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.
Pinnacle West’s other operating subsidiary is El Dorado. Additional information related to this business 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 1.2 million customers. We own or lease 6,394 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 2013, no single purchaser or user of energy accounted for more than 1.1% 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 type during 2013 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 63% of Four Corners Units 4 and 5 following the acquisition of SCE’s interest in Units 4 and 5 described below. As of December 30, 2013, APS retired Units 1, 2 and 3. APS has a total entitlement from Four Corners of 970 MW.
On November 8, 2010, APS and SCE entered into an asset purchase agreement (the “Asset Purchase Agreement”) providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners, allowing APS to acquire 739 MW from SCE. On December 30, 2013, APS and SCE closed this transaction. The final purchase price for SCE’s interest was approximately $182 million, subject to certain minor post-closing adjustments.
In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction. On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners. If approved, these would result in an average bill impact to residential customers of approximately 2%. APS cannot predict the outcome of this request.
Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031 (the “2016 Coal Supply Agreement”). El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation. When APS ultimately acquires a right to EPE’s interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.
The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments 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 are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a Prevention of Significant Deterioration (“PSD”) permit from EPA to install selective catalytic reduction (“SCR”) control technology at Four Corners, as described below under “Environmental Matters - EPA Environmental Regulation.” APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.
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 and state governments and private landholders. The Cholla coal contract runs through 2024. 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, with extension rights through 2026. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. The current lease expires in 2019.
These coal-fueled 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-fueled facilities. See Note 11 for information regarding APS’s coal mine reclamation obligations.
Nuclear
Palo Verde Nuclear Generating Station - Palo Verde is a 3-unit nuclear power plant located approximately 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and approximately 17% of Unit 2. In addition, APS leases approximately 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 approximately 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 expire 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 was required to give notice to the respective lessor trusts between December 31, 2010 and December 31, 2012 if it wished to retain the leased assets (without specifying whether it would purchase the leased assets or extend the leases) or return the leased assets to the lessor trusts. On December 31, 2012, APS gave notice to the respective lessor trusts informing them it will retain the leased assets. APS must give notice to the respective lessor trusts by June 30, 2014 notifying them which of the purchase or lease renewal options it will exercise. We are currently analyzing these options. See Note 19 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, and issued renewed operating licenses for each of the three units in April 2011, which extended 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 100% of Palo Verde’s requirements for uranium concentrates through 2017, 90% of its requirements in 2018 and 45% of its requirements in 2019-2020. The participants have also contracted for all of Palo Verde’s conversion services through 2016, 95% of its requirements in 2017-2018 and 45% of its requirements in 2019-2020; 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 (the “Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. APS is directly and indirectly involved in several legal proceedings related to DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high level waste.
APS Lawsuit for Breach of Standard Contract - In December 2003, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a lawsuit against DOE in the U.S. Court of Federal Claims for damages incurred due to DOE’s breach of the Standard Contract. The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded $30.2 million in damages to APS and the Palo Verde participants for costs incurred through December 2006.
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. That lawsuit is presently pending in the Court of Federal Claims.
The One-Mill Fee - In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee is recovered by APS in its retail rates. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE (“Secretary”) with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the D.C. Circuit reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the D.C. Circuit’s order. On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval.
DOE’s Construction Authorization Application for Yucca Mountain - 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, the DOE submitted its Yucca Mountain construction authorization application to the NRC, but in March 2010, the DOE filed a motion to dismiss with prejudice the Yucca Mountain construction authorization application. Several interested parties have also intervened in the NRC proceeding. Additionally, a number of interested parties filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the D.C. Circuit. In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.
Waste Confidence - On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and
permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (“Waste Confidence Decision”).
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012. In September 2013, the NRC issued its draft environmental impact statement to support an updated Waste Confidence Decision. In October 2013, the NRC began a series of nationwide public meetings to receive stakeholder input on the draft environmental impact statement. The NRC’s meeting schedule was completed in December 2013. The NRC Commissioners have instructed the staff to issue the final generic environmental impact statement and rule by no later than September 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, Palo Verde does not have any licensing actions pending with the NRC.
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.
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 20 for additional information about APS’s nuclear decommissioning trusts.
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, an earthquake measuring 9.0 on the Richter Scale occurred off the coast of Japan causing a series of seven tsunamis. As a result, the Fukushima Daiichi Nuclear Power Station experienced damage.
Following the earthquake and tsunamis, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, we cannot predict the ultimate financial or operational impacts on Palo Verde or APS; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%).
Natural Gas and Oil Fueled Generating Facilities
APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near Palo Verde; Ocotillo, located in Tempe (discussed below); 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 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 3,179 MW. Gas for these plants is financially hedged up to three years in advance of purchasing and the gas is generally purchased one month prior to delivery. 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.
Ocotillo is a 330 MW 4-unit gas plant. In early 2014, APS announced a roughly $600-$700 million project to modernize the plant, which will involve retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines. In total, this will increase the capacity of the site by 290 MW, to 620 MW, with completion targeted for summer 2018.
Solar Facilities
To date, APS has begun operation of 118 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 approximately 4 MW of renewable energy. This fleet of solar systems includes a 3 MW facility located at the Prescott Airport and 1 MW of small solar in various locations across Arizona. APS has also developed 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 owns, operates and receives energy from approximately 1 MW of solar photovoltaic distributed energy systems located within a certain test area in Flagstaff, Arizona. Additionally, APS owns 14 MW of
solar photovoltaic systems installed across Arizona through the ACC-approved Schools and Government Program.
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 portion of APS’s purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. (See Note 17.) 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 table 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 90 MW in each of 2013 and 2014.
(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 may be increased in 5 MW increments in each of 2014, 2015 and 2016 and 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.
(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 2013 peak one-hour demand on its electric system was recorded on July 8, 2013 at 6,927 MW, compared to the 2012 peak of 7,207 MW recorded on August 8, 2012. APS’s reserve margin at the time of the 2013 peak demand, calculated using system load serving capacity, was 27%. Excluding certain contractual rights to call on additional capacity on short notice, which APS may use in the event of unusual weather or unplanned outages, the 2013 reserve margin was 17%. APS anticipates the reserve margin for 2014 will be approximately 34% or 24% excluding contractual rights to call on additional capacity. APS expects that our reserve margins will decrease over the next three years and that additional conventional resources will be needed around 2017.
Future Resources and Resource Plan
Under the ACC’s resource planning rule, APS will file by April 1 of each even year its resource plans for the next fifteen-year period. 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. APS will be filing its next resource plan by April 1, 2014.
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 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025. In APS’s 2009 retail rate case settlement agreement (the “2009 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 approximately 12% of retail sales, by year-end 2015, which is more than double the 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, such as rooftop solar systems). 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 4.5% in 2014. The following table summarizes the RES requirement standard (not including the additional commitment required by the 2009 Settlement Agreement) and its timing:
Renewable Energy Portfolio. To date, APS has a diverse portfolio of existing and planned renewable resources totaling 1175 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 1074 MW are currently in operation and 101 MW are under contract for development or are under construction. Renewable resources in operation include 137 MW of facilities owned by APS, 629 MW of long-term purchased power agreements, and an estimated 308 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 is developing owned solar resources through the AZ Sun Program. Under this program to date, APS estimates its investment commitment will be approximately $695 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) Under the AZ Sun Program, an additional 20 MW has been approved to be contracted, but is not included in the table above since it is not yet under contract. Another 30 MW is possible under AZ Sun, but has not yet been approved.
(b) Includes Flagstaff Community Power Project and APS School and Government Program.
(c) Distributed generation is produced in DC and is converted to AC for reporting purposes.
Demand Side Management
In December 2009, Arizona regulators 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. The ACC initiated its Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard (“EES”) 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 2009 Settlement Agreement).
Government Awards
Through the American Recovery and Reinvestment Act of 2009 (“ARRA”) and other DOE initiatives, the Federal government made a number of programs available for utilities to develop renewable resources, improve reliability and create jobs. APS continues its work on a $3 million non-ARRA award for a high penetration photovoltaic generation study related to the Community Power Project in Flagstaff, Arizona. This award will conclude during 2015 and is 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 rooftop solar panels to meet or supplement their energy needs.
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 an increasing 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.
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. Although some very limited retail competition existed in APS’s service territory in
1999 and 2000, 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.
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 May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are expected to be held in 2014.
Wholesale
FERC regulates rates for wholesale power sales and transmission services. (See Note 3 for information regarding APS’s transmission rates.) During 2013, approximately 5.4% 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. There have been no recent attempts by Congress to pass legislation that would regulate greenhouse gas (“GHG”) emissions, and it is unclear if and when the 113th Congress will consider a climate change bill. In the event climate change legislation ultimately passes, 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 GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted.
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 GHGs in Arizona, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013 and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA.
We continue to monitor 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 prior participant in Four Corners, indicated that SB 1368 may prohibit it from making emission control expenditures at the plant and, as a result, SCE sold its entire 48% interest in each of Units 4 and 5 of Four Corners to APS on December 30, 2013. (See “Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Four Corners” above for details of the sale of SCE’s interest in Four Corners to APS.)
Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. This determination was made in response to a 2007 United States Supreme Court ruling that GHGs fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, EPA has the authority to regulate GHG emissions of new motor vehicles under the Clean Air Act. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. EPA issued a rule under the Clean Air Act, known as the “tailoring rule,” establishing new GHG emissions thresholds that determine when sources, including power plants, must obtain air operating permits or New Source Review permits. “New Source Review,” or “NSR,” 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 applicable to power plants in January 2011. Several groups filed lawsuits challenging EPA’s endangerment finding and the tailoring rule, but the D.C. Circuit upheld these rules. Petitioners asked
the United States Supreme Court to reverse all or part of the appeals court’s decision upholding EPA’s GHG rules. On October 15, 2013, the Supreme Court granted these petitions limiting the question it would review to whether EPA permissibly determined that its regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit such gasses, including power plants. The Court is expected to issue its decision in the case no later than mid-2014.
APS does not expect that any resulting Supreme Court decision or the tailoring rule will have a significant impact on its current operations. The rule will require APS to consider the impact of GHG emissions as part of its traditional NSR analysis for new sources and major modifications to existing plants.
On June 25, 2013, President Obama unveiled his Climate Action Plan addressing his plans to reduce GHG emissions in the United States. While the plan identifies a wide range of strategies for cutting GHG emissions, most important to APS and the electric utility industry is the implementation of carbon pollution standards for new, modified, and existing fossil-fired electric generating units. Concurrent with the President’s speech, the White House issued a Presidential Memorandum directing EPA to use its existing authorities under the Clean Air Act to develop GHG emission standards for new, modified, and existing power plants. The Presidential Memorandum directs EPA to propose GHG emission standards for modified and existing units by June 1, 2014 and to finalize them by June 1, 2015. The memorandum further directed EPA to reissue proposed standards of performance for new power plants by September 20, 2013 and to finalize them in a timely fashion.
Consistent with President Obama’s June 2013 directive, pursuant to its authority under the Clean Air Act and its endangerment finding, on September 20, 2013, EPA issued a proposed rule, which would establish New Source Performance Standards (“NSPS”) for new fossil-fired power plants. Once finalized, APS does not expect that the GHG NSPS will have any material impact on its current operations. EPA indicated in its proposal that the rule will not apply to modified or reconstructed electric generating units, which are to be addressed in a subsequent rulemaking. We cannot currently predict the shape of any final rules or standards for existing fossil-fired power plants or assess how they might potentially impact the company. APS will continue to monitor these standards as they are developed.
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 solar, wind, geothermal, biogas, and biomass, and we expect the percentage of renewable energy in our resource portfolio to increase over the coming years.
APS prepares an inventory of GHG emissions from its operations. This inventory is reported to EPA under the EPA GHG Reporting Program and is voluntarily communicated to the public in Pinnacle West’s 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.
EPA Environmental Regulation
Regional Haze Rules. In 1999, 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, EPA) to determine what pollution control technologies constitute the Best Available Retrofit Technology (“BART”) for certain older major stationary sources, including fossil-fired power plants. 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 EPA’s final BART determinations (and Cholla’s obligations to comply with ADEQ’s and EPA’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 in early 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 State Implementation Plan (“SIP”) for Cholla and other sources in Arizona in early 2011.
On December 2, 2011, EPA provided notice of a proposed consent decree to address a lawsuit filed by a number of environmental non-governmental organizations, which alleged that EPA failed to promulgate Federal Implementation Plans (“FIPs”) for states that have not yet submitted all or part of the required regional haze SIPs. In accordance with the consent decree, on December 5, 2012, EPA issued a final BART rule applicable to Cholla. EPA approved ADEQ’s BART emissions limits for sulfur dioxide (“SO2”) and emissions of particulate matter (“PM”), but added a SO2 removal efficiency requirement of 95%. In addition, EPA disapproved ADEQ’s BART determinations for oxides of nitrogen (“NOx”) and promulgated a FIP establishing a new, more stringent “bubbled” NOx emission rate applicable to the two BART-eligible Cholla units owned by APS and the other BART-eligible unit owned by PacifiCorp. In order to comply with this new rate, APS will be required to install SCR control technology on all three of the Cholla units. APS’s total costs for these post-combustion NOx controls would be approximately $200 million. This amount is not included in our current estimates for environmental capital expenditures in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7. Under the FIP, APS has five years from December 2012 to complete installation of the equipment and achieve the BART emission limit for NOx.
APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. We expect briefing in the case to be completed in February 2014.
Four Corners. On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance options. On December 30, 2013, APS notified EPA that the Four Corners participants selected the BART alternative, which required APS to retire Four Corners Units 1-3 by January 1, 2014 and install and operate SCR control technology on Units 4
and 5 by July 31, 2018. Consistent with this alternative, APS retired Four Corners Units 1-3 on December 30, 2013. APS’s 63% share of the costs for these controls is estimated to be approximately $350 million. Approximately half of these costs are included in the capital expenditure estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7 because APS expects to incur that portion of the costs during the 2014 through 2016 timeframe. For PM emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBtu and a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.
On October 22, 2012, WildEarth Guardians filed a petition for review in the United States Court of Appeals for the Ninth Circuit alleging that EPA violated the Endangered Species Act (“ESA”) when it promulgated the final Four Corners BART FIP. The court granted APS’s motion for leave to intervene as a defendant in the case. A decision is expected before the end of 2014. We cannot currently predict the outcome of this case or whether such outcome will have a material adverse impact on our financial position, results of operations, or cash flows.
Navajo Plant. On January 18, 2013, EPA issued a proposed BART rule for the Navajo Plant, which would require installation of SCR technology in order to achieve a new, more stringent plant-wide NOx emission limit. Under the proposal, the Navajo Plant participants would have up to five years after EPA issues its final determinations to achieve compliance with the BART requirements. APS’s total costs for post-combustion NOx controls could be up to approximately $200 million. The majority of these costs are not included in the capital expenditure estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7 because APS expects to incur such costs in years following 2016. EPA’s proposal also includes an “Alternative to BART,” which would provide the Navajo Plant with additional time to install the SCR technology. Under this “better than BART” alternative, the Navajo Plant participants would be required to install SCR technology on one unit per year in each of 2021, 2022, and 2023. In response to EPA’s request for comments on other options that could set longer time frames for installing pollution controls if the Navajo Plant can achieve additional emission reductions, on July 26, 2013, a group of stakeholders, including SRP, the operating agent for the Navajo Plant, submitted to EPA two suggested alternatives to BART, which would achieve greater NOx emission reductions than EPA’s proposed BART rule. If the rule is finalized as proposed, depending on which alternate operating scenario the Navajo Plant participants ultimately select, the required NOx emission reductions could be achieved by either closing one of the three 750 MW units at the plant or curtailing energy production across all three units, such that the emission reductions are commensurate with the closure of approximately one of the Navajo Plant units. On September 25, 2013, EPA issued a supplemental BART proposal proposing to determine that these alternatives are “better than BART” because NOx emissions that would be achieved thereunder would result in greater reasonable progress toward the national visibility goal than EPA’s proposed BART determination.
Mercury and other Hazardous Air Pollutants. On December 16, 2011, 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. Generally, plants will have three years after the effective date of the rule to achieve compliance. In the case of Cholla, APS will have a total of four years after the MATS’ effective date to comply with the new MACT standards, because on September 24, 2012, the permitting authority granted APS’s request for a one-year compliance date extension. Similarly, SRP
will have until April 16, 2016 to comply with MATS at the Navajo Plant, as a result of a one-year extension granted by EPA and the Navajo Nation EPA on January 27, 2014.
The MATS will require APS to install additional pollution control equipment. APS has installed certain of the equipment necessary to meet the anticipated standards. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $120 million for Cholla Units 2 and 3. These costs are not included in the capital expenditure estimates described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures” in Item 7. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.
Cooling Water Intake Structures. 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 their 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. EPA will issue the final standards upon completion of its ongoing ESA consultations with the U.S. Fish and Wildlife Service and National Marine Fisheries Service and is working to finalize the standards by April 2014.
Coal Combustion Waste. On June 21, 2010, 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. EPA proposes regulating CCRs as either non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) or hazardous waste under Subtitle C of RCRA 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. EPA has not yet indicated a preference for any of the alternatives.
In April 2012, a coalition of environmental groups filed suit to compel EPA to finalize its proposed CCR rule. Soon thereafter, coal ash recyclers filed similar lawsuits against EPA, which were consolidated with the environmental groups’ lawsuits. On January 29, 2014, the parties in the CCR
deadline litigation filed a consent decree with the court obligating EPA to make a final decision by December 2014 whether or not to adopt the Subtitle D option for CCR. The consent decree does not foreclose EPA from adopting the Subtitle C option. We cannot currently predict the timing or content of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows.
Effluent Limitation Guidelines. On April 19, 2013, EPA proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units. EPA’s proposal offers numerous options (four of which are “preferred alternatives”) that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. We cannot currently predict the shape of EPA’s final rule or whether this action will have a material adverse impact on our financial position, results of operations, or cash flows. EPA is currently subject to a consent decree deadline to finalize the revised guidelines by May 2014, although it is in negotiations to obtain an extension of time.
Ozone National Ambient Air Quality Standards. In March 2008, EPA adopted new, more stringent eight-hour ozone standards, known as national ambient air quality standards (“NAAQS”). In January 2010, EPA proposed to adopt even more stringent eight-hour ozone NAAQS. However, the following year, President Obama decided to withdraw EPA’s revised ozone standards until completion of the next review. EPA had a March 2013 deadline to complete its review of the 2008 ozone NAAQS, but failed to meet it. Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014. 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 located in ozone nonattainment areas. At this time, APS is unable to predict the timing of the final standards or 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 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 EPA has undertaken under the Clean Air Act. 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 NSR 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 EPA. APS responded to EPA’s request in August 2009 and is currently unable to predict any resulting actions the EPA may take, including any potential litigation.
Clean Air Act Citizen Lawsuit. On October 4, 2011, Earthjustice, on behalf of several environmental non-governmental 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 NSR provisions of the Clean Air Act. Subsequent to filing its original complaint, on January 6, 2012, Earthjustice filed an amended complaint adding claims for violations of the Clean Air Act’s NSPS program. Among other things, the environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Superfund-Related Matters. 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 potentially responsible parties (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that 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 EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with 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 $2 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 expenditures related to this matter cannot be reasonably estimated.
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. We are unable to determine a range of potential losses that are reasonably possible of occurring.
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’s 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. In addition, APS is a party to a water contract that allows the company to secure water for Four Corners in the event of a water shortage and is a party to a shortage sharing agreement, which provides for the apportionment of water supplies to Four Corners in the event of a water shortage in the San Juan River Basin.
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 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. Several 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 APS’s 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 Arizona Supreme 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 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.
Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, or cash flows.
BUSINESS OF OTHER SUBSIDIARIES
Our other operating subsidiary, El Dorado, is not expected to contribute in any material way to our future financial performance, nor will it require any material amounts of capital over the next three years. We continue to focus on our core utility business and streamlining the Company.
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, 2013, El Dorado had total assets of $15 million.
SunCor
In February 2012, our other first-tier subsidiary, SunCor, filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. On March 25, 2013, the bankruptcy plan submitted to the court and agreed to by SunCor and its creditors (the “Joint Plan”) became effective. The Joint Plan provides for the full release of Pinnacle West and its affiliates from any and all claims related to SunCor, SunCor’s subsidiaries, and their respective estates. SunCor and its subsidiaries are in the process of being formally dissolved.
OTHER INFORMATION
Pinnacle West, APS and El Dorado 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 2,865 employees) for which APS serves as the generating facility manager. Approximately 1,797 APS employees are union employees. APS entered into a 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 Company is currently engaged in discussions with union representatives to enter into an extension of the current agreement. In January 2013, the Palo Verde security officers voted to change their collective bargaining representative from the Security, Police and Fire Professionals of America to the United Security Professionals of America (“USPA”), and the National Labor Relations Board certified the results. The Company is currently engaged in negotiations with the USPA over the terms of a new collective bargaining agreement.
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, Code of Ethics and 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 Code of Ethics and 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 Corporate Secretary, Mail Station 8602, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-4400).
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 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 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 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 FERC, NRC, 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, FERC can impose penalties (up to one million dollars per day per violation) for failure to comply with mandatory electric reliability standards. 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 safety-related, security-related and other licensing 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 all nuclear generation facilities, including Palo Verde. As a result of the March 2011 earthquake and tsunamis 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 has been 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 complete its formal actions as a result of its review. As a result of the Fukushima event, however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (APS’s share is 29.1%). We cannot predict whether these amounts will increase or whether additional financial and/or operational requirements on Palo Verde and APS may be imposed.
In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increased inspection regime that could ultimately result in the shut-down of a unit or civil penalties, 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, or may become, subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, discharges of wastewater and streams originating from fly ash and bottom ash handling facilities, 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 as a result of government enforcement actions or private claims 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 PRPs.
Regional Haze. APS has received final rulemakings imposing new requirements on Four Corners and Cholla and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plants. The financial impact of installing and operating the required pollution control equipment could jeopardize the economic viability of these plants or the ability of individual participants to continue their participation in these plants.
Mercury and other Hazardous Air Pollutants. EPA issued MATS to regulate emissions of mercury and other hazardous air pollutants from fossil-fired power plants. The MATS will require APS to install additional pollution control equipment at Cholla and possibly the Navajo Plant. The financial impact of installing and operating such equipment could jeopardize the economic viability of Cholla.
Coal Ash. 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. 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 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.
Effluent Limitation Guidelines. EPA is expected to finalize revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil-fired electric generating units in 2014. EPA has indicated that it expects the revised standards to target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities and scrubber-related operations. APS currently disposes of fly ash waste and bottom ash in ash ponds at Four Corners. Changes required by the rule could significantly increase ash disposal costs at Four Corners.
New Source Review. 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, repair and replacement 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 EPA regarding projects and operations at Four Corners. Several environmental non-governmental organizations filed suit against the Four Corners participants for alleged violations of New Source Review and the NSPS programs of the Clean Air Act. If EPA seeks to impose New Source Review requirements at Four Corners or any other APS plant, or if the citizens groups prevail in their Clean Air Act lawsuit, capital investments could be required to install new pollution control technologies. 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. Due to current or potential future regulations or legislation, the economics of continuing to own certain resources, particularly coal facilities, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
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 GHG emissions.
Concern over climate change, deemed by many to be induced by rising levels of GHG 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 GHG emissions.
Financial Risks - Potential Greenhouse Gas Regulation. EPA is taking action to regulate domestic GHG emissions and is expected to issue proposed regulations in mid-2014. Any limitations on CO2 and other GHG emissions resulting from this regulatory effort could require substantial additional capital expenditures and operating costs and could have a material adverse impact on all fossil-fuel-fired generation facilities (particularly coal-fired facilities, which constitute approximately 30% of APS’s owned and leased generation capacity).
At the state level, the California legislature enacted legislation to address GHG emissions and the California Air Resources Board approved regulations that established a cap-and-trade program for
GHGs. This legislation, regulations and other state-specific initiatives may affect APS’s business, including sales into the impacted states.
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. On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. One of these options could be a continuation or expansion of APS’s existing AG (Alternative Generation) - 1 program, which essentially allows up to 200 MW of cumulative load to be served via a buy-through arrangement with competitive suppliers of generation. We cannot predict future regulatory or legislative action that might result in increased competition.
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 and facilities. 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 settlement agreement in APS’s most recent retail rate case (the “2012 Settlement Agreement”) includes a mechanism, the LFCR, to address these matters.
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 substantially offset through ratemaking mechanisms, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.
Customer and Sales Growth. For the three years 2011 through 2013, APS’s retail customer growth averaged 1.0% per year. We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kWh will increase on average by about 1% during 2014 through 2016, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. Actual customer and sales growth may differ from our projections as a result of numerous factors, such as economic conditions, customer growth and usage patterns, and the effects of energy efficiency and distributed energy programs and requirements. Additionally, recovery of a substantial portion of our fixed costs of providing service is based upon the volumetric amount of our sales. If our customer growth rate does not continue to improve as projected, or if it declines, or if the Arizona economy fails to improve, we may be unable to reach our estimated demand level and sales projections, which could have a negative impact on our 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. Concerns over physical security of these assets is also increasing, which may require us to incur additional capital and operating costs to address. Damage to certain of our facilities due to vandalism or other deliberate acts could lead to outages or other adverse effects.
The inability to successfully develop or acquire generation resources to meet reliability requirements, new or evolving standards or 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. The current abundance of low, stably priced natural gas, together with environmental and other concerns surrounding coal-fired generation resources, create strategic questions related to the appropriate generation portfolio and fuel diversification mix. In addition, APS is required by the ACC to meet certain energy resource portfolio requirements such as the EES and the RES. The development of any generation facility is subject to many 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 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 constitutes approximately 18% of our owned and leased generation capacity. 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 $111 million (but not more than $16.4 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”) 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 or emissions, including clean coal and coal gasification, renewable technologies including photovoltaic (solar) cells, customer-sited generation (solar), energy storage (batteries), 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, as well as digital meters enabling two-way communications between the utility and its customers. Many of the products and processes resulting from these and other alternative technologies have not yet been widely used or tested on a long-term basis, and their use on large-scale systems is not as advanced and established as APS’s existing technologies and equipment. Widespread installation and acceptance of these technologies could enable the entry of new market participants, such as technology companies, into the interface between APS and its customers and could have other unpredictable effects on APS’s business.
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, with approximately 38% of employees eligible to retire by 2017. Although we have undertaken efforts to recruit and train new employees, we face increased competition for talent. 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. 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 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. We obtained cyber insurance to provide coverage for a portion of the losses and damages that may result from a security breach of our information technology systems, but such insurance may not cover the total loss or damage caused by a breach.
FINANCIAL RISKS
Financial market disruptions or new financial rules or regulations may increase our financing costs or limit our access to various financial markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
Pinnacle West and APS 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 these financial 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 interest expense on our existing variable rate debt and new debt we expect to issue in the future, and thus 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 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. We are subject to risks related to the provision of employee healthcare benefits and recent healthcare reform legislation. 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 of the fixed income and equity securities held in these trusts may increase our funding requirements into the related trusts. 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 OCI. 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 are impacted by federal legislation. Increasing liabilities or otherwise increasing funding requirements under these plans, resulting from adverse changes in legislation or otherwise, could result 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.
Employee healthcare costs in recent years have continued to rise. The Patient Protection and Affordable Care Act is expected to result in additional healthcare cost increases. Costs and other
effects of the legislation, which may include the cost of compliance and potentially increased costs of providing for medical insurance for our employees, cannot be determined with certainty at this time. We will continue to monitor healthcare legislation and its impact on our plans and costs.
Our cash flow depends on the performance of APS.
We derive essentially all of our revenues and earnings from our wholly-owned subsidiary, 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 financing 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;
· 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 of Directors and fill vacancies on the Board of Directors, 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 of Directors 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.
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 2013 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 (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%), Tucson Electric Power Company (7%) and El Paso (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, in December 2013 APS acquired SCE’s 48% interest in Units 4 and 5, and closed 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 5,908 pole miles of overhead lines and approximately 49 miles of underground lines, 5,685 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,399 miles of overhead lines and approximately 17,758 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, 2013:
Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan. In APS’s 2014 plan, APS projects it will develop 275 miles of new lines over the next ten years. 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 with the capability to string 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 2014 transmission plan, are the Delaney to Palo Verde line and the North Gila to Hassayampa line, both of which are intended to support the transmission of renewable energy to Phoenix and California.
Plant and Transmission Line Leases and Rights-of-Way on Indian Lands
The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under rights-of-way from the federal government. The right-of-way and lease for the Navajo Plant expire in 2019 and the right-of-way 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 rights-of-way. APS is filing applications for renewal of these rights-of-way with the DOI. Before it may approve the Four Corners lease extension and issue the renewed rights-of-way, 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 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 or federal agencies. Other rights expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required at that time. In recent negotiations, 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. The ultimate cost of renewal of the rights-of-way for our transmission lines is therefore uncertain.
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 regarding environmental matters, Superfund-related matters, matters related to a September 2011 power outage and a New Mexico tax matter.
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 21, 2014, 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 14, 2014, Pinnacle West’s common stock was held of record by approximately 23,053 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 2013 and 2012.
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, 2013, 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 2013.
(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 and APSES discontinued operations (see Note 1).
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 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. APS operates and is a joint owner of Palo Verde. The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide. In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to ensure that its regulations reflect lessons learned from the Fukushima events.
Although the NRC has repeatedly affirmed its position that continued operation of U.S. commercial nuclear power plants does not impose an immediate risk to public health and safety, the NRC has proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. APS management continues to work closely with the NRC and others in the nuclear industry to ensure that the enhancements are implemented in an organized, sequential and structured way consistent with their safety benefit and significance of the issue being addressed.
Coal and Related Environmental Matters and Transactions. APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning GHG 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.
Four Corners
Asset Purchase Agreement and Coal Supply Matters. SCE, a participant in Four Corners, previously indicated that certain California legislation prohibited it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into the Asset Purchase Agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. On December 30, 2013, APS and SCE closed this transaction. The final purchase price for the interest was approximately $182 million, subject to certain minor post-closing adjustments.
In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction. On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS’s acquisition of SCE’s interest in Four Corners. If approved, these would result in an average bill impact to residential customers of approximately 2%. APS cannot predict the outcome of this request.
Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement. El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation. When APS ultimately acquires a right to EPE’s interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.
Pollution Control Investments and Shutdown of Units 1, 2 and 3. EPA, in its final regional haze rule for Four Corners, required the Four Corners’ owners to elect one of two emissions alternatives to apply to the plant. On December 30, 2013, APS, on behalf of the co-owners, notified EPA that they chose the alternative BART compliance strategy requiring the permanent closure of Units 1, 2 and 3 by January 1, 2014 and installation and operation of SCR controls on Units 4 and 5 by July 31, 2018. On December 30, 2013, APS retired Units 1, 2 and 3.
Lease Extension. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments 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 are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a PSD permit from EPA to install SCR control technology at Four Corners. APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.
Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development. The capital expenditures table presented in the “Liquidity and Capital Resources” section
below includes new transmission projects through 2016, along with other transmission costs for upgrades and replacements. APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater 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 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025. In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 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 currently estimated to be approximately 12% of APS’s estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers’ properties).
On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.
On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.
On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue,
but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.
Demand Side Management. In December 2009, Arizona regulators 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. The ACC initiated an Energy Efficiency rulemaking, with a proposed EES 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. This ambitious standard became effective on January 1, 2011. The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs. This amount was recovered by the then-existing DSMAC over a twelve-month period beginning March 1, 2012. This amount did not include $10 million already being recovered in general retail base rates, but did include amortization of 2009 costs (approximately $5 million of the $72 million).
On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels. ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward. APS expects to receive a decision from the ACC in early 2014.
On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished. This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.
Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the 2012 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.
As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an
alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners. This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate. APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement. APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration.
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are expected to be held in 2014.
Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. 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.
El Dorado. The operations of El Dorado, our only other operating subsidiary, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2011 through 2013, 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, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery
mechanisms. 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 in 2013 was 1.3% compared with the prior year. For the three years 2011 through 2013, APS’s customer growth averaged 1.0% per year. We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.5% in 2013 compared with the prior year, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, offset by mildly improving economic conditions and customer growth. For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kWh will increase on average about 1% during 2014 through 2016, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to improve 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 and energy conservation, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a reasonable range of variation in our kWh 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. Historically, 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, changes in our generation resource allocation, 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 customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. In the 2009 Settlement Agreement, APS committed to operational expense reductions from 2010 through 2014, and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012. In July 2012, we began amortizing the regulatory asset over a 36-month period.
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. See Note 1 regarding deferral of certain costs pursuant to an ACC order.
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 10.5% of the assessed value for 2013, 9.6% for 2012, and 9.0% for 2011. 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 contained in the 2012 Settlement Agreement).
Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as 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 used during construction 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 only 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.
Operating Results - 2013 compared with 2012.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2013 was $406 million, compared with net income of $382 million for the prior year. The results reflect an increase of approximately $21 million for the regulated electricity segment, primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues; and lower net interest charges due to lower debt balances and lower interest rates in the current-year period. These positive factors were partially offset by higher operations and maintenance expenses; higher fuel and purchased power costs, net of related deferrals; lower retail sales as a result of changes in customer usage related to energy efficiency, customer conservation and distributed generation, partially offset by customer growth; and higher depreciation and amortization expenses.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
(a) Includes activities related to SunCor.
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $57 million higher for the year ended December 31, 2013 compared with the prior year. The following table summarizes the major components of this change:
Operations and maintenance. Operations and maintenance expenses increased $40 million for the year ended December 31, 2013 compared with the prior year primarily because of:
· An increase of $14 million related to technical analysis, consulting, advertising and communications costs;
· An increase of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues;
· An increase of $9 million related to the closure of Four Corners Units 1, 2, and 3, deferred for regulatory recovery in depreciation;
· An increase of $6 million in energy delivery and customer service costs;
· An increase of $6 million in information technology costs;
· A decrease of $6 million in generation costs primarily related to lower fossil generation outage costs and lower nuclear generation costs; and
· A decrease of $2 million related to other miscellaneous factors.
Depreciation and amortization. Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2013 compared with the prior year, primarily because of
increased plant in service, partially offset by the regulatory deferral of operating expenses associated with the closure of Four Corners Units 1, 2, and 3.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, decreased $13 million for the year ended December 31, 2013 compared with the prior year, primarily because of lower debt balances and lower interest rates in the current year.
Income taxes. Income taxes were $5 million lower for the year ended December 31, 2013 compared with the prior year primarily due to a lower effective tax rate in the current period, partially offset by the effects of higher pretax income in the current year.
Operating Results - 2012 compared with 2011.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2012 was $382 million, compared with net income of $339 million for the prior year. The results reflect an increase of approximately $59 million for the regulated electricity segment, primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011; and lower net interest charges due to lower debt balances and lower interest rates in the current year.
The $17 million decrease in discontinued operations is primarily related to a contribution Pinnacle West made to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 1) and absence of the 2011 gain on sale of our investment in APSES.
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 transmission right-of-way costs, 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) Includes activities related to APSES and SunCor.
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $71 million higher for the year ended December 31, 2012 compared with the prior year. The following table summarizes the major components of this change:
Operations and maintenance. Operations and maintenance expenses decreased $19 million for the year ended December 31, 2012 compared with the prior year primarily because of:
· A decrease of $28 million related to settlement in 2011 of certain transmission right-of-way costs, which was offset in operating revenues;
· A decrease of $22 million related to costs for demand-side management, renewable energy and similar regulatory programs;
· A decrease of $15 million in generation costs, primarily related to lower nuclear generation costs;
· An increase of $21 million related to employee benefit costs, including approximately $12 million of pension and other postretirement costs;
· An increase of $9 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance results;
· An increase of $7 million in information technology costs, primarily related to higher software maintenance; and
· An increase of $9 million due to other miscellaneous factors.
Depreciation and amortization. Depreciation and amortization expenses were $23 million lower for the year ended December 31, 2012 compared with the prior year, primarily due to the impacts of Palo Verde operating license extensions, partially offset by increased plant in service.
Taxes other than income taxes. Taxes other than income taxes increased $11 million for the year ended December 31, 2012 compared with the prior year, primarily because of higher property tax rates in the current year.
Other income (expenses), net. Other income (expenses), net, decreased $10 million for the year ended December 31, 2012 compared with the prior year, primarily because of higher investment losses of approximately $2 million and other non-operating expenses of approximately $8 million in the current year.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, decreased $24 million for the year ended December 31, 2012 compared with the prior year, primarily because of lower debt balances and lower interest rates in the current year.
Income taxes. Income taxes were $53 million higher for the year ended December 31, 2012 compared with the prior year, primarily due to higher pre-tax income in the current year and a lower effective tax rate in 2011.
Discontinued Operations
Results from discontinued operations decreased $17 million, primarily due to a contribution Pinnacle West made to SunCor’s estate as part of a negotiated resolution to the bankruptcy (see Note 1) and absence of a gain related to the sale of our investment in APSES in 2011.
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 by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity issuances. An 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, 2013, APS’s common equity ratio, as defined, was 58%. Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.
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.
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, 2013, 2012 and 2011 (dollars in millions):
Pinnacle West Consolidated
Arizona Public Service Company
Operating Cash Flows
2013 Compared with 2012. Pinnacle West’s consolidated net cash provided by operating activities was $1,153 million in 2013, compared to $1,171 million in 2012, a decrease of $18 million in net cash provided. The decrease is primarily related to a $127 million change in cash collateral posted and $76 million of higher pension contributions made in 2013 compared to 2012 (approximately $18 million of which is reflected in capital expenditures). The decrease is partially offset by approximately $167 million of higher cash inflows primarily due to higher authorized revenue requirements resulting from the retail regulatory settlement effective July 1, 2012 and other changes in working capital.
2012 Compared with 2011. Pinnacle West’s consolidated net cash provided by operating activities was $1,171 million in 2012, compared to $1,125 million in 2011, an increase of $46 million in net cash provided. The increase is primarily related to a $77 million reduction of cash collateral posted and a decrease of $23 million in cash paid for interest in the current year, partially offset by a $26 million increase in property tax payments, a $65 million pension contribution in 2012 (approximately $12 million of which is reflected in capital expenditures) and other changes in working capital.
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 Income 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 benefit obligations. Under ERISA, the qualified pension plan was 107% funded as of January 1, 2013 and is estimated to be approximately 103% funded as of January 1, 2014. 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. We made contributions to our pension plan totaling $141 million in 2013, $65 million in 2012, and zero in 2011. The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead
for Progress in the 21st Century Act (zero in 2014, $19 million in 2015 and $122 million in 2016). Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016). With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011. The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.
The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities. Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.
During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination. On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund. Cash related to this refund was received in the first quarter of 2014.
Investing Cash Flows
2013 Compared with 2012. Pinnacle West’s consolidated net cash used for investing activities was $1,009 million in 2013, compared to $873 million in 2012, an increase of $136 million in net cash used. The increase in net cash used for investing activities is primarily related to APS’s purchase of SCE’s interest in Units 4 and 5 of Four Corners of approximately $209 million, partially offset by a decrease of approximately $73 million in other capital expenditures.
2012 Compared with 2011. Pinnacle West’s consolidated net cash used for investing activities was $873 million in 2012, compared to $782 million in 2011, an increase of $91 million in net cash used. The increase in net cash used for investing activities is primarily due to the absence of $55 million in proceeds from the sale of life insurance policies in 2011 and the absence of $45 million in proceeds from the sale of Pinnacle West’s investment in APSES in 2011.
Capital Expenditures. The following table summarizes the 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. The estimated Renewables expenditures include 20 MW of utility-scale solar projects which were approved by the ACC in the 2014 RES Implementation Plan. We have not included estimated costs for Cholla’s compliance with MATS or EPA’s regional haze rule since we have challenged the regional haze rule judicially and are considering our future options with respect to that plant if the regional haze rule is upheld. The portion of estimated costs through 2016 for installation of pollution control equipment needed to ensure Four Corners’ compliance with EPA’s regional haze rules have been included in the table above. We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned 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
2013 Compared with 2012. Pinnacle West’s consolidated net cash used for financing activities was $161 million in 2013, compared to $305 million of net cash used in 2012, a decrease of $144
million in net cash used. The decrease in net cash used for financing activities is primarily due to $531 million in lower repayments of long-term debt, largely offset by $340 million in lower issuances of long-term debt and a $31 million net change in APS’s commercial paper borrowings, which is classified as short-term borrowings on the Consolidated Balance Sheets. On December 30, 2013, commercial paper issuances were used to fund the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners (see below).
2012 Compared with 2011. Pinnacle West’s consolidated net cash used for financing activities was $305 million in 2012, compared to $420 million in 2011, a decrease of $115 million in net cash used. The decrease in net cash used for financing activities is primarily due to an increase of $92 million in APS’s short-term debt borrowings in 2012. In addition, APS had $56 million in higher issuances of long-term debt, partially offset by $99 million in higher repayments of long-term debt. Pinnacle West had $100 million in lower repayments of long-term debt, partially offset by $50 million in lower debt issuances (see below).
Significant Financing Activities. On December 18, 2013, the Pinnacle West Board of Directors declared a quarterly dividend of $0.5675 per share of common stock, payable on March 3, 2014, to shareholders of record on February 3, 2014. During 2013, Pinnacle West increased its indicated annual dividend from $2.18 per share to $2.27 per share. For the year ended December 31, 2013, Pinnacle West’s total dividends paid per share of common stock were $2.20 per share, which resulted in dividend payments of $235 million.
On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.
On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. On May 28, 2013, we remarketed the bonds. The interest rate for these bonds was set to a new term rate. The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018. During this time, the bonds will bear interest at a rate of 1.75% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in
each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.
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.
At December 31, 2013, Pinnacle West’s $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.
On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility matures in April 2018.
At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS can use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. APS had commercial paper borrowings of $153 million at December 31, 2013.
See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.
Other Financing Matters. See Note 3 for information regarding the PSA approved by the ACC.
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.
See Note 17 for information related to the change in our margin and collateral 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, 2013, the ratio was approximately 47% for Pinnacle West and 45% 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 14, 2014 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 available liquidity resources to respond to a downward revision to our credit ratings.
Off-Balance Sheet Arrangements
See Note 19 for a discussion of the impacts on our financial statements of consolidating certain VIEs.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2013 (dollars in millions):
(a) The long-term debt matures at various dates through 2042 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2013 (see Note 6).
(b) The short-term debt represents commercial paper borrowings at APS (see Note 5).
(c) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 3 and 11). These amounts include commitments incurred from acquiring SCE’s interest in Four Corners.
(d) Contracts to purchase renewable energy credits in compliance with the RES (see Note 3).
(e) These contractual obligations include commitments for capital expenditures and other obligations.
(f) Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 19). We have committed to retain the assets relating to the noncontrolling interests beyond 2015, either through lease extensions or by purchasing the assets. If we elect to purchase the assets, the purchase price will be based on the fair value of the assets at the end of 2015. Such value is unknown at this time and is subject to an appraisal process.
If we elect to extend the leases, we will be required to make annual payments beginning in 2016 of approximately $23 million; however, the length of the lease extensions is unknown at this time as it must be determined through an appraisal process. Due to these uncertainties, amounts relating to the noncontrolling interests beyond 2015 have not been included in the table above.
This table excludes $42 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately zero, $19 million and $122 million in estimated minimum pension contributions for 2014, 2015 and 2016, respectively (see Note 8).
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with accounting principles generally accepted in the United States of America (“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 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 Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $809 million of regulatory assets and $901 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2013.
Included in the balance of regulatory assets at December 31, 2013 is a regulatory asset of $314 million for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds
over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2013 reported pension liability on the Consolidated Balance Sheets and our 2013 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, 2013 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2013 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 healthcare cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trust fund, 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 a discussion on accounting policies and Note 14 for further fair value measurement discussion.
OTHER ACCOUNTING MATTERS
During 2013, we adopted new accounting guidance relating to balance sheet offsetting disclosures, and disclosures of amounts reclassified from accumulated OCI. During the first quarter of 2014 we are required to adopt new accounting guidance related to balance sheet presentation of certain unrecognized tax benefits. See Note 2.
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 and benefit plan assets.
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 and Note 20) and benefit plan assets. The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan 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, 2013 and
2012. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (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, 2013 and 2012. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (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 2013 and 2012 (dollars in millions):
(a) Represents the amounts reflected in income after the effect of PSA deferrals.
(b) 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, 2013 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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, 2013 and 2012 (dollars in millions):
(a) Represents the amounts reflected in income after the effect of PSA deferrals.
(b) These contracts are economic 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 17 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 2013, 2012 and 2011
Pinnacle West Consolidated Statements of Comprehensive Income for 2013, 2012, and 2011
Pinnacle West Consolidated Balance Sheets as of December 31, 2013 and 2012
Pinnacle West Consolidated Statements of Cash Flows for 2013, 2012 and 2011
Pinnacle West Consolidated Statements of Changes in Equity for 2013, 2012 and 2011
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 2013, 2012 and 2011
APS Consolidated Statements of Comprehensive Income for 2013, 2012, and 2011
APS Consolidated Balance Sheets as of December 31, 2013 and 2012
APS Consolidated Statements of Cash Flows for 2013, 2012 and 2011
APS Consolidated Statements of Changes in Equity for 2013, 2012 and 2011
Supplemental Notes to APS’s Consolidated Financial Statements
Financial Statement Schedules for 2013, 2012 and 2011
Pinnacle West Schedule I - Condensed Statements of Comprehensive Income for 2013, 2012 and 2011
Pinnacle West Schedule I - Condensed Balance Sheets as of December 31, 2013 and 2012
Pinnacle West Schedule I - Condensed Statements of Cash Flows for 2013, 2012 and 2011
Pinnacle West Schedule II - Reserve for Uncollectibles for 2013, 2012 and 2011
APS Schedule II - Reserve for Uncollectibles for 2013, 2012 and 2011
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. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework (1992), our management concluded that our internal control over financial reporting was effective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31, 2013 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 21, 2014
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, 2013 and 2012 and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 21, 2014
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 STATEMENTS OF COMPREHENSIVE INCOME
(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 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, except per share amounts)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
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1. Summary of Significant Accounting Policies
Description of Business and Basis of Presentation
Pinnacle West is a holding company that conducts business through its subsidiaries, APS and El Dorado, and formerly SunCor and APSES. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. SunCor was a developer of residential, commercial and industrial real estate projects and essentially all of these assets were sold in 2009 and 2010. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities for SunCor are reported as discontinued operations. APSES provided energy-related projects to commercial and industrial retail customers in competitive markets in the western United States. APSES was sold in 2011 and is reported as discontinued operations. El Dorado is an investment firm.
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS and El Dorado, and formerly SunCor and APSES. APS’s consolidated financial statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.
We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 19).
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.
Certain line items are presented in more detail on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows than was presented in the prior years. Other line items are more condensed than the previous presentation. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications had no impact on total assets or net cash flow provided by operating activities. The following tables show the impacts of the reclassifications of prior years (previously reported) amounts (dollars in thousands):
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Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
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Regulatory Accounting
APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
See Note 3 for additional information.
Electric Revenues
We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs.
For the period January 1, 2010 through June 30, 2012, electric revenues also include proceeds for line extension payments for new or upgraded service in accordance with the 2009 Settlement Agreement (see Note 3). Effective July 1, 2012, as a result of the 2012 Settlement Agreement, these amounts are now recorded as contributions in aid of construction and are not included in electric revenues.
Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.
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Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including accrued utility revenues. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
Property, Plant and Equipment
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
· material and labor;
· contractor costs;
· capitalized leases;
· construction overhead costs (where applicable); and
· allowance for funds used during construction.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
APS records a regulatory liability on its regulated assets for the difference between the amount that has been recovered in regulated rates and the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it can recover in regulated rates the costs calculated in accordance with this accounting guidance.
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2013 were as follows:
· Fossil plant - 18 years;
· Nuclear plant - 26 years;
· Other generation - 26 years;
· Transmission - 37 years;
· Distribution - 34 years; and
· Other - 7 years.
APS applied for twenty-year extensions of its operating licenses for each of the three Palo Verde units in December 2008. On April 21, 2011, the NRC approved the extensions of the Palo Verde licenses. The nuclear plant remaining life takes into consideration an ACC decision which authorizes the use of the new Palo Verde nuclear plant lives, effective January 1, 2012.
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Pursuant to an ACC order, we defer operating costs related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. See Note 3 for further discussion. These costs are deferred on the depreciation line of the Consolidated Statements of Income.
For the years 2011 through 2013, the depreciation rates ranged from a low of 0.45% to a high of 12.08%. The weighted-average rate was 3.00% for 2013, 2.71% for 2012, and 2.98% for 2011.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statement of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
AFUDC was calculated by using a composite rate of 8.56% for 2013, 8.60% for 2012, and 10.25% for 2011. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Materials and Supplies
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trust, certain cash equivalents and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Due to the short-term nature of net accounts receivable, accounts payable, and short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost (see Note 6).
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
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The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.
See Note 14 for additional information about fair value measurements.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emission allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 17 for additional information about our derivative instruments.
Loss Contingencies and Environmental Liabilities
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 8 for additional information on pension and other postretirement benefits.
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Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures (see Note 4).
Cash and Cash Equivalents
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
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Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $53 million in 2013, $50 million in 2012, and $47 million in 2011. Estimated amortization expense on existing intangible assets over the next five years is $47 million in 2014, $38 million in 2015, $29 million in 2016, $19 million in 2017, and $7 million in 2018. At December 31, 2013, the weighted-average remaining amortization period for intangible assets was 6 years.
Investments
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with guidance on accounting for certain investments in debt and equity securities. See Note 14 and Note 20 for more information on these investments.
Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.
2. New Accounting Standards
During 2013, we adopted, on a retrospective basis, new guidance relating to balance sheet offsetting disclosures. The new guidance requires enhanced disclosures regarding an entity’s ability to offset certain instruments on the balance sheet and how offsetting impacts the balance sheet. The adoption of this guidance resulted in expanded disclosures relating to our derivative instruments (see Note 17), but did not impact our financial statement results.
During 2013, we also adopted, on a prospective basis, new guidance relating to reporting amounts reclassified from accumulated other comprehensive income. This guidance requires new disclosures relating to accumulated other comprehensive income and how reclassifications from accumulated other comprehensive income impact net income. As a result of adopting this new guidance, we have included a new footnote disclosure to provide the information required by the new standard (see Notes 21 and S-4). The adoption of this guidance did not impact our financial statement results.
In July 2013, new guidance was issued which will generally require entities to present unrecognized tax benefits as a reduction to any available deferred tax asset for a net operating loss, a similar tax loss, or a tax credit carryforward. The intent of this guidance is to eliminate diversity in practice in the presentation of certain unrecognized tax benefits. The new guidance is effective for us during the first quarter of 2014, and is permitted to be adopted using either a prospective or retrospective application. Currently, we do not present unrecognized tax benefits as a reduction to deferred tax asset carryforwards on the balance sheet. As a result, the adoption of this new guidance
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will impact our balance sheet presentation; however, we do not expect these presentation changes to be material to our balance sheet. The adoption of this new guidance will not impact our results of operations or cash flows.
3. Regulatory Matters
Retail Rate Case Filing with the Arizona Corporation Commission
On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into the 2012 Settlement Agreement detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.
Settlement Agreement
The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the Base Fuel Rate from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million.
APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016. The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest. Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement.
Other key provisions of the 2012 Settlement Agreement include the following:
· An authorized return on common equity of 10.0%;
· A capital structure comprised of 46.1% debt and 53.9% common equity;
· A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;
· Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:
· Deferral of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and
· Deferral of 100% in all years if Arizona property tax rates decrease;
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· A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);
· Implementation of a “Lost Fixed Cost Recovery” rate mechanism to support energy efficiency and distributed renewable generation;
· Modifications to the Environmental Improvement Surcharge to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;
· Modifications to the PSA, including the elimination of the 90/10 sharing provision;
· A limitation on the use of the RES surcharge and the DSMAC to recoup capital expenditures not required under the terms of the 2009 Settlement Agreement discussed below;
· Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;
· Modification of the TCA to streamline the process for future transmission-related rate changes; and
· Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.
The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012. This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.
2008 General Retail Rate Case On-Going Impacts
On December 30, 2009, the ACC issued an order approving the 2009 Settlement Agreement entered into by APS and twenty-one other parties. The 2009 Settlement Agreement contains certain on-going requirements, commitments and authorizations that will survive the 2012 Settlement Agreement, including the following:
· A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014;
· Authorization and requirements of equity infusions into APS of $700 million during the period beginning June 1, 2009 through December 31, 2014 and compliance with various
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financial conditions, including the maintenance of a prescribed capital structure (APS was able to meet these conditions without the need for additional equity infusions beyond the $253 million infused into APS in the second quarter of 2010); and
· Renewable energy programs that require APS to expand its use of renewable energy through 2015, as well as allow for concurrent recovery of renewable energy expenses.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.
On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS’s demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer’s existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system’s output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.
On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the
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electrical grid. ACC professional staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS’s revenue, but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.
Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan for review by and approval of the ACC.
On June 1, 2011, APS filed its 2012 Demand Side Management Implementation Plan consistent with the ACC’s Electric Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such standards is for cumulative energy efficiency savings of 3% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2009 Settlement Agreement (2.75% of total energy resources for the same two-year period). The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS’s energy efficiency and demand side management program costs. This amount was recovered by the then existing DSMAC over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates, but does include amortization of 2009 costs (approximately $5 million of the $72 million).
On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan. In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels. ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward. APS expects to receive a decision from the ACC in early 2014.
On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished. This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.
PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
· APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
· an adjustment to the PSA rate is made annually each February 1st (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
· the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
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· the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
· the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2013 and 2012 (dollars in millions):
The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year. This represents a $0.000228 per kWh increase over the 2013 PSA charge. This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh. Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until
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settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
Effective June 1, 2012, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $16 million for the twelve-month period beginning June 1, 2012 in accordance with the FERC-approved formula.
Effective June 1, 2013, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $26 million for the twelve-month period beginning June 1, 2013 in accordance with the FERC-approved formula. Pursuant to the 2012 Settlement Agreement (discussed above), an adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2013.
Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.
APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter. On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012. APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014. APS anticipates that the ACC will consider whether to approve APS’s LFCR adjustment prior to the end of March 2014.
Deregulation
On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are expected to be held in 2014.
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Four Corners
On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. As a result of this purchase, APS now owns 63% of Units 4 and 5. APS has a total entitlement from Four Corners of 970 MW. The final purchase price for the interest was approximately $182 million. APS acquired assets and assumed certain of SCE’s decommissioning and mine reclamation obligations. We have recognized plant-in-service, net of accumulated depreciation, of $316 million, which includes an acquisition adjustment of $255 million. In addition, we have recognized a liability of $34 million for the decommissioning obligations, $93 million for the mine reclamation obligations, $18 million of other various liabilities, and $11 million of construction work in progress relating to this purchase. These amounts are subject to revision during the measurement period, not to exceed one year, to the extent additional information is obtained about the facts and circumstances that existed as of the acquisition date. While we expect the ACC to approve the recovery of the acquisition adjustment, should recovery be disallowed, it will be reclassified from plant-in-service to goodwill, subject to impairment testing. The decommissioning and mine reclamation obligations were recognized at their fair value. Because APS’s rates are regulated, APS expects to recover the costs of the acquired plant assets, including a return on its investment based on its cost of capital. APS believes this return is consistent with what a market participant would consider to be fair value in APS’s regulatory environment. Accordingly, APS believes the cost of the plant assets approximate their fair value.
The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. This includes deferral for future recovery of all non-fuel operating cost for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Four Corners Units 1-3. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Four Corners Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Four Corners Units 1-3 was $37 million as of December 31, 2013.
As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group for transmission of the additional power received from Four Corners. This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate. APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement. As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration.
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Regulatory Assets and Liabilities
The detail of regulatory assets is as follows (dollars in millions):
(a) This asset represents the future recovery of under-funded pension and other postretirement benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 8 for further discussion.
(b) See “Cost Recovery Mechanisms” discussion above.
(c) Subject to a carrying charge.
(d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
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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.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates.
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction and pension and other postretirement benefits. The regulatory liabilities primarily relate to deferred taxes resulting from investment tax credits (“ITC”) and the change in income tax rates.
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.
The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities. Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.
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During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination. On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund. Cash related to this refund was received in the first quarter of 2014.
On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS, resulting in a cumulative effect adjustment. To account for the adoption of these regulations, plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets. Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19). As a result, there is no income tax expense associated with the VIEs recorded on the Consolidated Statements of Income.
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
Included in the balances of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2010 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2010.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Consolidated Statements of Income as income tax expense. The amount of interest recognized in the Consolidated
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Statements of Income related to unrecognized tax benefits was a pre-tax benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012, and a pre-tax expense of $3 million for 2011.
The total amount of accrued liabilities for interest recognized in the Consolidated Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2013, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of income tax expense are as follows (dollars in thousands):
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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):
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. As of December 31, 2013 APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2013, APS has recorded a regulatory liability of $2
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million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
The components of the net deferred income tax liability were as follows (dollars in thousands):
As of December 31, 2013, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of $131 million which first begin to expire in 2031, and other federal and state loss carryforwards of $2 million which first begin to expire in 2018.
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5. Lines of Credit and Short-Term Borrowings
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2013 (dollars in millions):
(a) At December 31, 2013, APS had $153 million of outstanding commercial paper. Accordingly, at such date, the total combined amount available under its two $500 million credit facilities was $847 million.
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.
Pinnacle West
At December 31, 2013, the Pinnacle West credit facility, which terminates in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.
APS
On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility matures in April 2018.
At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS can use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $153 million at December 31, 2013.
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See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2012 (dollars in millions):
(a) At December 31, 2012, APS had $92 million of outstanding commercial paper. Accordingly, at such date the total combined amount available under its two $500 million credit facilities was $908 million.
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.
Pinnacle West
At December 31, 2012, the Pinnacle West credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit and no commercial paper borrowings.
APS
APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS will use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS’s senior unsecured debt credit ratings.
The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2012, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.
See “Financial Assurances” in Note 11 for a discussion of APS’s separate outstanding letters of credit.
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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 February 6, 2013, the ACC issued a financing order in which, subject to specified parameters and procedures, it (a) approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power), (b) approved an increase in APS’s long-term debt authorization from $4.2 billion to $5.1 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs, and (c) authorized APS to enter into derivative financial instruments for the purpose of managing interest rate risk associated with its long- and short-term debt. This financing order is set to expire on December 31, 2017.
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, 2013 and 2012 (dollars in thousands):
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b) The weighted-average rate for the variable rate pollution control bonds was 0.03%-0.06% at December 31, 2013 and 0.13%-0.15% at December 31, 2012.
(c) The weighted-average interest rate was 1.269% at December 31, 2013 and 1.312% at December 31, 2012.
(d) Current maturities include $215 million of pollution control bonds expected to be remarketed in 2014 and $300 million in senior unsecured notes that mature in 2014.
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The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in millions):
Debt Fair Value
Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within level 2 of the fair value hierarchy. 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
APS
On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.
On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. On May 28, 2013, we remarketed the bonds. The interest rate for these bonds was set to a new term rate. The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018. During this time, the bonds will bear interest at a rate of 1.75% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
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On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.
On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt indebtedness.
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, 2013, the ratio was approximately 47% for Pinnacle West and 45% 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, 2013, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the
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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.
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2013, 2012 and 2011 is as follows (dollars in thousands):
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
At December 31, 2013, 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 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.
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Pinnacle West also sponsors an other 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 further 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. We deferred pension and other postretirement benefit costs of approximately $14 million in 2012 and $11 million in 2011. Pursuant to an ACC regulatory order, we began amortizing the regulatory asset over 3 years beginning in July 2012. We amortized approximately $8 million during 2013 and $4 million during 2012.
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, 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 2013 and 2012 (dollars in thousands):
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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, 2013 and 2012 (dollars in thousands):
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2013 and 2012 (dollars in thousands):
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2013 and 2012 (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 2014 (dollars in thousands):
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The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2014, we are assuming a 6.9% long-term rate of return for pension assets and 7.1% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
The assumed healthcare cost trend rates shown above have a significant effect on the amounts reported for the healthcare plans. In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects (dollars in millions):
Plan Assets
The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets.
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The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.
The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.
Long-term fixed income assets, also known as liability-hedging assets, are designed to offset changes in the benefit obligations due to changes in interest rates. 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.
Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments include investments in real estate, private equity and various other strategies. The plan may hold investments in return-generating assets by holding securities in common and collective trusts.
Based on the IPS, and given the pension plan’s funded status at year-end 2013, the long-term fixed income assets had a target allocation of 58% with a permissible range of 55% to 61% and the return-generating assets had a target allocation of 42% with a permissible range of 45% to 39%. The return-generating assets have additional target allocations, as a percent of total plan assets, of 22% equities in U.S. and other developed markets, 6% equities in emerging markets, and 14% in alternative investments. The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. As of December 31, 2013, long-term fixed income assets represented 55% of total pension plan assets, and return-generating assets represented 45% of total pension plan assets.
The asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for an asset allocation target mix of generally 25% of fixed income assets and 75% of non-fixed income assets. This asset allocation target mix does not vary with the plan’s funded status. As of December 31, 2013, investment in fixed income assets represented 38% of the other postretirement benefit plan total assets, and non-fixed income assets represented 62% of the other postretirement benefit plan’s assets. Fixed income assets are primarily invested in corporate bonds of investment-grade U.S. issuers, and U.S. Treasuries. Non-fixed income assets are primarily invested in large cap U.S. equities in diverse industries, and international equities in both emerging and developed markets.
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 fixed income securities, 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
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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, maturity and credit quality. 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). Common and collective trusts are valued using the concept of net asset value (“NAV”), which is a value 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, 2013, 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 have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing 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, 2013, by asset category, are as follows (dollars in thousands):
(a) Represents investments in a partnership that invests in privately held portfolio companies.
(b) This category consists primarily of debt securities issued by municipalities.
(c) Represents plan receivables and payables.
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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2012, by asset category, are as follows (dollars in thousands):
(a) Represents investments in a partnership that invests in privately held portfolio companies.
(b) This category consists primarily of debt securities issued by municipalities.
(c) Represents plan receivables and payables.
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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, 2013 and 2012 (dollars in thousands):
Contributions
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $141 million in 2013, $65 million in 2012, and zero in 2011. The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead for Progress in the 21st Century Act (zero in 2014, $19 million in 2015, and $122 million in 2016). Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016). With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011. The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year. APS funds its share of the contributions. APS’s share of the pension plan contribution was $140 million in 2013, $64 million in 2012, and zero in 2011. APS’s share of the contributions to the other postretirement benefit plan was $14 million in 2013, $22 million in 2012, and $19 million in 2011.
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):
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.
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Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2013, 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 $9 million for 2013, $8 million for 2012, and $8 million for 2011.
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 $18 million in 2013, $19 million in 2012, and $21 million in 2011. APS’s lease expense was $15 million in 2013, $16 million in 2012, and $18 million in 2011.
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 VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The above lease disclosures exclude the impacts of these sale leaseback transactions, as lease accounting for these agreements is eliminated upon consolidation. See Note 19 for a discussion of VIEs.
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs, as well as for providing our own financing. Our share of operating expenses 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, 2013 (dollars in thousands):
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(a) See Note 19.
(b) Weighted-average of interests.
(c) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(d) See Note 3.
11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the United States Court of Federal Claims. The lawsuit seeks to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the NWPA. This lawsuit is currently pending in the Court of Federal Claims.
APS currently estimates it will incur $122 million 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, 2013,
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APS had a regulatory liability of $42 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to $13.6 billion per occurrence. 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 $13.2 billion of liability coverage 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 $127.3 million, subject to an annual limit of $19 million per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo Verde units, APS’s maximum potential retrospective assessment per incident for all three units is approximately $111 million, with an annual payment limitation of approximately $16.4 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”). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses site-wide has been imposed on the NEIL property policies. Effective April 1, 2013, a sublimit of $327.6 million per unit has been imposed on the non-nuclear losses covered by the NEIL accidental outage policy, potentially subject to further limitations. 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 $48 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, sublimits 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 2014 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $729 million in 2014; $628 million in 2015; $638 million in 2016; $613 million in 2017; $580 million in 2018; and $8.7 billion thereafter. These fuel and purchased power commitments include the amounts incurred from acquiring SCE’s interest in Four Corners. 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 for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms that expire in 2031.
The following table summarizes our estimated coal take-or-pay commitments (dollars in millions):
(a) Total take-or-pay commitments are approximately $3.4 billion. The total net present value of these commitments is approximately $2.2 billion.
APS spends more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes the actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in millions):
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 $48 million in 2014; $42 million in 2015; $42 million in 2016; $42 million in 2017; $42 million in 2018; and $453 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy. Also, these amounts do not include purchases of renewable energy credits that are associated with purchased power contracts.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded a final coal mine reclamation obligation of approximately $207 million at December 31, 2013 and $119 million at December 31, 2012. Under our current coal supply agreements, we expect to make payments to certain coal providers for the final mine reclamation as follows: $1 million in 2014; $1 million in 2015; $8 million in 2016; $14 million in 2017; $14 million in 2018; and $170 million thereafter. Any amendments to current coal supply agreements may change the timing of the reimbursement.
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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, EPA advised APS that EPA considers APS to be a PRP in the OU3 in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with 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 $2 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 expenditures related to this matter cannot be reasonably estimated.
On August 6, 2013, RID filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Southwest Power Outage
Regulatory. On September 8, 2011 at approximately 3:30 PM, a 500kV 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. Approximately ten minutes after the transmission line went off-line, generation and transmission resources for the Yuma area were lost, resulting in approximately 69,700 APS customers losing service.
Within the same time period that APS’s Yuma customers lost service, a series of transmission and generation disruptions occurred across the systems of several utilities that resulted in outages affecting portions of southern Arizona, southern California and northern Mexico. A total of approximately 7,900 MW of firm load and 2.7 million customers were reported to have been affected. Service to all affected APS customers was restored by 9:15 PM on September 8. Service to customers affected by the wider regional outages was restored by approximately 3:25 AM on September 9.
FERC and the North American Electric Reliability Corporation (“NERC”) conducted a joint inquiry into the outages and, on May 1, 2012, they issued a report (the “Joint Report”) with their analysis and conclusions as to the causes of the events. The report includes recommendations to help industry operators prevent similar outages in the future, including increased data sharing and coordination among the western utilities and entities responsible for bulk electric system reliability coordination. The Joint Report does not address potential reliability violations or an assessment of responsibility of the parties involved. APS continues to analyze business practices and procedures related to the September 8 events.
On January 22, 2014, following non-public preliminary investigations, FERC Staff issued a Notice of Alleged Violations naming six entities involved in the event, including APS. FERC Staff
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alleges that each of the named entities violated varying numbers of NERC Reliability Standards. APS is alleged to have violated seven Reliability Standard Requirements. The allegations of violations are preliminary determinations by FERC Staff and do not constitute findings by FERC itself that any violations have occurred.
APS intends to work with FERC Staff to resolve the matter. If violations of the 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 a violation is found to have been in existence. APS cannot predict the timing or financial or operational impacts that may result from the Staff’s Notice of Alleged Violations, including any payments that may result from a settlement if one is reached, or any claims that may be made as a result of the outages.
Litigation. On September 6, 2013, a purported consumer class action complaint was filed in Federal District Court in San Diego, California, naming APS and Pinnacle West as defendants and seeking damages for loss of perishable inventory and sales as a result of interruption of electrical service. APS and Pinnacle West filed a motion to dismiss, which the court granted on December 9, 2013. On January 13, 2014, the plaintiffs appealed the lower court’s decision.
Clean Air Act Citizen Lawsuit
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 NSR 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 environmental plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS and the other Four Corners participants may reinstate their motions to dismiss without risk of default. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Environmental Matters
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 CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.
Regional Haze Rules. APS has received the final rulemaking imposing new requirements on Four Corners and Cholla and is currently awaiting a final rulemaking from EPA that could impose new requirements on the Navajo Plant. EPA and ADEQ will require these plants to install pollution control equipment that constitutes the BART to lessen the impacts of emissions on visibility surrounding the
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plants. Based on EPA’s final standards, APS’s 63% share of the cost of these controls for Four Corners Units 4 and 5 would be approximately $350 million. APS’s share of costs for upgrades at Navajo, based on EPA’s FIP proposal, could be up to approximately $200 million. APS has filed a Petition for Review of EPA’s rule as it applies to Cholla, which, if not successful, will require installation of controls with a cost to APS of approximately $200 million.
Mercury and Other Hazardous Air Pollutants. In 2011, EPA issued rules establishing maximum achievable control technology standards to regulate emissions of mercury and other hazardous air pollutants from fossil-fired plants. APS estimates that the cost for the remaining equipment necessary to meet these standards is approximately $120 million for Cholla Units 2 and 3. No additional equipment is needed for Four Corners Units 4 and 5 to comply with these rules. SRP, the operating agent for the Navajo Plant, is still evaluating compliance options under the rules.
Other future environmental rules that could involve material compliance costs include those related to cooling water intake structures, coal combustion waste, effluent limitations, ozone national ambient air quality, GHG emissions, and other rules or matters involving the Clean Air Act, Clean Water Act, ESA, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with these and other future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
Regional Haze Rules - Cholla
APS believes that EPA’s final rule as it applies to Cholla is unsupported and that EPA had no basis for disapproving Arizona’s SIP and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. We expect briefing in the case to be completed on February 21, 2014.
New Mexico Tax Matter
On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the “Assessment”). APS’s share of the Assessment is approximately $12 million. For procedural reasons, on behalf of the Four Corners co-owners, including APS, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit, but cannot predict the timing or outcome of this litigation.
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Financial Assurances
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2013, approximately $76 million of letters of credit were outstanding to support existing pollution control bonds of a similar amount. The letters of credit are available to fund the payment of principal and interest of such debt obligations. One of these letters of credit expires in 2015 and two 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 19 for further details on the Palo Verde sale leaseback transactions). These letters of credit will expire on December 31, 2015, and totaled approximately $32 million at December 31, 2013. Additionally, APS has issued letters of credit to support collateral obligations under certain risk management arrangements, including certain natural gas tolling contracts entered into with third parties. At December 31, 2013, $55 million of such letters of credit were outstanding that will expire in 2014 and 2015.
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 has issued parental guarantees and surety bonds for APS which were not material at December 31, 2013.
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. During the fourth quarter of 2013, a new decommissioning study with updated cash flow estimates was completed for Palo Verde.
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. The Four Corners coal-fired power plant asset retirement obligation relates to final plant decommissioning, including ash pond closures. In the fourth quarter of 2012, a new study related to ash pond closure was completed which updated the total costs estimates and related cash flows. In the fourth quarter of 2013, APS finalized the transaction to acquire SCE’s interest in Four Corners. As part of that transaction, APS assumed SCE’s asset retirement obligation. Also, APS retired Four Corners Units 1-3 on December 30, 2013. Decommissioning activities began for Units 1-3 in January 2014. An update was made to the timing of the Units 1-3 decommissioning cash out flows to coincide with the expected decommissioning activities.
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
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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 2013 and 2012 (dollars in millions):
Decommissioning activities for Four Corners Units 1-3 will begin in January 2014; thus, $33 million of the total asset retirement obligation of $347 million at December 31, 2013, is classified as a current liability on the balance sheet.
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 2013 and 2012 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.
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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.
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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 valuations are unobservable 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.
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 inputs and 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 activity, 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 activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Recurring Fair Value Measurements
We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust and plan assets held in our retirement and other benefit plans. See Note 8 for the fair value discussion of plan assets held in our retirement and other benefit plans.
Cash Equivalents
Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets.
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Risk Management Activities - Derivative Instruments
Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair 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. 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. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities.
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.
Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.
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 the concept of NAV, which is a value 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
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shares are offered to a limited group of investors, they are not considered to be traded in an active market.
Cash equivalents reported within Level 2 represent investments held in a short-term investment commingled fund, valued using NAV, which invests in U.S. government fixed income securities. We may transact in this commingled fund on a daily basis at the NAV.
Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield 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 have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 20 for additional discussion about our nuclear decommissioning trust.
Fair Value Tables
The following table presents the fair value at December 31, 2013 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 17.
(c) Represents nuclear decommissioning trust net pending securities sales and purchases.
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The following table presents the fair value at December 31, 2012 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in millions):
(a) Primarily consists of heat rate options and other long-dated electricity contracts.
(b) Represents counterparty netting, margin and collateral. See Note 17.
(c) Represents nuclear decommissioning trust net pending securities sales and purchases.
Fair Value Measurements Classified as Level 3
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote and option model inputs. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
Our option contracts classified as Level 3 primarily relate to purchase heat rate options. The significant unobservable inputs for these instruments include electricity prices, gas prices and volatilities. If electricity prices and electricity price volatilities increase, we would expect the fair value of these options to increase, and if these valuation inputs decrease, we would expect the fair value of these options to decrease. If natural gas prices and natural gas price volatilities increase, we would expect the fair value of these options to decrease, and if these inputs decrease, we would expect the fair value of the options to increase. The commodity prices and volatilities do not always move in corresponding directions. The options’ fair values are impacted by the net changes of these various inputs.
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2013 and December 31, 2012:
(a) Includes swaps and physical and financial contracts.
(b) Electricity and natural gas price volatilities are estimated based on historical forward price movements due to lack of market quotes for implied volatilities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) Includes swaps and physical and financial contracts.
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2013 and 2012 (dollars in millions):
Amounts included in earnings are recorded in either operating revenues or 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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our heat rate options and long-dated energy transactions that extend beyond available quoted periods.
Financial Instruments Not Carried at Fair Value
The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. See Note 6 for our long-term debt fair values.
15. Earnings Per Share
The following table presents earnings attributable to common shareholders per weighted-average common share outstanding for the years ended December 31, 2013, 2012 and 2011:
Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 822,000 shares in 2013, 1,017,000 shares in 2012 and 811,000 shares in 2011. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 110,805,943 shares in 2013, 110,527,311 shares in 2012 and 109,864,243 shares in 2011.
For the years ended 2013, 2012 and 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.
16. Stock-Based Compensation
Pinnacle West grants long-term incentive awards under the 2012 Long-Term Incentive Plan (“2012 Plan”) in the form of Stock Grants, Restricted Stock Units and Performance Shares and may grant restricted stock, stock units, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan, effective May 16, 2012, provides 4,595,500 common shares to be available for grant to eligible employees and members of the Board of Directors. Awards made since 2012 were issued under the 2012 Plan, and prior awards from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”).
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock Unit Awards and Stock Grants
Stock grants issued to non-officer members of the Board of Directors in 2013, 2012 and 2011, provided the members of the Board of 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. The members of the Board of Directors who elect to defer may elect to receive payment in either stock, or 50% in cash and 50% in stock. The members of the Board of Directors may elect to receive payments either as of the last business day of the month following the month in which they separate from service on the Board of Directors, or as of a specified date, which 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 Directors 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 are paid, based on the Director’s election, in either stock, or 50% in cash and 50% in stock.
Restricted stock units have been granted to officers and key employees 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. From 2010 through 2013, officers and key employees elected to receive payment in either stock, or 50% in cash and 50% in stock.
Restricted stock unit awards vest and settle over a four-year period. In addition, officers and key employees accrue dividend rights on 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 through 2013 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 the Company’s closing stock price, and remeasured at each balance sheet date. Compensation expense for retirement eligible participants is recognized immediately.
In December 2012, the Company granted a retention award of 50,617 restricted stock units to the Chairman of the Board, President, and Chief Executive Officer of Pinnacle West. The award will vest and will be paid in shares of common stock on December 31, 2016, provided that he remains employed with the Company until the vesting date. The award will accrue notional dividends equal to the amount of dividends that would have been received if the Chairman of the Board, President and Chief Executive Officer had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. The award can be increased up to an additional 33,745 restricted stock units payable in stock if certain performance requirements are met.
A 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 vested 50% on February 15, 2013. The remaining grant will vest 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 they would have received if they had directly owned one share of Pinnacle West common stock for each restricted stock unit held from the grant date to each dividend payment date. Each additional restricted stock unit
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 three years ended 2013, 2012 and 2011:
(a) Weighted-average grant date fair value.
The following table is a summary of the status of restricted stock units and stock grants, as of December 31, 2013 and changes during the year. This table represents only the stock portion of restricted stock units, per the election on payment discussed in the paragraph above:
The amount of cash required to settle the payments on restricted stock units is (dollars in millions):
Performance Share Awards
Performance share awards have been granted to officers and key employees under the 2012 Plan since 2012 and under the 2007 Plan from 2008 to 2011. Performance share awards contain two performance element criteria that affect the number of shares received after the end of a three-year performance period if performance criteria conditions are met.
The 2013, 2012 and 2011 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 utility index and the other 50% is 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,
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 liability awards, with compensation cost initially calculated on the date of grant using the Company’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 performance criteria are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
The following table is a summary of the performance shares granted and the weighted-average fair value for the three years ended 2013, 2012 and 2011:
(a) Reflects the target payout level.
(b) Weighted-average grant date fair value.
The following table is a summary of the status of performance shares, as of December 31, 2013 and changes during the year:
(a) Nonvested shares are reflected at target payout level. The increase or decrease in the number of shares from the target level to the estimated actual payout level is included in the increase for performance factor amounts in the year the award vests.
Stock Options
The Company has not granted stock options since 2004 and has no stock options outstanding.
The following table summarizes the option activity under prior equity incentive plans for the year ended December 31, 2013:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash received from options exercised under our share-based payment arrangements was $0.1 million for 2013, $0.5 million for 2012, and $1.8 million for 2011. 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, 2013, there was $17 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 2.0 years. The total fair value of shares vested during 2013, 2012 and 2011 was $20 million, $19 million and $14 million, respectively.
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $25 million in 2013, $32 million in 2012, and $23 million in 2011. 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 $10 million in 2013, $13 million in 2012, and $9 million in 2011. APS’s share of compensation cost that has been charged against income was $25 million in 2013, $32 million in 2012, and $22 million in 2011.
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 units and performance shares.
17. 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 may be 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, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
delivery periods) 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.
On June 1, 2012, we elected to discontinue cash flow hedge accounting treatment for the significant majority of our contracts that had previously been designated as cash flow hedges. This discontinuation is due to changes in PSA recovery (see Note 3), which now allows for 100% deferral of the unrealized gains and losses relating to these contracts. For those contracts that were de-designated, all changes in fair value after May 31, 2012 are no longer recorded through OCI, but are deferred through the PSA. The amounts previously recorded in accumulated OCI relating to these instruments will remain in accumulated OCI, and will transfer to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if we determine it is probable that the forecasted transaction will not occur. When amounts have been reclassified from accumulated OCI to earnings, they will be subject to deferral in accordance with the PSA. Cash flow hedge accounting treatment will continue for a limited number of contracts that are not subject to PSA recovery.
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 purchases 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 OCI 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 cash flow hedge accounting has been discontinued for the significant majority of our contracts, after May 31, 2012, effectiveness testing is no longer being performed for these contracts.
Prior to the 2012 Settlement Agreement, for its regulated operations, APS deferred 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. Due to the 2012 Settlement Agreement, for its regulated operations, APS now defers for future rate treatment 100% of the unrealized gains and losses for delivery periods after June 30, 2012 on 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2013, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
(a) “Bcf” is Billion Cubic Feet.
Gains and Losses from Derivative Instruments
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):
(a) During the years ended December 31, 2013, 2012, and 2011, we had zero, $1.8 million, and zero losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b) Amounts are before the effect of PSA deferrals.
During the next twelve months, we estimate that a net loss of $21 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, substantially all of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):
(a) Amounts are before the effect of PSA deferrals.
Derivative Instruments in the Consolidated Balance Sheets
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.
The significant majority of our derivative instruments are not currently designated as hedging instruments. The Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012, include gross liabilities of $5 million of derivative instruments designated as hedging instruments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2013 and 2012. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.
(a) All of our gross recognized derivative instruments were subject to master netting arrangements.
(b) Includes cash collateral provided to counterparties of $19,000.
(c) Represents cash collateral and margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $7,518, and cash margin provided to counterparties of $7.
(a) All of our gross recognized derivative instruments were subject to master netting arrangements.
(b) Includes cash collateral provided to counterparties of $49,299.
(c) Represents cash collateral relating to non-derivative instruments or derivatives qualifying for scope exceptions. Includes cash collateral provided to counterparties of $1,001, and cash collateral received from counterparties of $25,463. This amount is not subject to offsetting.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 92% of Pinnacle West’s $41 million of risk management assets as of December 31, 2013. This exposure relates to long-term traditional wholesale contracts with counterparties that have high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2013 (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 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 $180 million if our debt credit ratings were to fall below investment grade.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. Other Income and Other Expense
The following table provides detail of other income and other expense for 2013, 2012 and 2011 (dollars in thousands):
19. 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 during 2014 and 2015 related to these leases. The lease agreements include fixed rate renewal periods which 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. Predominately due to the fixed rate renewal periods, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
On December 31, 2012, APS notified the lessor trust entities that APS will retain the assets beyond 2015 by either exercising the fixed rate lease renewals or by purchasing the assets. If APS elects to purchase the assets, the purchase price will be based on the fair market value of the assets at the end of 2015. If APS elects to extend the leases, we will be required to make payments beginning in 2016 of approximately $23 million annually. The length of the lease extensions is unknown at this time, as it must be determined through an appraisal process. APS must give notice to the lessor trusts by June 30, 2014 notifying them which of these two options (lease renewal or purchasing the assets) it will exercise. The December 31, 2012 notification does not impact APS’s consolidation of the VIEs, as APS continues to be deemed the primary beneficiary of the VIEs.
As a result of consolidation, we eliminate rent expense and recognize depreciation and interest expense, resulting in an increase in net income for 2013, 2012 and 2011 of $34 million, $32 million and $28 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our Consolidated Balance Sheets at December 31, 2013 and December 31, 2012 include the following amounts relating to the VIEs (in millions):
Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets reported on our consolidated financial statements, the creditors of the VIEs have no other recourse to the assets of APS or Pinnacle West, except in certain circumstances, such as a default by APS under the lease.
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider 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 Palo Verde 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, 2013, APS would have been required to pay the noncontrolling equity participants approximately $133 million and assume $39 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.
20. Nuclear Decommissioning Trusts
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 stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at December 31, 2013 and December 31, 2012 (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) Net payables relate to pending purchases and sales of securities.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
(a) Proceeds are reinvested in the trust.
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2013 is as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
21. Changes in Accumulated Other Comprehensive Loss
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):
(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 17.
(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8.
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 APS. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework (1992), our management concluded that our internal control over financial reporting was effective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31, 2013 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 21, 2014
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, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 21, 2014
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 STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to APS’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 APS’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 APS’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 APS’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 APS’s Consolidated Financial Statements.
Certain notes to APS’s consolidated financial statements are combined with the notes to Pinnacle West’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West’s consolidated financial statements, the majority of which also relate to APS’s consolidated financial statements. In addition, listed below are the supplemental notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’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 ITCs are deferred and are amortized over the life of the related property, with such amortization applied as a credit to reduce current income tax expense in the statement of income.
The $71 million long-term income tax receivable on APS’s Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the IRS in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities. Additionally, as a result of this IRS guidance, the $138 million anticipated refund was reclassified to current income tax receivable.
During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $138 million anticipated refund was reduced by approximately $2 million to reflect the outcome of this examination. On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund. Cash related to this refund was received in the first quarter of 2014.
On September 13, 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. To account for the adoption of these regulations plant-related long-term deferred tax liabilities decreased by $84 million, with the offsetting decrease to current deferred income tax assets. Prior to the issuance of these regulations, this $84 million would have been repaid over 20 years through lower tax depreciation deductions.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 19). As a result, there is no income tax expense associated with the VIEs recorded on APS’s Consolidated Statements of Income.
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2013, 2012 and 2011 were approximately $10 million, $10 million and $8 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.
As of the balance sheet date, the tax year ended December 31, 2010 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2010.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Statements 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 benefit of $4 million for 2013, a pre-tax expense of $4 million for 2012 and a pre-tax expense of $3 million for 2011.
The total amount of accrued liabilities for interest recognized in the Balance Sheets related to unrecognized tax benefits was less than $1 million as of December 31, 2013, $13 million as of December 31, 2012 and $9 million as of December 31, 2011. To the extent that matters are settled favorably, this amount could be reversed and decrease our effective tax rate. Additionally, as of December 31, 2013, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 has revised the tax rate applicable to reversing temporary items in Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2013, APS has recorded a regulatory liability of $75 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
On April 4, 2013, New Mexico enacted legislation (H.B. 641) that included a five-year phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in New Mexico. In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability. As of December 31, 2013, APS has recorded a regulatory liability of $2 million, with a corresponding decrease in accumulated deferred income tax liabilities, to reflect the impact of this change in tax law.
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, 2013, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits which first begin to expire in 2031.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2013 and 2012 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 2013, 2012 and 2011 (dollars in thousands):
(a) As defined by FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
S-4. Changes in Accumulated Other Comprehensive Loss
The following table shows the changes in accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the year ended December 31, 2013 (dollars in thousands):
(a) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 17.
(b) These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE 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, 2013. 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, 2013. 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
No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended December 31, 2013 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 21, 2014 (the “2014 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 General Counsel, the President and Chief Operating Officer of APS and other persons designated as financial executives by the Chair of the Audit Committee. The Code of Ethics for Financial Executives is posted on Pinnacle West’s website (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 2014 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to “Ownership of Pinnacle West Stock” in the 2014 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2013 with respect to the 2012 Plan, the 2007 Plan and the 2002 Long-Term Incentive Plan (the “2002 Plan”), under which our equity securities are outstanding or currently authorized for issuance.
Equity Compensation Plan Information
(a) This amount includes shares subject to outstanding options, as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.
(b) The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.
(c) Awards under the 2012 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units. Additional shares cannot be awarded under either the 2002 Plan or the 2007 Plan. However, if an award under the 2012 Plan or an award that was outstanding under either the 2002 Plan or the 2007 Plan on or after December 31, 2011 is forfeited, terminated or cancelled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation or expiration, may be added back to the shares available for issuance under the 2012 Plan.
Equity Compensation Plans Approved By Security Holders
Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were previously approved by our shareholders: (a) the 2002 Plan, which was approved by our shareholders at our 2002 annual meeting of shareholders and under which no new stock awards may be granted; (b) the 2007 Plan, which was approved by our shareholders at our 2007 annual meeting of shareholders and under which no new stock awards may be granted; and (c) the 2012 Plan, which was approved by our shareholders at our 2012 annual meeting of shareholders. See
Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.
Equity Compensation Plans Not Approved by Security Holders
The Company does not have any equity compensation plans under which shares can be issued that have not been approved by the shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the 2014 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 2014 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 2013 and 2012.
(3) The aggregate fees billed primarily related to tax compliance and tax planning.
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 Chair 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 Chair 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 in 2013 were pre-approved by the Audit Committee or the Chair of the Audit Committee consistent with the pre-approval policy.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
3.1
Pinnacle West
Articles of Incorporation, restated as of May 21, 2008
3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962
8-7-08
3.2
Pinnacle West
Pinnacle West Capital Corporation Bylaws, amended as of May 19, 2010
3.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962
8-3-10
3.3
APS
Articles of Incorporation, restated as of May 25, 1988
4.2 to APS’s Form 18 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473
9-29-93
3.3.1
APS
Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012
3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473
5-22-12
3.4
APS
Arizona Public Service Company Bylaws, amended as of December 16, 2008
3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473
2-20-09
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
4.1
Pinnacle West
Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value
4.1 to Pinnacle West June 28, 2011 Form 8-K Report, File No. 1-8962
6-28-11
4.2
Pinnacle West
APS
Indenture dated as of January 1, 1995 among APS and The Bank of New York Mellon, as Trustee
4.6 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473
1-11-95
4.2a
Pinnacle West
APS
First Supplemental Indenture dated as of January 1, 1995
4.4 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473
1-11-95
4.3
Pinnacle West
APS
Indenture dated as of November 15, 1996 between APS and The Bank of New York, as Trustee
4.5 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473
11-22-96
4.3a
Pinnacle West
APS
First Supplemental Indenture dated as of November 15, 1996
4.6 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473
11-22-96
4.3b
Pinnacle West
APS
Second Supplemental Indenture dated as of April 1, 1997
4.10 to APS’s Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473
4-9-97
4.3c
Pinnacle West
APS
Third Supplemental Indenture dated as of November 1, 2002
10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962
5-15-03
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
4.4
Pinnacle West
Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Unsecured Debt Securities
4.1 to Pinnacle West’s Registration Statement No. 333-52476
12-21-00
4.5
Pinnacle West
Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Subordinated Unsecured Debt Securities
4.2 to Pinnacle West’s Registration Statement No. 333-52476
12-21-00
4.6
Pinnacle West
APS
Indenture dated as of January 15, 1998 between APS and The Bank of New York Mellon Trust Company N.A. (successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank), as Trustee
4.10 to APS’s Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473
1-16-98
4.6c
Pinnacle West
APS
Seventh Supplemental Indenture dated as of May 1, 2003
4.1 to APS’s Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473
5-9-03
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
4.6d
Pinnacle West
APS
Eighth Supplemental Indenture dated as of June 15, 2004
4.1 to APS’s Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473
6-28-04
4.6e
Pinnacle West
APS
Ninth Supplemental Indenture dated as of August 15, 2005
4.1 to APS’s Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473
8-22-05
4.6f
APS
Tenth Supplemental Indenture dated as of August 1, 2006
4.1 to APS’s July 31, 2006 Form 8-K Report, File No. 1-4473
8-3-06
4.6g
Pinnacle West
APS
Eleventh Supplemental Indenture dated as of February 26, 2009
4.1 to Pinnacle West/APS February 23, 2009 Form 8-K Report, File Nos. 1-8962 and 1-4473
2-25-09
4.6h
Pinnacle West
APS
Twelfth Supplemental Indenture dated as of August 25, 2011
4.1 to Pinnacle West/APS August 22, 2011 Form 8-K Report, File Nos. 1-8962 and 1-4473
8-24-11
4.6i
Pinnacle West
APS
Thirteenth Supplemental Indenture dated as of January 13, 2012
4.1 to Pinnacle West/APS January 10, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473
1-12-12
4.7
Pinnacle West
Second Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of June 23, 2004
4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962
8-9-04
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
4.7a
Pinnacle West
Third Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of November 25, 2008
4.1 to Pinnacle West’s Form S-3 Registration Statement No. 333-155641, File No. 1-8962
11-25-08
4.8
Pinnacle West
Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets
4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962
3-30-88
4.8a
Pinnacle West
APS
Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’s total assets
4.1 to APS’s 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.1.1
Pinnacle West
APS
Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee
10.2 to APS’s September 30, 1991 Form 10-Q Report, File No. 1-4473
11-14-91
10.1.1a
Pinnacle West
APS
Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994
10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473
3-30-95
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.1.1b
Pinnacle West
APS
Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994
10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473
3-30-95
10.1.1c
Pinnacle West
APS
Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991
10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473
3-28-97
10.1.1d
Pinnacle West
APS
Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991
10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.1.1e
Pinnacle West
APS
Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002
10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.1f
Pinnacle West
APS
Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002
10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.1g
Pinnacle West
APS
Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003
10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
10.1.1h
Pinnacle West
APS
Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003
10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.1.1i
Pinnacle West
APS
Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007
10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-9-07
10.1.1j
Pinnacle West
APS
Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007
10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473
5-9-07
10.1.2
Pinnacle West
APS
Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2
10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962
3-26-92
10.1.2a
Pinnacle West
APS
First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992
10.2 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.1.2b
Pinnacle West
APS
Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994
10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473
3-30-95
10.1.2c
Pinnacle West
APS
Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 20, 1996
10.1 to APS’s June 30, 1996 Form 10-Q Report, File No. 1-4473
8-9-96
10.1.2d
Pinnacle West
APS
Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of December 16, 1996
APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473
3-28-97
10.1.2e
Pinnacle West
APS
Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000
10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.2f
Pinnacle West
APS
Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002
10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962
5-15-02
10.1.2g
Pinnacle West
APS
Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003
10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.1.2h
Pinnacle West
APS
Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of April 1, 2007
10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962
2-27-08
10.2.1b
Pinnacle West
APS
Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively
10.4 to APS’s 1988 Form 10-K Report, File No. 1-4473
3-8-89
10.2.1ab
Pinnacle West
APS
Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993
10.3A to APS’s 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.2.1bb
Pinnacle West
APS
Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993
10.2 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473
11-10-94
10.2.1cb
Pinnacle West
APS
Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997
10.3A to APS’s 1996 Form 10-K Report, File No. 1-4473
3-28-97
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.2.1db
Pinnacle West
APS
Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001
10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962
3-14-01
10.2.2b
Pinnacle West
APS
Arizona Public Service Company Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986
10.1 to APS’s June 30, 1986 Form 10-Q Report, File No. 1-4473
8-13-86
10.2.2ab
Pinnacle West
APS
Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993
10.2A to APS’s 1993 Form 10-K Report, File No. 1-4473
3-30-94
10.2.2bb
Pinnacle West
APS
Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993
10.1 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473
11-10-94
10.2.2cb
Pinnacle West
APS
Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999
10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.2.3b
Pinnacle West
APS
Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996
10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.3ab
Pinnacle West
APS
First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans
10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.4b
Pinnacle West
APS
Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996
10.10A to APS’s 1995 Form 10-K Report, File No. 1-4473
3-29-96
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.2.4ab
Pinnacle West
APS
First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan
10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.4bb
Pinnacle West
APS
Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan
10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962
3-30-00
10.2.4cb
Pinnacle West
APS
Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002
10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962
5-15-03
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.2.4db
Pinnacle West
APS
Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003
10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.2.5b
Pinnacle West
APS
Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.2.6 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-20-09
10.2.5ab
Pinnacle West
APS
First Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.2.6a to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-19-10
10.2.5bb
Pinnacle West
APS
Second Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.2.5b to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
10.2.5cb
Pinnacle West
APS
Third Amendment to the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.3.1b
Pinnacle West
APS
Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003
10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962
3-15-04
10.3.1ab
Pinnacle West
APS
Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003
10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.3.2b
Pinnacle West
APS
Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005
10.3.2 to Pinnacle West/APS 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-20-09
10.4.1b
APS
Letter Agreement dated December 20, 2006 between APS and Randall K. Edington
10.78 to Pinnacle West/APS 2006 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-28-07
10.4.2b
APS
Letter Agreement dated July 22, 2008 between APS and Randall K. Edington
10.3 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473
8-07-08
10.4.3b
Pinnacle West
APS
Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield
10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-07-08
10.4.4b
APS
Supplemental Agreement dated December 26, 2008 between APS and Randall K. Edington
10.4.10 to Pinnacle West/APS 2008 Form 10-K Report, File No. 1-4473
2-20-09
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.4.5b
APS
Description of 2010 Palo Verde Specific Compensation Opportunity for Randall K. Edington
10.4.13 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-19-10
10.4.6 b
Pinnacle West
Letter Agreement dated May 21, 2009, between Pinnacle West and David P. Falck
10.4 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File No. 1-8962
5-6-10
10.4.7 b
APS
Supplemental Agreement dated June 19, 2012 between APS and Randall K. Edington
10.1 to Pinnacle West/APS June 30, 2012 Form 10-Q Report File Nos. 1-8962 and 1-4473
8-2-12
10.4.8 b
APS
Description of 2013 Palo Verde Specific Compensation Opportunity for Randall K. Edington
Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-4473
12-26-12
10.5.1bd
Pinnacle West
APS
Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries
10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.5.1abd
Pinnacle West
APS
Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
11-6-07
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.5.2bd
Pinnacle West
APS
Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473
11-6-07
10.5.3bd
Pinnacle West
APS
Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.5.3 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-19-10
10.5.4 bd
Pinnacle West
APS
Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries
10.5.4 to Pinnacle West/APS 2012 Form 10-K, File Nos. 1-8962 and 1-4473
2-22-13
10.6.1b
Pinnacle West
APS
Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.5A to Pinnacle West’s 2002 Form 10-K Report
3-31-03
10.6.1abd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473
12-15-05
10.6.1bbd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473
2-1-06
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.6.1cbd
Pinnacle West
APS
Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.6.1dbd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.6.2b
Pinnacle West
Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962
4-20-07
10.6.2ab
Pinnacle West
First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962
4-20-07
10.6.2bbd
Pinnacle West
APS
Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-5-09
10.6.2cbd
Pinnacle West
Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962
8-3-10
10.6.2dbd
Pinnacle West
Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.2 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962
8-3-10
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.6.2ebd
Pinnacle West
Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.4 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962
4-29-11
10.6.2fbd
Pinnacle West
Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.5 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962
4-29-11
10.6.2gbd
Pinnacle West
Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (Supplemental 2010 Award)
10.6 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962
4-29-11
10.6.3b
Pinnacle West
Description of Annual Stock Grants to Non-Employee Directors
10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962
11-6-07
10.6.4b
Pinnacle West
Description of Stock Grant to W. Douglas Parker
10.2 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962
11-6-07
10.6.5b
Pinnacle West
Description of Annual Stock Grants to Non-Employee Directors
10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962
8-07-08
10.6.6bd
Pinnacle West
APS
Summary of 2014 CEO Variable Incentive Plan and Officer Variable Incentive Plan
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.6.7
Pinnacle West
Description of Restricted Stock Unit Grant to Donald E. Brandt
Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-8962
12-26-12
10.6.8b
Pinnacle West
APS
Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
Appendix A to the Proxy Statement for Pinnacle West’s 2012 Annual Meeting of Shareholders, File No. 1-8962
3-29-12
10.6.8abd
Pinnacle West
Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.1 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-3-12
10.6.8bbd
Pinnacle West
Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.2 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-3-12
10.6.8cbd
Pinnacle West
Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.6.8dbd
Pinnacle West
Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan
10.6.8ebd
Pinnacle West
Master Amendment to Performance Share Agreements
10.3 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-3-12
10.6.8fbd
Pinnacle West
Master Amendment to Restricted Stock Unit Agreements
10.4 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-3-12
10.7.1
Pinnacle West
APS
Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant
5.01 to APS’s Form S-7 Registration Statement, File No. 2-59644
9-1-77
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.7.1a
Pinnacle West
APS
Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant
5.02 to APS’s Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.1b
Pinnacle West
APS
Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985
10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962
7-25-85
10.7.1c
Pinnacle West
APS
Amendment and Supplement No. 2 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011
10.1 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473
4-29-11
10.7.1d
Pinnacle West
APS
Amendment and Supplement No. 3 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011
10.2 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473
4-29-11
10.7.2
Pinnacle West
APS
Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site
5.04 to APS’s Form S-7 Registration Statement, File No. 2-59644
9-1-77
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.7.2a
Pinnacle West
APS
Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Site dated April 25, 1985
10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962
7-25-85
10.7.3
Pinnacle West
APS
Application and Grant of APS rights- of-way and easements, Four Corners Site
5.05 to APS’s Form S-7 Registration Statement, File No. 2-59644
9-1-77
10.7.3a
Pinnacle West
APS
Application and Amendment No. 1 to Grant of APS rights-of-way and easements, Four Corners Site dated April 25, 1985
10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962
7-25-85
10.7.4
Pinnacle West
APS
Four Corners Project Co-Tenancy Agreement Amendment No. 6
10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962
3-14-01
10.8.1
Pinnacle West
APS
Indenture of Lease, Navajo Units 1, 2, and 3
5(g) to APS’s Form S-7 Registration Statement, File No. 2-36505
3-23-70
10.8.2
Pinnacle West
APS
Application of Grant of rights-of-way and easements, Navajo Plant
5(h) to APS Form S-7 Registration Statement, File No. 2-36505
3-23-70
10.8.3
Pinnacle West
APS
Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant
5(l) to APS’s Form S-7 Registration Statement, File No. 2-394442
3-16-71
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.8.4
Pinnacle West
APS
Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998
10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.8.5
Pinnacle West
APS
Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971
10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.9.1
Pinnacle West
APS
ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto
10. 1 to APS’s 1988 Form 10-K Report, File No. 1-4473
3-8-89
10.9.1a
Pinnacle West
APS
Amendment No. 13, dated as of April 22, 1991, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
10.1 to APS’s March 31, 1991 Form 10-Q Report, File No. 1-4473
5-15-91
10.9.1b
Pinnacle West
APS
Amendment No. 14 to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962
8-14-00
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.9.1c
Pinnacle West
APS
Amendment No. 15, dated November 29, 2010, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
10.9.1c to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-18-11
10.10.1
Pinnacle West
APS
Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991
10.1 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473
8-8-91
10.10.2
Pinnacle West
APS
Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991
10.2 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473
8-8-91
10.10.2a
Pinnacle West
APS
Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS
10.3 to APS’s 1995 Form 10-K Report, File No. 1-4473
3-29-96
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.10.3
Pinnacle West
APS
Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995
10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.10.4
Pinnacle West
APS
Contract among PacifiCorp, APS and DOE Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995
10.5 to APS’s 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.10.5
Pinnacle West
APS
Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994
10.6 to APS’s 1995 Form 10-K Report, File No. 1-4473
3-29-96
10.11.1
Pinnacle West
APS
Five-Year Credit Agreement dated as of November 4, 2011 between APS, as Borrower, Barclays Bank PLC, as Agent, and the lenders and other parties thereto
10.11.1 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
10.11.2
Pinnacle West
Term Loan Agreement dated as of November 29, 2012 among Pinnacle West, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the lenders and other parties thereto
10.11.2 to Pinnacle West/APS 2012 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-22-13
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.11.3
Pinnacle West
Five-Year Credit Agreement dated as of November 4, 2011 among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent, and the lenders and other parties thereto
10.11.3 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
10.11.4
APS
$500,000,000 Four-Year Credit Agreement dated as of February 14, 2011 among APS as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, Credit Suisse Securities (USA) LLC, as Syndication Agent, Credit Suisse AG, Cayman Islands Branch, as Issuing Bank, Bank of America, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents and the other parties thereto
10.11.4 to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-18-11
10.11.5
Pinnacle West
APS
Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010
10.2 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-6-10
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.11.5a
Pinnacle West
APS
Amendment No. 1 to the Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated December 22, 2011
10.11.5a to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
10.11.6
Pinnacle West
APS
Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated as of April 16, 2010
10.3 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-6-10
10.11.6a
Pinnacle West
APS
Amendment No. 1 to the Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, dated December 22, 2011
10.11.6a to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
10.11.7
APS
Five-Year Credit Agreement dated as of April 9, 2013 among APS, as Borrower, Barclays Bank PLC, as Agent and the lenders and other parties thereto
10.1 to Pinnacle West/APS March 31, 2013 Form 10-Q Report, File Nos. 1-8692 and 1-4473
5-3-13
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.12.1c
Pinnacle West
APS
Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
4.3 to APS’s Form 18 Registration Statement, File No. 33-9480
10-24-86
10.12.1ac
Pinnacle West
APS
Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
10.5 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473
12-4-86
10.12.1bc
Pinnacle West
APS
Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.3 to APS’s 1988 Form 10-K Report, File No. 1-4473
3-8-89
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.12.1cc
Pinnacle West
APS
Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.3 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
10.12.2
Pinnacle West
APS
Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
10.1 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473
1-20-87
10.12.2a
Pinnacle West
APS
Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473
8-24-87
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.12.2b
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
10.4 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
10.13.1
Pinnacle West
APS
Agreement between Pinnacle West Energy Corporation and APS for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th day of April, 2001
10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.2
Pinnacle West
APS
Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001
10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.3
Pinnacle West
APS
Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP
10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.13.4
Pinnacle West
APS
Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP
10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.5
Pinnacle West
APS
Municipal Effluent Purchase and Sale Agreement dated April 29, 2010, by and between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, City of Glendale, APS and SRP
10.1 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473
5-6-10
10.14.1
Pinnacle West
APS
Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP
10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386
3-13-85
10.15.1
Pinnacle West
APS
Territorial Agreement between APS and SRP
10.1 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.2
Pinnacle West
APS
Power Coordination Agreement between APS and SRP
10.2 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.3
Pinnacle West
APS
Memorandum of Agreement between APS and SRP
10.3 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473
5-15-98
10.15.3a
Pinnacle West
APS
Addendum to Memorandum of Agreement between APS and SRP dated as of May 19, 1998
10.2 to APS’s May 19, 1998 Form 8-K Report, File No. 1-4473
6-26-98
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
10.16
Pinnacle West
APS
Purchase and Sale Agreement dated November 8, 2010 by and between SCE and APS
10.1 to Pinnacle West/APS November 8, 2010 Form 8-K Report, File Nos. 1-8962 and 1-4473
11-8-10
10.17
Pinnacle West
APS
Proposed Settlement Agreement dated January 6, 2012 by and among APS and certain parties to its retail rate case (approved by ACC Order No. 73183)
10.17 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473
2-24-12
12.1
Pinnacle West
Ratio of Earnings to Fixed Charges
12.2
APS
Ratio of Earnings to Fixed Charges
12.3
Pinnacle West
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
21.1
Pinnacle West
Subsidiaries of Pinnacle West
23.1
Pinnacle West
Consent of Deloitte & Touche LLP
23.2
APS
Consent of Deloitte & Touche LLP
31.1
Pinnacle West
Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
31.2
Pinnacle West
Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3
APS
Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4
APS
Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1e
Pinnacle West
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2e
APS
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.1
Pinnacle West
APS
Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee
4.2 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.1a
Pinnacle West
APS
Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee
4.3 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.2c
Pinnacle West
APS
Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
28.1 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473
11-9-92
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.2ac
Pinnacle West
APS
Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
10.8 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473
12-4-86
99.2bc
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein
28.4 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.3c
Pinnacle West
APS
Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
4.5 to APS’s Form 18 Registration Statement, File No. 33-9480
10-24-86
99.3ac
Pinnacle West
APS
Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
10.6 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473
12-4-86
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.3bc
Pinnacle West
APS
Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee
4.4 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.4c
Pinnacle West
APS
Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.3 to APS’s Form 18 Registration Statement, File No. 33-9480
10-24-86
99.4ac
Pinnacle West
APS
Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
10.10 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473
12-4-86
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.4bc
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.6 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.5
Pinnacle West
APS
Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein
28.2 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473
11-9-92
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.5a
Pinnacle West
APS
Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein
28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473
8-10-87
99.5b
Pinnacle West
APS
Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein
28.5 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.6
Pinnacle West
APS
Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
10.2 to APS’s November 18, 1986 Form 10-K Report, File No. 1-4473
1-20-87
99.6a
Pinnacle West
APS
Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473
8-24-87
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.6b
Pinnacle West
APS
Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee
4.5 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.7
Pinnacle West
APS
Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
10.5 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473
1-20-87
99.7a
Pinnacle West
APS
Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
28.7 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
99.8c
Pinnacle West
APS
Indemnity Agreement dated as of March 17, 1993 by APS
28.3 to APS’s 1992 Form 10-K Report, File No. 1-4473
3-30-93
99.9
Pinnacle West
APS
Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank
28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473
8-10-87
99.10
Pinnacle West
APS
ACC Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules
10.2 to APS’s September 30, 1999 Form 10-Q Report, File No. 1-4473
11-15-99
99.11
Pinnacle West
Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005
99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473
8-9-05
101.INS
Pinnacle West
APS
XBRL Instance Document
101.SCH
Pinnacle West
APS
XBRL Taxonomy Extension Schema Document
101.CAL
Pinnacle West
APS
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
Pinnacle West
APS
XBRL Taxonomy Extension Label Linkbase Document
Exhibit
No.
Registrant(s)
Description
Previously Filed as Exhibit: a
Date
Filed
101.PRE
Pinnacle West
APS
XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
Pinnacle West
APS
XBRL Taxonomy Definition Linkbase Document
aReports 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.
bManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.
cAn 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.
dAdditional 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.
eFurnished 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 21, 2014
/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
February 21, 2014
(Donald E. Brandt, Chairman
and Director
of the Board of Directors, President
and Chief Executive Officer)
/s/ James R. Hatfield
Principal Financial Officer
February 21, 2014
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner
Principal Accounting Officer
February 21, 2014
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)
/s/ Susan Clark-Johnson
Director
February 21, 2014
(Susan Clark-Johnson)
/s/ Denis A. Cortese, M.D.
Director
February 21, 2014
(Denis A. Cortese, M.D.)
/s/ Michael L. Gallagher
Director
February 21, 2014
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.
Director
February 21, 2014
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.
Director
February 21, 2014
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez
Director
February 21, 2014
(Humberto S. Lopez)
/s/ Kathryn L. Munro
Director
February 21, 2014
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom
Director
February 21, 2014
(Bruce J. Nordstrom)
Director
February 21, 2014
(Richard P. Fox)
Director
February 21, 2014
(David P. Wagener)
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 21, 2014
/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 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
February 21, 2014
(Donald E. Brandt, Chairman
and Director
of the Board of Directors, President and
Chief Executive Officer)
/s/ James R. Hatfield
Principal Financial Officer
February 21, 2014
(James R. Hatfield,
Executive Vice President and
Chief Financial Officer)
/s/ Denise R. Danner
Principal Accounting Officer
February 21, 2014
(Denise R. Danner,
Vice President, Controller and
Chief Accounting Officer)
/s/ Susan Clark-Johnson
Director
February 21, 2014
(Susan Clark-Johnson)
/s/ Denis A. Cortese, M.D.
Director
February 21, 2014
(Denis A. Cortese, M.D.)
/s/ Michael L. Gallagher
Director
February 21, 2014
(Michael L. Gallagher)
/s/ Roy A. Herberger, Jr., Ph.D.
Director
February 21, 2014
(Roy A. Herberger, Jr., Ph.D.)
/s/ Dale E. Klein, Ph.D.
Director
February 21, 2014
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez
Director
February 21, 2014
(Humberto S. Lopez)
/s/ Kathryn L. Munro
Director
February 21, 2014
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom
Director
February 21, 2014
(Bruce J. Nordstrom)
Director
February 21, 2014
(Richard P. Fox)
Director
February 21, 2014
(David P. Wagener)