling $1 billion as described above. The facilities described above are available to support its $250 million commercial paper program, for bank borrowings, or for issuances of letters of credit. At December 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper.
See “Financial Assurances” in Note 11 for a discussion of APS’s letters of credit.
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 to the extent those costs vary from the Base Fuel Rate on a current basis, APS’s recovery or refund of the deferrals from or to its ratepayers, as appropriate, is subject to annual and, if necessary, periodic PSA adjustments.
See Note 3 for information regarding the settlement related to the 2008 retail rate case, which includes ACC authorization and requirements of equity infusions into APS of at least $700 million by December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).
See Note 18 for information related to the change in our margin accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2011, the ratio was approximately 47% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
See Note 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 15, 2012 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. 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’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in 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.
Off-Balance Sheet Arrangements
See Note 20 for a discussion of the impacts on our financial statements of consolidating certain VIEs.
Guarantees and Surety Bonds
Pinnacle West sold its investment in APSES on August 19, 2011. Upon the closing of the sale, Pinnacle West was released from its parental guarantee and surety bond obligations related to the APSES business. Pinnacle West has also issued parental guarantees and surety bonds for APS which were not material at December 31, 2011.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2011 (dollars in millions):
(a) The long-term debt matures at various dates through 2041 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2011 (see Note 6).
(b) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Notes 3 and 11).
(c) Contracts to purchase renewable energy credits in compliance with the RES.
(d) These contractual obligations include commitments for capital expenditures and other obligations. These amounts do not include the purchase of SCE’s interest in Four Corners Units 4 and 5 due to additional approvals required. See discussion in “Overview.”
This table excludes $136 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately $65 million, $160 million and $160 million in estimated minimum pension contributions for 2012, 2013 and 2014, respectively (see Note 8).
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 $1.4 billion of regulatory assets and $826 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2011.
Included in the balance of regulatory assets at December 31, 2011 is a regulatory asset of $1.0 billion 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, 2011 reported pension liability on the Consolidated Balance Sheets and our 2011 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, 2011 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2011 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 derivative instruments designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. When a derivative instrument qualifies as a cash flow hedge, the effective portion of changes in the fair value is recognized 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 account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. 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. The significance of a particular input determines how the instrument is classified in a 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 a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for discussion on accounting policies and Note 14 for further fair value measurement discussion.
OTHER ACCOUNTING MATTERS
See Note 2 for discussion regarding the adoption of amended accounting guidance in the first quarter of 2012 relating to fair value measurements and disclosures, and the presentation of comprehensive income.
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 14). 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, 2011 and 2010. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2011 and 2010 (dollars in thousands):
Pinnacle West - Consolidated
The tables below present contractual balances of APS’s long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2011 and 2010. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2011 and 2010 (dollars in thousands):
APS - Consolidated
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 may qualify as derivatives, including futures, 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 2011 and 2010 (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, 2011 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, 2011 and 2010 (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.
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 2011, 2010 and 2009
Pinnacle West Consolidated Balance Sheets as of December 31, 2011 and 2010
Pinnacle West Consolidated Statements of Cash Flows for 2011, 2010 and 2009
Pinnacle West Consolidated Statements of Changes in Equity for 2011, 2010 and 2009
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 Consolidated Statements of Income for 2011, 2010 and 2009
APS Consolidated Balance Sheets as of December 31, 2011 and 2010
APS Consolidated Statements of Cash Flows for 2011, 2010 and 2009
APS Consolidated Statements of Changes in Equity for 2011, 2010 and 2009
Supplemental Notes to APS’s Consolidated Financial Statements
Financial Statement Schedules for 2011, 2010 and 2009
Pinnacle West Schedule I - Condensed Statements of Income for 2011, 2010 and 2009
Pinnacle West Schedule I - Condensed Balance Sheets as of December 31, 2011 and 2010
Pinnacle West Schedule I - Condensed Statements of Cash Flows for 2011, 2010 and 2009
Pinnacle West Schedule II - Reserve for Uncollectibles for 2011, 2010 and 2009
APS Schedule II - Reserve for Uncollectibles for 2011, 2010 and 2009
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, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 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 24, 2012
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, 2011 and 2010 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, 2011. 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, 2011, 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 Pinnacle West Capital Corporation and Subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 24, 2012
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
Description of Business and Basis of Presentation
Pinnacle West is a holding company that conducts business through its subsidiaries; APS, SunCor, El Dorado, and formerly APSES. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. SunCor was a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah but in 2009 and 2010, essentially all of these assets were sold. All activities for SunCor are now reported as discontinued operations (see Note 21). APSES provided energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. APSES was sold in 2011 and is now reported as discontinued operations (see Note 21). El Dorado is an investment firm.
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, and El Dorado. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.
We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 20).
In preparing the consolidated financial statements, we have evaluated the events that have occurred after December 31, 2011 through the date the financial statements were issued.
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These consolidated financial statements and notes have been prepared consistently with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income, Consolidated Balance Sheets, and Consolidated Statements of Cash Flows in accordance with accounting requirements for reporting discontinued operations (see Note 21) and the impacts related to the reclassification of regulatory assets and liabilities for the current portion (see Note 3).
Certain line items are presented in more detail on the Consolidated Statements of Cash Flows than was presented in the prior years. Other line items are more condensed than the previous presentation. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications had no impact on total net cash flow provided by operating activities.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables show the impact of the reclassifications of prior years (previously reported) amounts (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
See Note 3 for additional information.
Electric Revenues
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
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 fuel and purchased power costs.
Effective January 1, 2010, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 retail rate case settlement agreement (see Note 3). This revenue treatment continues through 2012, or until new rates are established in APS’s next general retail rate case, if that is before year end 2012. Certain proceeds received under previous versions of the line extension policy, or for activities not involving an extension or upgrade of service (e.g., service relocations at the request of governmental entities or undergrounding of overhead facilities) will continue to be treated as contributions in aid of construction and will not impact electric revenues.
Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
· material and labor;
· contractor costs;
· capitalized leases;
· construction overhead costs (where applicable); and
· allowance for funds used during construction.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset
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retirement obligations. APS believes it can recover in regulated rates the costs capitalized in accordance with this accounting guidance.
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2011 were as follows:
· Fossil plant - 18 years;
· Nuclear plant - 29 years;
· Other generation - 28 years;
· Transmission - 38 years;
· Distribution - 35 years; and
· Other - 7 years.
APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008. On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses. The nuclear plant remaining life takes into consideration an ACC decision which authorizes the new Palo Verde Nuclear plant lives, effective January 1, 2012.
For the years 2009 through 2011, the depreciation rates ranged from a low of 1.30% to a high of 10.20%. The weighted-average rate was 2.98% for 2011, 2.98% for 2010, and 3.06% for 2009.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
AFUDC was calculated by using a composite rate of 10.25% for 2011, 9.2% for 2010, and 5.9% for 2009. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain
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circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use unobservable inputs, such as models and other valuation methods, to determine fair market value.
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.
See Note 14 for additional information about fair value measurements.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emission allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 18 for additional information about our derivative instruments.
Loss Contingencies and Environmental Liabilities
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.
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Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and our subsidiaries and provide medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 8 for additional information on pension and other postretirement benefits.
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 23 for information on nuclear decommissioning costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 4.
Real Estate Investments
We did not have any real estate investments at December 31, 2011 and December 31, 2010 on our Consolidated Balance Sheets. For the purposes of evaluating impairment, in accordance with the provisions on accounting for the impairment or disposal of long-lived assets; we classified our real estate assets, such as land under development, land held for future development, and commercial property as “held and used” in 2010 and 2009. When events or changes in circumstances indicated that the carrying values of real estate assets considered held and used would not be recoverable, we compared the undiscounted cash flows that we estimated would be generated by each asset to its carrying amount. If the carrying amount exceeded the undiscounted cash flows, we adjusted the asset to fair value and recognized an impairment charge. The adjusted value became the new book value (carrying amount) for held and used assets. Our internal models used inputs that we believe were consistent with those that would be used by market participants.
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Cash and Cash Equivalents
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $47 million in 2011, $45 million in 2010, and $35 million in 2009. Estimated amortization expense on existing intangible assets over the next five years is $42 million in 2012, $35 million in 2013, $28 million in 2014, $21 million in 2015, and $13 million in 2016. At December 31, 2011, the weighted average remaining amortization period for intangible assets was 7 years.
Investments
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 and Note 23 for more information on these investments.
2. New Accounting Standards
In May 2011, the FASB issued amended guidance to converge fair value measurement and disclosure requirements for GAAP and IFRS. The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The guidance is effective for us on January 1, 2012. The adoption of this new guidance will result in additional fair value disclosures, but will not impact our financial statement results.
In June 2011, the FASB issued amended guidance on the presentation of comprehensive income intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence with IFRS. The amended guidance requires entities to present total comprehensive income, which includes components of net income and components of other comprehensive income, in either a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for us on January 1, 2012. The guidance will change our presentation of comprehensive income, but will not impact our financial statement results.
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3. Regulatory Matters
Retail Rate Case Filing with the Arizona Corporation Commission
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would increase the average retail customer bill approximately 6.6%. The filing is based on a test year ended December 31, 2010, adjusted as described below. On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case. The Settlement Agreement requires the approval of the ACC. Evidentiary hearings on the matter were completed on February 3, 2012. Opening briefs from parties are due February 29, 2012 and responsive briefs are due March 14, 2012. See below for details regarding the Settlement Agreement.
The key financial provisions of APS’s original request included:
· an increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5 million of lower fuel and purchased power costs currently addressed through the PSA (which will decrease base rates);
· a rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;
· the following proposed capital structure and costs of capital:
· a Base Fuel Rate of $0.03242 per kWh based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).
APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision. In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.
Settlement Agreement
The Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate from $0.03757 to $0.03207 per kWh); and (3) the
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transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.
APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the Settlement Agreement.
Other key provisions of the Settlement Agreement include the following:
· An authorized return on common equity of 10.0%;
· A capital structure comprised of 46.1% debt and 53.9% common equity;
· A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
· Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:
· Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
· Deferral of 100% in all years if Arizona property tax rates decrease;
· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant;
· Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
· Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce approximately $5 million annually;
· Modifications to the PSA, including the elimination of the current 90/10 sharing provision;
· Allowing a negative credit that currently exists in the PSA to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
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· Modification of the TCA to streamline the process for future transmission-related rate changes; and
· Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012. As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.
2008 General Retail Rate Case Impacts
On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were effective January 1, 2010. The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:
· Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);
· An authorized return on common equity of 11%;
· A capital structure comprised of 46.2% debt and 53.8% common equity;
· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);
· Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and
· Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.
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Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
On July 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016 timeframe and requesting 2012 RES funding of $129 million to $152 million. On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million. Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 MW under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in 2014 and 2015. In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications. Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.
Demand-Side Management Adjustor Charge (“DSMAC”). The 2008 retail rate case settlement agreement requires APS to submit an annual Energy Efficiency Implementation Plan for review by and approval of the ACC. In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand-side management programs over the current year. Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis. The surcharge allows for the recovery of energy efficiency expenses and any earned incentives.
The ACC previously approved recovery of all 2009 program costs plus incentives. The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2009 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery. As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.
On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed above less the $10 million already being recovered in general rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.
On June 1, 2011, APS filed its 2012 Energy Efficiency Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by
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the settlement agreement related to APS’s 2008 retail rate case (1.5% of total energy resources). APS proposed a budget for 2012 of $90 million. When added to the third and final year of the amortization of 2009 program costs authorized in 2009 and less the $10 million already being recovered in general rates, the proposed 2012 DSMAC would recover approximately $85 million over a twelve month period beginning March 1, 2012. APS expects a decision from the ACC prior to March 31, 2012.
PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
· APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
· under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchased power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate (see “Settlement Agreement” above for information regarding the elimination of this arrangement);
· an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
· the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
· the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
· the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2011 and 2010 (dollars in millions):
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The PSA rate for the PSA year beginning February 1, 2012 is ($0.0042) per kWh as compared to ($0.0057) per kWh for the prior year. Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.
Transmission Rates and Transmission Cost Adjustor. In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. If the Settlement Agreement (discussed above) is approved, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.
Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula. Approximately $38 million of this revenue increase relates to Retail Transmission Charges. The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.
Regulatory Assets and Liabilities
As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of regulatory assets and liabilities to separately reflect current and non-current amounts on the Consolidated Balance Sheets. This presentation is reflected in the tables below.
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The detail of regulatory assets is as follows (dollars in millions):
(a) This asset represents the future recovery in earnings of under-funded pension and other postretirement benefits obligation costs through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.
(b) See “Cost Recovery Mechanisms” discussion above.
(c) There are no regulatory assets for which the ACC has allowed recovery of costs but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
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The detail of regulatory liabilities is as follows (dollars in millions):
(a) In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. See Note 12.
(b) See “Cost Recovery Mechanisms” discussion above.
(c) Subject to a carrying charge.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the currently enacted income tax rates.
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.
In accordance with regulatory requirements, APS investment tax credits are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
The $69 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to be received in the next twelve months.
During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million
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which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
Included in the balances of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $7 million and $16 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated Statement of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2011, we have recognized $4 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of income tax expense are as follows (dollars in thousands):
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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):
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The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. In 2011, APS increased regulatory liabilities by a total of $62 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.
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The components of the net deferred income tax liability were as follows (dollars in thousands):
As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($67 million) and federal net operating losses ($92 million), both of which first begin to expire in 2029, and other federal and state loss carryforwards ($13 million) which first begin to expire in 2014.
5. Lines of Credit and Short-Term Borrowings
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2011 (dollars in millions):
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Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs. During the first quarter of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have otherwise matured in September 2011. During the fourth quarter of 2011, APS and Pinnacle West refinanced the existing credit facilities (as discussed below) that would have otherwise matured in February 2013.
Pinnacle West
On November 4, 2011, Pinnacle West refinanced its $200 million revolving credit facility that would have matured in February 2013, with a new $200 million facility. The new revolving credit facility terminates in November 2016. Interest rates are based on Pinnacle West senior unsecured debt credit ratings.
At December 31, 2011, the Pinnacle West credit facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2011, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.
APS
On February 14, 2011, APS refinanced its $489 million revolving credit facility that would have matured in September 2011, and increased the size of the facility to $500 million. The new revolving credit facility terminates in February 2015. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
On November 4, 2011, APS refinanced its $500 million revolving credit facility that would have matured in February 2013, with a new $500 million facility. The new revolving credit facility terminates in November 2016. APS may increase the amount of the facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use
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the facility to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
The facilities described above are available to support its $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2011, APS had no borrowings outstanding under any of its credit facilities and no outstanding commercial paper.
See “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit.
The table below presents the consolidated credit facilities and amounts available and outstanding and other short-term borrowings as of December 31, 2010 (dollars in millions):
Pinnacle West
On February 12, 2010, Pinnacle West refinanced its $283 million revolving credit facility that would have matured in December 2010, and decreased the size of the facility to $200 million. This facility was refinanced on November 4, 2011.
APS
On February 12, 2010, APS refinanced its $377 million credit facility that would have matured in December 2010, and increased the size of the facility to $500 million. This facility was refinanced on November 4, 2011.
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Debt Provisions
Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’s request, subject to specified parameters and procedures, to increase (a) APS’s short-term debt authorization from 7% of APS’s capitalization to (i) 7% of APS’s capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’s long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. This financing order expires December 31, 2012; however, all debt previously authorized and outstanding on December 31, 2012 will remain authorized and valid obligations of APS.
On November 22, 2011, APS filed a financing application with the ACC requesting an increase in APS’s long-term debt authorization (approximately $4.2 billion) to approximately $5.5 billion in light of the projected financing needed to fund APS’s capital expenditure and maintenance program and other cash requirements. In addition, APS requested authorization to (i) allow for other types of securities providing long-term capital financing, including preferred stock, trust preferred securities or other forms of hybrid securities, and (ii) manage interest rate risks and exposure associated with any long-term or short-term indebtedness authorized by the ACC.
6. Long-Term Debt and Liquidity Matters
All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2011 and 2010 (dollars in thousands):
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(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b) The weighted-average rate for the variable rate pollution control bonds was 0.09% at December 31, 2011 and 0.32% at December 31, 2010.
(c) The weighted-average interest rate was 5.27% at December 31, 2011 and 5.29% at December 31, 2010.
(d) The weighted-average interest rate was 1.794% at December 31, 2011.
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt and capitalized lease requirements (dollars in millions):
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Debt Fair Value
Our long-term debt fair value estimates are based on quoted market prices of the same or similar issues. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):
Credit Facilities and Debt Issuances
Pinnacle West
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91% $175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings. As of December 31, 2011, $50 million of the $175 million term loan facility had been repaid.
APS
On August 25, 2011, APS issued $300 million of 5.05% unsecured senior notes that mature on September 1, 2041. The net proceeds from the sale of the notes were used along with cash on hand to repay at maturity APS’s $400 million aggregate principal amount of 6.375% senior notes due October 15, 2011.
On September 7, 2011, APS entered into a new letter of credit agreement supporting its approximately $27 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B. The agreement expires September 22, 2016.
On December 8, 2011, APS extended a letter of credit agreement supporting its approximately $17 million aggregate principal amount of Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Bonds (Arizona Public Service Company Project), 1998. The agreement expires December 8, 2016.
On January 10, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale will be used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes due March 1, 2012.
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See Lines of Credit and Short-Term Borrowings in Note 5 and “Financial Assurances” in Note 11 for discussion of APS’s other letters of credit.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2011, the ratio was approximately 47% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2011, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.2 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total capitalization remains the same. Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
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7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2011, 2010 and 2009 is as follows (dollars in thousands):
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
(b) In April 2010, Pinnacle West issued 6,900,000 shares of common stock at an offering price of $38.00 per share, resulting in net proceeds of approximately $253 million. Pinnacle West contributed all of the net proceeds from this offering into APS in the form of equity infusions. APS has used these contributions to repay short-term indebtedness, to finance capital expenditures and for other general corporate purposes.
At December 31, 2011, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated
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employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
Pinnacle West also sponsors another postretirement benefit plan (Pinnacle West Capital Corporation Group Life and Medical Plan) for the employees of Pinnacle West and its subsidiaries. This plan provides medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. See Note 14 for discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset. In its 2009 retail rate case settlement, APS received approval to defer a portion of pension and other postretirement benefit cost increases incurred in 2011 and 2012. During 2011, we deferred pension and other postretirement benefit costs of approximately $12 million.
On March 23, 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act (the “Act”). One feature of the Act is the elimination of the tax deduction for prescription drug costs that are reimbursed as part of the Medicare Part D subsidy. Although this tax increase does not take effect until 2013, we are required to recognize the full accounting impact in our financial statements in the period in which the Act is signed. In accordance with accounting for regulated companies, the loss of this deduction is substantially offset by a regulatory asset that will be recovered through future electric revenues. In the first quarter of 2010, Pinnacle West charged regulatory assets for a total of $42 million, with a corresponding increase in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset) (dollars in thousands):
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The following table shows the plans’ changes in the benefit obligations and funded status for the years 2011 and 2010 (dollars in thousands):
The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2011 and 2010 (dollars in thousands):
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The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2011 and 2010 (dollars in thousands):
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2011 and 2010 (dollars in thousands):
The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2012 (dollars in thousands):
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
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In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2012, we are assuming a 7.75% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
Assumed health care cost trend rates above have a significant effect on the amounts reported for the health care plans. In selecting our health care trend rates, we consider past performance and forecasts of health care costs. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
Plan Assets
The Board of Directors has delegated oversight of the plans’ assets to an Investment Management Committee, which has adopted an investment policy. The investment policy’s overall strategy is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plans’ investment policies provide for mixes of investments including long-term fixed income assets and return-generating assets. Long-term fixed income assets are designed to offset changes in benefit obligations due to changes in discount rates and inflation. Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. The determination of total allocation between return-generating and long-term fixed income
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assets is reviewed on at least an annual basis. Other investment strategies include the external management of the plans’ assets, and the prohibition of investments in Pinnacle West securities.
Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury, other government agencies, and corporations. Long-term fixed income assets may also include interest rate swaps, U.S. Treasury futures and other instruments. The investment policy does not provide for a specific mix of long-term fixed income assets, but does require the average credit rating of such assets to be considered upper medium grade or above. The 2011 year-end long-term fixed income asset strategy focused on investments in corporate bonds of primarily investment-grade U.S. issuers and long-term treasuries, with total long-term fixed income assets representing 46% of total pension plan assets and 46% of other benefit plans assets.
Return-generating assets in the pension plan and other benefit plans target a mix of approximately 64% U.S. equities, 27% international equities, and 9% alternative investments. The 2011 year-end U.S. equity holdings were invested primarily in large-cap companies in diverse industries. International equities include investments in emerging and developing markets. Return-generating assets also include investments in securities through commingled funds in common and collective trusts. Alternative investments primarily include investments in real estate. The 2011 year-end return-generating assets represented 54% of total pension plan assets and 54% of other benefit plans’ assets.
See Note 14 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income and equity securities, in addition to investing indirectly in equity securities and real estate through the use of common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate curves. These instruments are classified as Level 2.
The common and collective trusts, which are similar to mutual funds, are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 index). The common and collective equity trusts are valued using net asset value (“NAV”), which is derived from the quoted active market prices of the underlying securities. The plans’ common and collective real estate trust is valued using NAV, which is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2011 the plans were able to transact in the common and collective trusts at NAV and accordingly classify these investments as Level 2. Because the trust’s shares are offered to a limited group of investors, they are not considered to be traded in an active market.
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. Additionally, we obtain and review independent audit reports on the trustee’s internal operating controls and valuation processes.
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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2011, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables.
(b) This category consists primarily of debt securities issued by municipalities.
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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2010, by asset category, are as follows (dollars in thousands):
(a) Represents plan receivables and payables.
(b) This category consists primarily of municipal debt securities issued by municipalities.
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The following table shows the changes in fair value for assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2010 (dollars in thousands):
(a) The return for December 31, 2010 represents the return on assets held as of March 31, 2010, the beginning of the period in which all the assets were transferred out of Level 3.
(b) Transfers into and out of Level 3 are measured at the beginning of the period in which the transfer occurs. Transfers out of Level 3 during 2010 relate to our Real Estate Common and Collective Trust being transferred to a Level 2 investment. During 2009 the Real Estate Common and Collective Trust had special redemption restrictions in place, which limited our ability to transact at the trust’s NAV. During 2010 these special redemption restrictions were lifted, and in 2010 and 2011 we were able to transact at the NAV according to the trust’s contractual redemption policy.
The plans had no investments valued using significant unobservable inputs (Level 3) for the year ended December 31, 2011.
Contributions
The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $160 million in 2014. In 2011, we did not make a contribution to our pension plan. The contribution to our other postretirement benefit plans in 2011 was approximately $19 million. The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year. APS and other subsidiaries fund their share of the contributions. APS’s share of the pension plan contribution was $195 million in 2010. APS’s share of the contributions to the other postretirement benefit plan were $19 million in 2011, $16 million in 2010, and $15 million in 2009.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
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(a) The estimated future other benefit payments take into account the Medicare Part D subsidy.
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2011, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $8 million for 2011, $9 million for 2010 and $9 million for 2009.
9. Leases
We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $21 million in 2011, $23 million in 2010 and $28 million in 2009. APS’s lease expense was $18 million in 2011, $19 million in 2010 and $19 million in 2009.
Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in millions):
In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed variable interest entities for which APS is the primary beneficiary. As the primary
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beneficiary APS consolidated these lessor trust entities. The above lease disclosures exclude the impacts of these sale leaseback transactions, as lease accounting for these agreements is eliminated upon consolidation. See Note 20 for a discussion of VIEs.
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2011 (dollars in thousands):
(a) See Note 20.
(b) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(c) Weighted average of interests.
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11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
APS currently estimates it will incur $122 million (in 2011 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2011, APS had a regulatory liability of $49 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
The Palo Verde participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $18 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $46 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Fuel and Purchased Power Commitments and Purchase Obligations
APS is party to purchase obligations and various fuel and purchased power contracts with terms expiring between 2012 and 2042 that include required purchase provisions. APS estimates the contract requirements to be approximately $580 million in 2012; $528 million in 2013; $556 million in 2014; $535 million in 2015; $503 million in 2016; and $6.8 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
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Of the various fuel and purchased power contracts mentioned above, some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.
The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):
(a) Total take-or-pay commitments are approximately $541 million. The total net present value of these commitments is approximately $401 million.
Renewable Energy Credits
APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $58 million in 2012; $32 million in 2013; $33 million in 2014; $32 million in 2015; $32 million in 2016; and $388 million thereafter.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’s coal mine reclamation obligation was approximately $118 million at December 31, 2011 and $117 million at December 31, 2010.
FERC Market Issues
On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit and ultimately remanded to the FERC for further consideration. On October 3, 2011, the FERC ordered an evidentiary, trial-type hearing before an administrative law judge to address possible activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. FERC rejected a market-wide remedy approach and instead directed that buyers seeking refunds must demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.
This hearing has been held in abeyance to provide an opportunity for the parties to engage in settlement negotiations. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.
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Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan. We estimate that our costs related to this investigation and study will be approximately $1 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time we cannot accurately estimate our total expenditures.
Climate Change Lawsuit
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against nine oil companies, fourteen power companies (including Pinnacle West), and a coal company, alleging that the defendants’ emissions of carbon dioxide contribute to global warming and constitute a public and private nuisance under both federal and state law. The plaintiffs also allege that the effects of global warming will require the relocation of the village, and they are seeking an unspecified amount of monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were granted. The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009, and Pinnacle West filed its reply on June 30, 2010. On January 24, 2011, the defendants filed a motion, which was later granted, to defer calendaring of oral argument until after the United States Supreme Court ruled in a similar nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut.
On June 20, 2011, the Supreme Court issued its opinion in Connecticut holding, among other things, that the Clean Air Act and the EPA actions authorized by the act, which are aimed at controlling greenhouse gas emissions, displace any federal common law right to seek abatement of greenhouse gas emissions from fossil fuel-fired power plants. However, the Court left open the issue of whether such claims may be available under state law. Oral argument in the Kivalina case was heard on November 28, 2011; the parties await the court’s decision. We believe the action in Kivalina is without merit and will continue to defend against both the federal and state claims.
Southwest Power Outage
Regulatory Inquiry. On September 8, 2011 at approximately 3:30PM, a 500 kV transmission line running between the Hassayampa and North Gila substations in southwestern Arizona tripped out of service due to a fault that occurred at a switchyard operated by APS. At the time, an APS employee at the North Gila substation was performing a procedure to remove from service a capacitor bank that was believed not to be operating properly. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.
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Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.8 million customers (1.6 million in the United States and 1.2 million in northern Mexico) were reported to have been affected. Service to all affected APS customers was restored by 9:15PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25AM on September 9.
APS has an internal review of the September 8 events underway. In addition:
· the FERC and the North American Electric Reliability Corporation (“NERC”) are conducting a joint inquiry into the outages; and
· the Western Electricity Coordinating Council (“WECC”) initiated a Detailed Disturbance Analysis process to identify and understand the cause of the events that occurred, and identify and ensure timely implementation of corrective actions.
APS cannot predict the timing, results or potential impacts of any of the inquiries into the September 8 events, or any other claims that may be made as a result of the outages. If violations of NERC Reliability Standards are ultimately determined to have occurred, FERC has the legal authority to assert a possible fine of up to $1 million per violation per day that the violation is found to have been in existence.
Lawsuit. On September 12, 2011, two purported consumer class action complaints were filed in Federal District Court in San Diego, California, naming APS, Pinnacle West and San Diego Gas & Electric Company as defendants and seeking damages for loss of perishable inventory as a result of interruption of electrical service. On December 22, 2011, the plaintiffs voluntarily dismissed both lawsuits. In January 2012, one of the cases was refiled in California Superior Court in San Diego, California. APS and Pinnacle West have numerous defenses against any such complaints, and do not believe that any potential impact will be material.
New Source Review
On October 4, 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the PSD provisions of the Clean Air Act. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS believes the claims in this matter are without merit and will vigorously defend against them. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Financial Assurances
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2011, approximately $44 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund
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the payment of principal and interest of such debt obligations. These letters of credit expire in 2016. APS has also entered into letters of credit to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 20 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire at December 31, 2015, totaling approximately $52 million. Additionally, APS has issued two letters of credit to support the collateral obligations under a certain natural gas tolling contracts entered into with third parties. At December 31, 2011, $30 million of letters of credit were outstanding to support these tolling contract obligations. These letters of credit will expire in 2015 and 2016.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
Pinnacle West sold its investment in APSES on August 19, 2011. Upon the closing of the sale, Pinnacle West was released from its parental guarantee and surety bond obligations related to the APSES business. Pinnacle West has also issued parental guarantees and surety bonds for APS which were not material at December 31, 2011.
12. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. In the first quarter of 2011, a new decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.
Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.
Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.
The following schedule shows the change in our asset retirement obligations for 2011 and 2010 (dollars in millions):
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In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 3.
13. Selected Quarterly Financial Data (Unaudited)
Consolidated quarterly financial information for 2011 and 2010 is as follows (dollars in thousands, except per share amounts):
(a) The March 31, 2011 results were adjusted for the effect of reclassifications for discontinued operations (see Note 21). The adjustments resulted in a reduction in operating revenues of $10,728, a reduction in operations and maintenance of $1,457, a reduction in operating income of $1,357, a decrease in income taxes of $356, and a decrease in income from continuing operations of $1,043.
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14. Fair Value Measurements
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange-traded equities, exchange-traded derivative instruments, cash equivalents, and investments in U.S. Treasury securities.
Level 2 - Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. This category also includes investments in common and collective trusts and commingled funds that are redeemable and valued based on NAV.
Level 3 - Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where models are required due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. Option contracts are valued using a Black-Scholes option pricing model that incorporates commodity prices, volatilities, and correlation factors.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
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Recurring Fair Value Measurements
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans.
Cash Equivalents
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.
Risk Management Activities - Derivative Instruments
Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. Certain option contracts are valued using option valuation models which utilize both observable and unobservable inputs such as volatility rates and correlation factors. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions and the use of option valuation models with significant unobservable inputs.
Investments Held in our Nuclear Decommissioning Trust
The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued based on NAV, which is primarily derived from the quoted active market prices of the underlying equity securities. We may transact in these commingled funds on a semi-monthly basis at the NAV, and accordingly classify these investments as Level 2. The commingled funds, which are similar to mutual funds, are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 index. Because the commingled fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.
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Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV.
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies including mortgage-backed instruments are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield and interest rate curves. These instruments are classified as Level 2. Whenever possible multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.
Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services that utilize the valuation methodologies described to determine fair market value. We assess these valuations and verify that pricing can be supported by actual recent market transactions. Additionally, we obtain and review independent audit reports on the trustee’s operating controls and valuation processes. See Note 23 for additional discussion about our nuclear decommissioning trust.
Fair Value Tables
The following table presents the fair value at December 31, 2011 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
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(a) Primarily consists of heat rate options and other long-dated electricity contracts.
(b) Represents counterparty netting, margin and collateral. See Note 18.
(c) Represents nuclear decommissioning trust net pending securities sales and purchases.
The following table presents the fair value at December 31, 2010 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
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(a) Primarily consists of long-dated electricity contracts.
(b) Represents counterparty netting, margin and collateral. See Note 18.
(c) Represents nuclear decommissioning trust net pending securities sales and purchases.
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The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2011 and 2010 (dollars in millions):
Amounts included in earnings are recorded in either regulated electricity segment revenue or regulated electricity segment fuel and purchased power depending on the nature of the underlying contract.
Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are generally related to changes in the significance of reserves applied to derivative instruments. Transfers out of Level 3 may also be related to our long-dated energy transactions as they move closer to delivery and quoted prices become available.
Nonrecurring Fair Value Measurements
For the periods ended December 31, 2011 and 2010, we had no assets or liabilities measured at fair value on a nonrecurring basis.
Financial Instruments Not Carried at Fair Value
The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. For our long-term debt fair values see Note 6.
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15. Earnings Per Share
The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2011, 2010 and 2009:
Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 811,000 shares in 2011, 565,000 shares in 2010 and 103,000 shares in 2009. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 109,864,243 shares in 2011, 107,137,785 shares in 2010 and 101,263,795 shares in 2009.
For the year ended 2011, there were no common stock options that were excluded from the computation of diluted earnings per share as a result of the options’ exercise prices being 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 192,542 during 2010 and 572,301 during 2009.
16. Stock-Based Compensation
Pinnacle West grants long-term incentive awards under the 2007 long-term incentive plan (“2007 Plan”) in the form of Stock Grants, Restricted Stock Units, Restricted Stock and Performance Shares and may grant incentive and stock options, stock appreciation rights, dividend equivalents and stock. The 2007 Plan, effective May 23, 2007, provides a maximum of 8 million common shares to be available for grant to eligible employees and members of the Board of Directors.
Restricted Stock Unit Awards and Stock Grants
Stock grants issued to non-officer members of the Board of Directors in 2009 under the 2007 Plan were paid in fully transferable shares of stock. The 2011 and 2010 grants issued under the 2007 Plan provided Directors the option to elect to receive a stock grant, or to defer receipt until a later date and receive restricted stock units in lieu of the stock grant. Directors who elect to defer may elect to receive payment in either (1) stock, or (2) 50% in cash and 50% in stock. The Director may elect to receive payments either (1) as of the last business day of the month following the month in which the Director separates from services on the Board, or (2) as of a date specified by the Director,
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which date must be after December 31 of the year in which the grant was received. The deferred restricted stock units accrue dividend rights equal to the amount of dividends the Director would have received if the Director had directly owned one share of common stock for each restricted stock unit held plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either (1) stock, or (2) 50% stock and 50% cash.
Restricted stock units have been granted to officers and key employees under the 2007 Plan in each year since 2007. From 2007 through 2009, officers and key employees elected to receive payment in either cash or in fully transferable shares of stock, in exchange for each restricted stock unit on pre-established valuation dates. For 2010 and 2011, participants elected to receive payment in either stock, or 50% cash and 50% stock.
Restricted stock unit awards vest and settle over a four-year period. In addition, officers and key employees accrue dividend rights on the vested restricted stock units, equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested restricted stock units from the date of grant to the date of payment plus interest compounded quarterly. The dividends and interest for the 2007 through 2009 awards are paid in cash. The dividends and interest for the 2010 and 2011 awards are paid in the same form as the restricted stock unit payment election. Restricted stock unit awards are accounted for as a liability award, with compensation cost initially calculated on the date of grant using Pinnacle West’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately.
An additional grant of restricted stock unit awards was made to officers of the Company on February 15, 2011, payable solely in shares of common stock upon the officer’s retirement or other separation of employment. This award will vest 50% on February 15, 2013, 25% on February 15, 2014 and 25% on February 15, 2015, provided that the officer remains employed on such date. The officers will also accrue notional dividends equal to the amount of dividends that an officer would have received if the officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held by the officer from the grant date to each dividend payment date. Each additional restricted stock unit will proportionally vest on the same remaining vesting schedule that applies to the original restricted stock unit.
The following table is a summary of granted restricted stock units and stock grants and the weighted average fair value for the years ended 2011, 2010 and 2009:
(a) weighted average fair value
The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2011 and changes during the year. This table represents only the stock portion of restricted stock units, per the election on payment discussed in the paragraph above:
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The amount of cash required to settle the payments on restricted stock units is (dollars in millions):
Performance Share Awards
Performance share awards have been granted to officers and key employees under the 2007 Plan since 2008. Performance share awards contain two performance elements criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.
The 2009 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth of relevant companies in a specified utilities index, and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 150% of the target award. Shares received include dividend rights paid in cash equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.
The 2011 and 2010 performance share grant criteria is based 50% upon the percentile ranking of Pinnacle West’s total shareholder return at the end of the three-year performance period as compared with the total shareholder return of all relevant companies in a specified utilities index and the other 50% based upon six non-financial separate performance metrics. The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that they would have received had they directly owned stock equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.
Performance share awards are accounted for as a liability awards, with compensation cost initially calculated on the date of grant using Pinnacle West’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately. Management also evaluates the probability of meeting the performance criteria at each balance sheet date. If the performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
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The following table is a summary of the performance shares granted and the weighted average fair value for the years ended 2011, 2010 and 2009:
(a) weighted average grant date fair value
The following table is a summary of the status of performance shares, as of December 31, 2011 and changes during the year:
Retention Units
The retention unit awards have fully vested and settled on January 4, 2010; for any employee that was eligible to retire before that date, the employee’s retention units vested by retirement date and the compensation expense was recognized by retirement eligibility. Retention unit awards were granted to key employees in 2006 and 2007. Each retention unit award represented the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. Each retention unit award vested and settled in equal annual installments over a four-year period. In addition, the employee received a cash payment equal to the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. As this award was accounted for as a liability award, compensation costs, initially measured based on Pinnacle West’s stock price on the grant date, were remeasured at each balance sheet date, using Pinnacle West’s closing stock price.
The amount of cash to settle the payment on the first business day of 2010 was $1.3 million, and 2009 was $1.1 million.
Incentive Shares
On January 21, 2009, the Human Resources Committee approved under the 2007 Plan payment of 2008 incentive awards to officers in the form of a Pinnacle West common stock grant. A total of 138,756 shares were issued for this stock grant with a grant date fair value of $32.58 per share. The stock grant was included in stock compensation expense in 2008.
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Stock Options
Pinnacle West has not granted stock options since 2004. Currently outstanding stock option grant terms cannot be longer than 10 years and options cannot be repriced during their terms.
The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2011:
Cash received from options exercised under our share-based payment arrangements was $1.8 million for 2011, $4.6 million for 2010, and $3 million for 2009. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements were immaterial for all years.
The intrinsic value of options exercised was immaterial for all years.
As of December 31, 2011, there was $20.5 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2.2 years. The total fair value of shares vested during 2011 was $14.4 million, 2010 was $11 million, and 2009 was $10 million.
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $23 million in 2011, $15 million in 2010, and $5 million in 2009. The compensation cost that Pinnacle West has capitalized is immaterial for all years. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $9 million in 2011, $6 million in 2010, and $2 million in 2009. APS’s share of compensation cost that has been charged against income was $22 million in 2011, $15 million in 2010, and $4 million in 2009.
Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares except to satisfy tax withholding obligations upon the vesting of restricted stock during 2011.
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17. Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.
Financial data for 2011, 2010 and 2009 is provided as follows (dollars in millions):
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(a) All other activities relate to SunCor, APSES and El Dorado. Income from discontinued operations for 2011 is primarily related to the sale of our investment in APSES. Income from discontinued operations for 2010 is primarily related to the APSES sale of its district cooling business. Loss from discontinued operations for 2009 is primarily related to real estate impairment charges at SunCor (see Note 22). None of these segments is a reportable business segment.
18. Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria are designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments
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may not meet the specific hedge accounting requirements and are not designated as accounting hedges. Contracts that have the same terms (quantities and delivery points) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value; see Note 14 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchase and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged item are correlated and is measured based on the relative changes in fair value of the derivative instrument contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of accumulated other comprehensive income (“AOCI”) and reclassified into earnings in the same period during which the hedged transaction affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment. As of December 31, 2011, we hedged the majority of certain exposures to the price variability of commodities for a maximum of 39 months.
APS defers for future rate treatment approximately 90% of unrealized gains and losses on certain derivatives, pursuant to the PSA mechanism, that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
As of December 31, 2011, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
Gains and Losses from Derivative Instruments
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedges during the year ended December 31, 2011 and December 31, 2010 (dollars in thousands):
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(a) During the year ended December 31, 2011 and 2010, we had no amounts reclassified from AOCI to earnings related to discontinued cash flow hedges.
During the next twelve months, we estimate that a net loss of $80 million before income taxes will be reclassified from AOCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, certain of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.
The following table provides information about gains and losses from derivative instruments not designated as accounting hedges during the year ended December 31, 2011 and December 31, 2010 (dollars in thousands):
Fair Values of Derivative Instruments in the Consolidated Balance Sheets
The following table provides information about the fair value of our risk management activities reported on a gross basis. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. These amounts are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets. Amounts are as of December 31, 2011 (dollars in thousands):
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(a) Collateral relates to non-derivative instruments or derivative instruments that qualify for a scope exception.
(b) Other represents counterparty netting, options, and other risk management contracts.
The following table provides information about the fair value of our risk management activities reported on a gross basis at December 31, 2010 (dollars in thousands):
(a) Includes $11 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception.
(b) Includes $1 million of collateral relating to non-derivative instruments or derivative instruments that qualify for a scope exception.
(c) Other represents counterparty netting, options, and other risk management contracts.
Credit Risk and Credit Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management contracts with many counterparties, including two counterparties for which our exposure represents approximately 80% of Pinnacle West’s $80 million of risk management assets as of December 31, 2011. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great
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majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2011 (dollars in millions):
(a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the footnote above.
We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features which could also require us to post additional collateral of approximately $194 million if our debt credit ratings were to fall below investment grade.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2011, 2010 and 2009 (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20. Palo Verde Sale Leaseback Variable Interest Entities
In 1986, APS entered into agreements with three separate VIE lessor trusts in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will pay approximately $49 million per year for the years 2011 to 2015 related to these leases. The leases do not contain fixed price purchase options or residual value guarantees. However, the lease agreements include fixed rate renewal periods which may have a significant impact on the VIEs’ economic performance. We have concluded that these fixed rate renewal periods may give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. In addition to the fixed rate renewal periods, our primary beneficiary analysis also considered that APS is the operating agent for Palo Verde, has fair value purchase options, and is obligated to decommission the leased assets.
As a result of consolidation we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for 2011, 2010 and 2009 of $28 million, $20 million and $19 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes to our Consolidated Statements of Cash Flows, but does not impact net cash flows.
Our Consolidated Balance Sheets at December 31, 2011 and December 31, 2010 include the following amounts relating to the VIEs (in millions):
Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS under the lease.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants, assume the VIEs’ debt, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2011, APS would have been required to pay the noncontrolling equity participants approximately $141 million and assume $97 million of debt. Since APS consolidates these VIEs, the debt APS would be required to assume is already reflected in our Consolidated Balance Sheets.
For regulatory ratemaking purposes the leases continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
21. Discontinued Operations
SunCor - In 2009, our real estate subsidiary, SunCor, began disposing of its homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt. All activity for the income statement and prior comparative period income statement amounts are included in discontinued operations. In 2010 and 2009, SunCor recorded real estate impairment charges (see Note 22). SunCor’s asset sales resulted in no gain for 2010 and 2009 due to the impairment charges discussed above. At December 31, 2011, SunCor had approximately $9 million of assets on its balance sheet, including $7 million of intercompany receivables, and $2 million of other assets. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. We do not expect SunCor’s bankruptcy to have a material impact on Pinnacle West’s financial position, results of operations, or cash flows.
APSES - On August 19, 2011, Pinnacle West sold its investment in APSES. The sale resulted in an after-tax gain from discontinued operations of approximately $10 million. In June 2010, APSES sold its district cooling business. As a result of that sale, we recorded an after-tax gain from discontinued operations of approximately $25 million. Prior period income statement amounts related to these sales and the associated revenues and costs are reflected in discontinued operations.
The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009 (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) Includes a tax benefit recognized by the parent company in accordance with an intercompany tax sharing agreement of $1 million for the year ended December 31, 2011, $4 million for the year ended December 31, 2010, and $113 million for the year ended December 31, 2009.
22. Real Estate Impairment Charge
In 2009, SunCor undertook and completed a review of its assets and strategies within its various markets as a result of the distressed conditions in real estate and credit markets. Based on the results of the review, on March 27, 2009, SunCor’s Board of Directors authorized a series of strategic transactions to dispose of SunCor’s homebuilding operations, master-planned communities, land parcels, commercial assets and golf courses in order to reduce SunCor’s outstanding debt. As a result, SunCor took impairment charges in 2009 and 2010. There have been no additional impairments in 2011. All SunCor’s operations are reflected in discontinued operations (see Note 21). The detail of the impairment charge is as follows (dollars in millions, and before income taxes):
23. Nuclear Decommissioning Trust
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per their stated investment guidelines. The trust
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2011 and December 31, 2010 (dollars in millions):
(a) Net payables relate to pending securities sales and purchases.
(a) Net payables relate to pending securities sales and purchases.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
(a) Proceeds are reinvested in the trust.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2011 is as follows (dollars in millions):
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, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 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 24, 2012
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 consolidated balance sheets of Arizona Public Service Company and subsidiary (the “Company”) as of December 31, 2011 and 2010, 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, 2011. 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, 2011, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Arizona Public Service Company and subsidiary as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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 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, 2011, 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 24, 2012
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED 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 Consolidated Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Consolidated Financial Statements.
Certain notes to Arizona Public Service Company’s consolidated 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 consolidated 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 CONSOLIDATED 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’s taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted tax rates.
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from ITCs and the change in income tax rates.
In accordance with regulatory requirements, APS investment tax credits are deferred and are amortized over the life of the related property, with such amortization applied as a credit to reduce current income tax expense in the statement of income.
During the first quarter of 2010, the Company reached a settlement with the IRS with regard to the examination of tax returns for the years ended December 31, 2005 through 2007. As a result of this settlement, net uncertain tax positions decreased $62 million, including approximately $3 million which decreased our effective tax rate. Additionally, the settlement resulted in the recognition of net interest benefits of approximately $4 million through the effective tax rate.
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2011, 2010 and 2009 were approximately $8 million, $6 million and $15 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years prior to 2006. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next twelve months.
We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of income as income tax expense. The amount of interest recognized in the Statements of Income related to unrecognized tax benefits was a pre-tax expense of $3 million for 2011, a pre-tax benefit of $2 million for 2010 and a pre-tax expense of $2 million for 2009.
The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was $9 million as of December 31, 2011, $6 million as of December 31, 2010 and $8 million as of December 31, 2009. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2011, we have recognized $4 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of APS’s income tax expense are as follows (dollars in thousands):
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
The following chart compares APS’s pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. In 2011, APS increased regulatory liabilities by a total of $62 million, with a corresponding decrease in accumulated deferred income tax liabilities to reflect the impact of this change in tax law.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars in thousands):
As of December 31, 2011, the deferred tax assets for credit and loss carryforwards relate to federal general business credits ($60 million) and federal net operating losses ($37 million), both of which first begin to expire in 2031, and other federal and state loss carryforwards ($10 million) which first begin to expire in 2013.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2011 and 2010 is as follows (dollars in thousands):
S-3. Other Income and Other Expense
The following table provides detail of APS’s other income and other expense for 2011, 2010 and 2009 (dollars in thousands):
(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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, 2011. 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’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of December 31, 2011. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s 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 77 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 153 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 78 of this report and “Report of Independent Registered Public Accounting Firm” on page 154 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’s internal control over financial reporting occurred during the fiscal quarter ended December 31, 2011 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s 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 16, 2012 (the “2012 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 “Directors’ Compensation,” “Report of the Human Resources Committee,” “Executive Compensation,” and “Human Resources Committee Interlocks and Insider Participation” in the 2012 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” and “Securities Authorized for Issuance Under Executive Compensation Plans” in the 2012 Proxy Statement.
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 2012 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
Reference is hereby made to “Accounting and Auditing Matters - Audit Fees and - Pre-Approval Policies” in the 2012 Proxy Statement.
APS
The following fees were paid to APS’s 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 employee benefit plan audits performed in 2011 and 2010.
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’s 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.
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.
e
Furnished herewith as an 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 24, 2012
/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
Principal Executive Officer and Director
February 24, 2012
(Donald E. Brandt, Chairman
of the Board of Directors, President
and Chief Executive Officer)
/s/ James R. Hatfield
Principal Financial Officer
February 24, 2012
(James R. Hatfield,
Senior Vice President and
Chief Financial Officer)
/s/ Denise R. Danner
Principal Accounting Officer
February 24, 2012
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)
/s/ Edward N. Basha, Jr.
Director
February 24, 2012
(Edward N. Basha, Jr.)
/s/ Susan Clark-Johnson
Director
February 24, 2012
(Susan Clark-Johnson)
/s/ Denis A. Cortese
Director
February 24, 2012
(Denis A. Cortese)
/s/ Michael L. Gallagher
Director
February 24, 2012
(Michael L. Gallagher)
/s/ Pamela Grant
Director
February 24, 2012
(Pamela Grant)
/s/ Roy A. Herberger, Jr.
Director
February 24, 2012
(Roy A. Herberger, Jr.)
/s/ Dale E. Klein
Director
February 24, 2012
(Dale E. Klein)
/s/ Humberto S. Lopez
Director
February 24, 2012
(Humberto S. Lopez)
/s/ Kathryn L. Munro
Director
February 24, 2012
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom
Director
February 24, 2012
(Bruce J. Nordstrom)
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 24, 2012
/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
Principal Executive Officer and Director
February 24, 2012
(Donald E. Brandt, Chairman
of the Board of Directors and
Chief Executive Officer)
/s/ James R. Hatfield
Principal Financial Officer
February 24, 2012
(James R. Hatfield,
Senior Vice President and Chief
Financial Officer)
/s/ Denise R. Danner
Principal Accounting Officer
February 24, 2012
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)
/s/ Edward N. Basha, Jr.
Director
February 24, 2012
(Edward N. Basha, Jr.)
/s/ Susan Clark-Johnson
Director
February 24, 2012
(Susan Clark-Johnson)
/s/ Denis A. Cortese
Director
February 24, 2012
(Denis A. Cortese)
/s/ Michael L. Gallagher
Director
February 24, 2012
(Michael L. Gallagher)
/s/ Pamela Grant
Director
February 24, 2012
(Pamela Grant)
/s/ Roy A. Herberger, Jr.
Director
February 24, 2012
(Roy A. Herberger, Jr.)
/s/ Dale E. Klein
Director
February 24, 2012
(Dale E. Klein)
/s/ Humberto S. Lopez
Director
February 24, 2012
(Humberto S. Lopez)
/s/ Kathryn L. Munro
Director
February 24, 2012
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom
Director
February 24, 2012
(Bruce J. Nordstrom)