ITEM 1. BUSINESS
OVERVIEW
General
Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of the outstanding equity securities of APS, its major subsidiary. 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 principal subsidiary is SunCor, which is engaged in real estate development activities in the western United States. See “Business of SunCor Development Company” in this Item 1. Pinnacle West’s other first-tier subsidiaries, APSES, El Dorado and Pinnacle West Marketing & Trading are discussed in “Business of Other Subsidiaries” in this Item 1.
Pinnacle West Energy, which owned and operated unregulated generating plants, transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% ownership interest in Silverhawk to NPC on January 10, 2006. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.
Business Segments
Pinnacle West has two principal business segments (determined by products, services and the regulatory environment):
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the regulated electricity segment (accounting for 83% of operating revenues in 2007), which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution; and
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the real estate segment (accounting for 6% of operating revenues in 2007), which consists of SunCor’s real estate development and investment activities.
See Note 17 for financial information about the business segments.
APS ACC Proceedings
The key issue affecting Pinnacle West’s and APS’ financial outlook is adequate and timely retail rate treatment by the ACC. Note 3 discusses the results of APS’ most recent retail rate case as well as other rate matters.
Employees
At December 31, 2007, Pinnacle West employed approximately 7,600 people, including the employees of its subsidiaries. Of these employees, approximately 6,800 were employees of APS, including employees at jointly-owned generating facilities (approximately 3,000 employees) for which APS serves as the generating facility manager. Approximately 800 people were employed by Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
Available Information
Pinnacle West makes available free of charge on or through its internet site, (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: its Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q, its Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934.
Pinnacle West also has a Corporate Governance webpage. You can access Pinnacle West’s Corporate Governance webpage through its internet site, www.pinnaclewest.com, by clicking on the “About Us” link to the heading “Corporate Commitments.” Pinnacle West posts the following on its Corporate Governance webpage:
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Corporate Governance Guidelines;
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Board Committee Summary;
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Charters for Pinnacle West’s Audit Committee, Corporate Governance Committee, Finance, Nuclear and Operating Committee and Human Resources Committee;
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Code of Ethics for Financial Professionals;
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Ethics Policy and Standards of Business Practices;
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Director Independence Standards;
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Executive Officer Stock Ownership Guidelines; and
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Restricted Stock Retention Policy.
Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its internet site. The information on Pinnacle West’s internet site is not incorporated by reference into this report.
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).
Forward-Looking Statements
This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A
ITEM 1A. RISK FACTORS
In addition to the factors affecting specific business operations identified in connection with the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results. Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.
APS is subject to comprehensive government regulation by several federal, state and local regulatory agencies that could have a material adverse impact on its business and results of operations.
APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business and results of operations. The ACC regulates APS’ retail electric rates and APS’ issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between us, APS and our respective affiliates. While approved electric rates are intended to permit APS to recover its costs of service and earn a reasonable rate of return, the profitability of APS is affected by the rates it may charge. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings and ancillary matters which are before or which may come before the ACC.
APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS’ business. The FERC, the NRC, the EPA, and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and, as noted in the preceding paragraph, the rates that APS can charge customers. We believe the necessary permits, approvals and certificates have been obtained for APS’ existing operations and that APS’ business is
conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of additional 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 NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. In early 2007, the NRC placed Palo Verde Unit 3 in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime, including on-site in-depth inspections of Palo Verde equipment and operations. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS management has been conducting site-wide assessments of equipment and operations. APS continues to cooperate fully with the NRC throughout this process. The enhanced NRC inspection regime and APS’ ongoing commitment to the conservatively safe operation of Palo Verde could result in NRC action or an APS decision to shut down one or more units in the event of noncompliance with operating requirements or in light of other operational considerations.
APS is subject to numerous environmental laws and regulations that may increase its cost of operations, impact its business plans, or expose it to environmental liabilities.
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, and hazardous waste. 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, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if APS fails to obtain, maintain or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses. In addition, failure to comply with applicable environmental laws and regulations could result in civil liability or criminal penalties. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’ customers, could have a material adverse effect on our financial position, results of operations or cash flows.
Concern over climate change could result in significant legislative and regulatory efforts to limit greenhouse gas emissions or related litigation, which may increase APS’ cost of operations.
Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gasses, including a recent lawsuit filed against us and several other utilities, seeking damages related to climate change. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law; however, there is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect to greenhouse gas emissions. If the United States Congress, or individual states or groups of states in which we operate, ultimately pass legislation regulating the emissions of greenhouse gases, any resulting limitations on generation facility CO2 and other greenhouse gas emissions could result in the creation of substantial additional costs in the form of taxes, emissions allowances or required equipment upgrades and could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal fired facilities), including ours.
There are inherent risks in the operation of nuclear facilities, such as environmental, health and financial risks and the risk of terrorist attack.
Through APS, we have an ownership interest in and operate, on behalf of a group of owners, Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to 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.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime, which could ultimately result in the shut down of a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. See the first risk factor above for a discussion of the enhanced NRC inspection regime currently in effect at Palo Verde and the related operational and regulatory implications. In addition, 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 or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
The operation of power generation facilities involves risks that could result in unscheduled power outages or reduced output, which could materially affect our results of operations.
The operation of power generation facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications occur from time to time and are an inherent risk of our business. If APS’ facilities operate below expectations, we may lose revenue or incur additional expenses.
Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on our business and our financial results.
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect APS’ load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase.
Changes in technology may adversely affect our business.
Research and development activities are ongoing to improve alternative technologies to produce power, including fuel cells, micro turbines, clean coal and coal gasification, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these, or other technologies could reduce the cost of power production, making APS’ generating facilities less competitive. In addition, advances in technology could reduce the demand for power supply, which could adversely affect APS’ business.
Our results of operations can be adversely affected by 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, our 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 our results of operations and harm our financial condition.
Our cash flow largely depends on the performance of our subsidiaries.
We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.
The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. An ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. The common equity ratio, as defined in the ACC order, is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt.
Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.
Because we are structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their assets and cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.
Financial market disruptions may increase our financing costs or limit our access to the credit markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:
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an economic downturn;
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the bankruptcy of an unrelated energy company;
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increased market prices for electricity and gas;
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terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies;
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changes in technology; or
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the overall health of the utility or real estate industry.
Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:
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increasing the cost of future debt financing;
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increasing our vulnerability to adverse economic and industry conditions;
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requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and
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placing us at a competitive disadvantage compared with our competitors that have less debt.
Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of APS’ pollution control bonds are periodically reset through auction processes. These bonds are supported by bond insurance policies provided by Ambac, and the interest rates on those bonds are directly affected by the rating of the bond insurer. Accordingly, interest rates on these bonds have recently increased. We do not expect, however, that any such increase will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.
A reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.
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 could limit our access to capital and increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade could 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 limit our 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.
The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.
Our operations include managing market risks related to commodity prices and, subject to specified risk parameters, engaging in marketing and trading activities intended to profit from market price movements. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. 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, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.
Changing interest rates affect interest paid on variable-rate debt and interest earned on variable-rate securities in our pension plan, other postretirement benefit plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and other postretirement benefit liabilities are also impacted by the discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates impact the discount rate, and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income. The pension plan, other postretirement benefit and nuclear decommissioning trust funds also have risks associated with changing market values of fixed income and equity investments. A significant portion of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.
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:
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variations in our quarterly operating results;
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operating results that vary from the expectations of management, securities analysts and investors;
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changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;
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developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries;
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announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
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announcements by third parties of significant claims or proceedings against us;
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favorable or adverse regulatory or legislative developments;
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our dividend policy;
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future sale of equity or equity-linked securities; and
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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.
We may enter into credit and other agreements from time to time that restrict our ability to pay dividends.
Payment of dividends on our common stock may be restricted by credit and other agreements entered into by us from time to time. There are currently no material restrictions on our ability to pay dividends under any such agreement.
SunCor’s business and financial performance could be adversely affected by a variety of factors affecting the real estate market.
SunCor’s business and financial performance could continue to be adversely affected by a variety of factors affecting the real estate market, including downward changes in general economic, real estate construction or other business conditions; the potential overvaluation of land and new homes, which could result in an economic down cycle for the homebuilding industry; future increases in interest rates, reductions in mortgage availability or increases in the effective costs of owning a home, which could prevent potential customers from buying homes in SunCor’s developments; competition for homebuyers or commercial customers or partners, which could reduce SunCor’s profitability; supply shortages and other risks related to the demand for skilled labor and building materials, which could increase costs and delay deliveries; government regulations, which could increase the cost and limit the availability of SunCor’s development, homebuilding and commercial projects; and inflation, which could result in increased costs that SunCor may not be able to recoup if demand declines.
ITEM 1B.
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 2007 fiscal year and that remain unresolved.
ITEM 2.
ITEM 2. PROPERTIES
Information Regarding Our Properties
See “Business of Arizona Public Service Company - Portfolio Resources” in Item 1 for the location and a description of our principal properties.
See “Business of Arizona Public Service Company - Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ power plants.
See “Business of Arizona Public Service Company - Construction Program” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 for a discussion of APS’ construction program.
Real Estate Segment Properties
See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. Substantially all of SunCor’s debt is collateralized by interests in certain real property.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See “Business of Arizona Public Service Company - Environmental Matters” and “Water Supply” in Item 1 with regard to pending or threatened litigation and other disputes.
See Note 3 with respect to retail rate proceedings before the ACC.
See Note 11 with regard to a lawsuit against APS and the other Navajo Generating Station participants and for information relating to the FERC proceedings on California energy market issues.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Not applicable.
SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF PINNACLE WEST
Pinnacle West’s executive officers are as follows:
The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and their principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of Phelps Dodge Corporation.
Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective September 2003. Prior to that time, he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000 - February 2001) and Executive Vice President, Commercial Operations of APS (September 1996 - October 1998). Mr. Davis was also President of APS (October 1998 - December 2006) and is Chief Executive Officer of APS (since October 2002). Mr. Davis has announced that he will retire effective March 1, 2008. He is also a director of APS.
Mr. Brandt was elected Executive Vice President of Pinnacle West in September 2003. Prior to that time, he was Senior Vice President of Pinnacle West (December 2002 - September 2003). He was also elected Chief Financial Officer of Pinnacle West in December 2002. Mr. Brandt was also elected President of APS in December 2006. Prior to that time, he was Executive Vice President of APS (September 2003 - December 2006) and Senior Vice President of APS (January 2003 - September 2003). He was also elected Chief Financial Officer of APS in January of 2003. Effective March 1, 2008, Mr. Brandt will serve as President and Chief Operating Officer of Pinnacle West, and President and Chief Executive Officer of APS.
Mr. Bennett was elected to his present position effective November 2007. Prior to that time, he was Vice President, Customer Service of APS (May 1991 - November 2007).
Mr. Denman was elected to his present position effective November 2007. Prior to that time, he was Vice President, Fossil Generation of APS (April 1997 - November 2007).
Mr. Edington was elected to his present position effective November 2007. Prior to that time, he was Senior Vice President and Chief Nuclear Officer of APS (January 2007 - November 2007). He was previously with Entergy Corporation, serving as Site Vice President and Chief Nuclear Officer of Cooper Generating Station (2003 - January 2007) and Vice President of Operator Training, Indian Point Energy Center (2001 - 2003).
Mr. Flores was elected to his present position in September 2003. Prior to that time, he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 - September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 - July 1999). Mr. Flores has announced that he will retire effective March 31, 2008.
Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was Vice President and Controller of Pinnacle West (August 1999 - October 2002), Controller of Pinnacle West (July 1999 - August 1999) and Controller of APS (July 1997 - July 1999).
Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was Treasurer of Pinnacle West (August 1999 - February 2004) and Manager, Treasury Operations of APS (1997 - 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.
Ms. Loftin was elected to her present position effective November 2007. Prior to that time, she was Vice President, General Counsel and Secretary of Pinnacle West (October 2002 - November 2007) and Vice President and General Counsel (July 1999 - October 2002). She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
Mr. Robinson was elected to his present position effective November 2007. Prior to that time, he was Vice President, Planning of APS (September 2003 - November 2007), Vice President, Finance and Planning of APS (October 2002 - September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 - October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).
Ms. Sundberg was elected Vice President, Human Resources of APS effective November 2007. Prior to that time, she was with American Express Company, serving as Vice President, Employee Relations, Safety, Compliance & Embrace (January 2007 - November 2007), Vice President, HR Relationship Leader, Global Corporate Travel Division (August 2003 - January 2007) and Vice President, Global Culture Initiative (January 2003 - August 2003).
Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 - September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 - October 2002).
PART II
ITEM 5.
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 21, 2008, Pinnacle West’s common stock was held of record by approximately 30,177 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE STOCK SYMBOL: PNW
APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’ common stock.
The chart below sets forth the dividends paid on APS’ common stock for each of the four quarters for 2007 and 2006.
Common Stock Dividends
(Dollars in Thousands)
The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2007, 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 2007.
(1)
Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION
SELECTED CONSOLIDATED FINANCIAL DATA
SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 of this report.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is above the national average and remains an important driver of our revenues and earnings.
Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
SunCor, our real estate development subsidiary, has been an important source of earnings in recent years, although SunCor’s earnings in 2007 and expected earnings in 2008 reflect a slowdown in the western United States real estate markets. See discussion below in “Pinnacle West Consolidated - Factors Affecting our Financial Outlook - Subsidiaries.” Our subsidiary, APSES, provides energy-related products and services and competitive commodity-related energy services to commercial and industrial retail customers in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.
We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.
See “Pinnacle West Consolidated - Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.
PINNACLE WEST CONSOLIDATED -
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and investment activities.
The following table summarizes income from continuing operations for the years ended December 31, 2007, 2006 and 2005 and reconciles net income in total (dollars in millions):
(a)
Includes an $84 million after-tax regulatory disallowance of plant costs in 2005 in accordance with APS’ 2003 general retail rate case settlement.
(b)
Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
(c)
Primarily relates to sales of commercial properties.
(d)
See Note 22.
PINNACLE WEST CONSOLIDATED - RESULTS OF OPERATIONS
2007 Compared with 2006
Our consolidated net income for 2007 was $307 million compared with $327 million for 2006. The current period includes income from discontinued operations of $11 million related to sales of commercial properties by SunCor and a loss from discontinued operations of $3 million related to an APSES project. The prior year includes income from discontinued operations of $10 million related to sales of commercial properties by SunCor. Income from continuing operations decreased $18 million in the year-to-year comparison and is reflected in the segments as follows:
•
Regulated Electricity Segment - Income from continuing operations increased approximately $15 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance. In addition, higher fuel and purchased power costs related to commodity price increases were substantially offset by deferral of such costs in accordance with the PSA. See Note 3 for further discussion of the regulatory disallowance and the PSA.
•
Real Estate Segment - Income from continuing operations decreased approximately $38 million primarily due to lower sales of residential property and land parcels resulting from the continued slowdown in the western United States real estate markets.
· Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $283 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:
•
a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;
•
a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;
•
a $50 million increase in retail revenues due to the effects of weather;
•
a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;
•
a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and
•
a $14 million net increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $185 million lower for the year ended December 31, 2007 compared with the prior year primarily because of:
•
a $167 million decrease in residential property sales due to the continued slowdown in western United States real estate markets; and
•
an $18 million decrease primarily due to lower sales of land parcels.
All Other Revenues
Marketing and trading revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily because of higher mark-to-market gains resulting from changes in forward prices and higher competitive retail sales volumes in California.
Other revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily as a result of increased sales by APSES of energy-related products and services.
2006 Compared with 2005
Our consolidated net income for 2006 was $327 million compared with $176 million for the comparable prior-year period. The prior year included a net loss from discontinued operations of $47 million, which was related to the sale and operations of Silverhawk, partially offset by income from sales of real estate commercial properties at SunCor. Income from continuing operations increased $94 million in the period-to-period comparison, reflecting the following changes in earnings by segment:
•
Regulated Electricity Segment - Income from continuing operations increased approximately $92 million primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; and higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax of costs in accordance with the PSA.
•
Real Estate Segment - Income from continuing operations increased approximately $15 million primarily due to increased margins on residential sales and the sale of certain joint venture assets, partially offset by higher general and administrative expenses. Income from discontinued operations decreased $7 million due to lower commercial property sales.
•
Other - Income from continuing operations decreased approximately $13 million primarily due to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California.
Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the prior year are contained in the following table (dollars in millions):
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $398 million higher for 2006 compared with the prior-year period primarily as a result of:
•
a $265 million increase in revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense;
•
a $124 million increase in retail revenues related to customer growth, excluding weather effects;
•
a $3 million increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $62 million higher for 2006 compared with the prior-year period primarily as a result of:
•
a $55 million increase in residential sales due to higher prices and volumes; and
•
a $7 million increase in commercial real estate sales.
Other Revenues
Other revenues were $25 million lower for 2006 compared with the prior-year period primarily as a result of decreased sales-related products and services by APSES.
Marketing and trading revenues were $21 million lower for 2006 compared with the prior-year period primarily as a result of:
•
a $20 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;
•
a $12 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with APS’ 2003 general retail rate case settlement;
•
a $23 million increase from higher prices on competitive retail sales in California; and
•
a $12 million decrease due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES - Pinnacle West Consolidated
Operating Cash Flows
Net cash provided by operating activities was $658 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $264 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Net cash provided by operating activities was $394 million for 2006, compared with $730 million for 2005, a decrease in net cash flow of $336 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Investing Cash Flows
Net cash used for investing activities was $873 million for 2007, compared with $569 million for 2006, a decrease in net cash flow of $304 million.
This cash flow decrease was primarily due to:
•
An increase in cash used for capital expenditures and capitalized interest of $183 million (see table and discussion below).
The cash flow decreases were partially offset by:
•
A decrease of $65 million in cash invested in securities at APS;
•
An increase of $19 million cash provided by sale of real estate investments; and
•
A net increase of $3 million due to miscellaneous factors.
Net cash used for investing activities was $569 million for 2006, compared with $585 million for 2005, an increase in net cash flow of $16 million.
This cash flow increase was primarily due to:
•
Less cash used for capital expenditures (including the 2005 acquisition of the Sundance Plant) and capitalized interest of approximately $72 million (see table and discussion below).
The cash flow increases were partially offset by:
•
A decrease of $43 million in cash provided by sale of real estate investments; and
•
A net decrease of $7 million due to miscellaneous factors.
Financing Cash Flows
Net cash provided by financing activities was $185 million for 2007, compared with $108 million for 2006, an increase in net cash flow of $77 million.
This cash flow increase was primarily due to a net increase of $295 million in short-term borrowings to fund day-to-day operations and liquidity needs.
The cash flow increases were partially offset by:
•
A decrease of $161 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes; and
•
A net decrease of $57 million due to miscellaneous factors.
Net cash provided by financing activities was $108 million for 2006, compared with net cash used for financing activities in 2005 of $155 million, an increase in net cash flow of $263 million.
This cash flow increase was primarily due to:
•
An increase of $429 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes;
•
A net increase of $56 million in short-term borrowings to fund day-to-day operations and liquidity needs; and
•
A net increase of $37 million due to miscellaneous factors.
The cash flow increases were partially offset by:
Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for 2005, 2006 and 2007 and estimated capital expenditures for the next three years:
CAPITAL EXPENDITURES
(dollars in millions)
(a)
Includes $185 million in 2005 for the acquisition of the Sundance Plant.
(b)
Primarily information systems and facilities projects.
(c)
Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, these amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). Major transmission projects are driven by regional customer growth.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Installation of new steam generators in Palo Verde Unit 3 was completed in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share), which completed the steam generator replacement program for all three units. Environmental expenditures are estimated at approximately $70 million to $120 million per year for 2008, 2009 and 2010. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require additional environmental expenditures. (See “Business of Arizona Public Service Company - Environmental Matters - Regional Haze Rules” in Item 1.) Generation also includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008, 2009 and 2010.
Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
On January 23, 2008, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 3, 2008, to shareholders of record on February 1, 2008.
Our primary sources of cash are dividends from APS, external debt and equity financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2005 through 2007, total dividends from APS were $510 million and total distributions from SunCor were $70 million. For 2007, cash contributions from APS were $170 million and distributions from SunCor were $10 million. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2007, APS’ common equity ratio, as defined, was approximately 54%.
At December 31, 2007, Pinnacle West’s outstanding long-term debt, including current maturities, was $175 million. Pinnacle West has a $300 million revolving credit facility that terminates in December 2010. This line of credit is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit. At December 31, 2007, Pinnacle West had no borrowings outstanding under its revolving line of credit. At December 31, 2007, we had $115 million of commercial paper outstanding.
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We contributed approximately $52 million in 2007. The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
Significant Financing Activities - 2007. On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
Significant Financing Activities -2006. In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).
On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations, equity infusions from Pinnacle West and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West. As noted above, in May 2007, Pinnacle West infused approximately $40 million of equity into APS.
APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion at December 31, 2007. APS has two committed lines of credit totaling $900 million that are available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. At December 31, 2007, APS had borrowings of $218 million under its revolving line of credit. The amount drawn was used for general corporate purposes.
Significant Financing Activities -2007. Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
Significant Financing Activities -2006. On August 3, 2006, APS issued $400 million of debt as follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036. A portion of the proceeds was used to pay at maturity approximately $84 million of APS’
6.75% Senior Notes due November 15, 2006. The remainder was used to fund its construction program and other general corporate purposes.
On September 28, 2006, APS put in place the $500 million revolving credit facility that terminates in September 2011. APS may increase the amount of the facility up to a maximum facility of $600 million upon the satisfaction of certain conditions. APS will use the facility for general corporate purposes. The facility can also be used for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.
Other Financing Matters - See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
See “Cash Flow Hedges” in Note 18 for information related to decreased collateral provided to us by counterparties and the change in our margin account.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during 2007 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.
SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60 million, of which $48 million was outstanding at December 31, 2007. The loan matures on April 19, 2009, and may be extended one year if certain conditions are met.
On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.
SunCor’s total outstanding debt was approximately $246 million as of December 31, 2007, including $94 million of debt classified as current maturities of long-term debt under revolving lines of credit totaling $170 million. SunCor’s long-term debt, including current maturities, was $238 million and total short-term debt was $8 million at December 31, 2007. See Note 6.
El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
APSES expects minimal capital expenditures over the next three years.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financial agreements contain a pricing grid in which the interest costs we pay are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
See Note 6 for further discussions.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 25, 2008 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and access to capital. It may also require additional collateral related to certain derivative instruments, natural gas transportation, fuel supply, and other energy-related contracts.
(a)
Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
Guarantees and Letters of Credit
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2007 (dollars in millions):
(a)
The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2007 (see Note 6).
(b)
The short-term debt is primarily related to APS bank borrowings under its revolving line of credit and commercial paper at Pinnacle West (see Note 5).
(c)
Our purchased power and fuel commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).
(d)
These contractual obligations include commitments for capital expenditures and other obligations.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and power costs and the amount of such costs currently included in base rates. We had $625 million, including $111 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2007.
Also included in the balance of regulatory assets at December 31, 2007 is a regulatory asset of $338 million in accordance with SFAS No. 158 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.
In addition, we had $643 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2007, which primarily are related to removal costs. 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, 2007 reported pension liability on the Consolidated Balance Sheets and our 2007 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, 2007 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2007 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)
This assumes a 1% change in the initial and ultimate health care cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we
use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)).
The fair value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. See “Market Risks - Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.
OTHER ACCOUNTING MATTERS
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This new guidance is effective for us on January 1, 2008, with early application permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
PINNACLE WEST CONSOLIDATED - FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2005 through 2007, retail electric revenues comprised approximately 84% of
our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including demand and prices. Competitive retail sales of energy and energy-related products and services are made by APSES in certain western states that have opened to competition.
Rate Proceedings Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed above under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
Fuel and Purchased Power Costs Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “PSA Modifications” and “2006 Deferrals” in Note 3 for information regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
Customer and Sales Growth The customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory was 3.3% during 2007. Customer growth averaged 4.0% a year for the three years 2005 through 2007; and we currently expect customer growth to decline, averaging about 1% to 2% per year for 2008 through 2010 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2005 through 2007, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 4.8%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 3.8% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 1% to 2% on average per year, during 2008 through 2010, excluding the effects of weather variations. We currently expect our retail sales growth in 2008 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases (see Note 3).
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 responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.
Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
Wholesale Market Our marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits. See “Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ recent filing with the FERC requesting an increase in transmission rates.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.
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” above for information regarding planned additions to our facilities.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.3% of the assessed value for 2007, 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we improve our existing facilities. See “Capital Expenditures” above for information regarding planned additions to our facilities.
Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.
Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.
Subsidiaries SunCor’s net income was $24 million in 2007, $61 million in 2006 and $56 million in 2005. See Note 17 for further discussion. We currently expect SunCor’s net income in 2008 to be approximately $20 million. This estimate reflects continuation of the slowdown in the western United States real estate markets.
The historical results of APSES, Pinnacle West Marketing & Trading and El Dorado are not indicative of future performance.
General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 12). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following tables show the net pretax changes in mark-to-market of our derivative positions in 2007 and 2006 (dollars in millions):
(a)
The decreases in mark-to-market recorded in OCI are due primarily to decreases in forward natural gas prices.
The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” 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 and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2007 and 2006 (dollars in millions).
(a)
These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY - RESULTS OF OPERATIONS
Regulatory Matters
See “Pinnacle West Consolidated - Results of Operations - Regulatory Matters” above for information about the ACC’s order in APS’ general retail rate case and the PSA.
2007 Compared with 2006
Our net income for 2007 was $284 million compared with $270 million for 2006. APS’ net income increased approximately $14 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; higher interest expense due to higher debt balances and higher rates; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance (see Note 3). In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See Note 3 for further discussion.
Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):
Electric operating revenues were $278 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:
•
a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;
•
a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and
•
a $9 million net increase due to miscellaneous factors.
2006 Compared with 2005
APS’ net income for 2006 was $270 million compared with $170 million for the comparable prior year. The $100 million increase was primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; higher marketing and trading gross margin primarily due to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates; and higher interest expense. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax costs in accordance with the PSA.
Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the year ended December 31, 2005 are contained in the following table (dollars in millions):
Electric operating revenues were $388 million higher for 2006 compared with the prior year primarily as a result of:
•
a $265 million increase in revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense;
•
a $124 million increase in retail revenues related to customer growth, excluding weather effects; and
•
a $1 million decrease due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES - ARIZONA PUBLIC SERVICE COMPANY
Operating Cash Flows
Net cash provided by operating activities was $766 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $372 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Net cash provided by operating activities was $394 million for 2006, compared with $722 million for 2005, a decrease in net cash flow of $328 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Investing Cash Flows
Net cash used for investing activities was $881 million for 2007, compared with $714 million for 2006, a decrease in net cash flow of $167 million.
This cash flow decrease was primarily due to:
•
An increase of $239 million in cash used for capital expenditures and allowance for borrowed funds used during construction (see table and discussion above).
The cash flow decrease was partially offset by:
•
A decrease of $65 million in cash invested in securities; and
•
A net increase of $7 million due to miscellaneous factors.
Net cash used for investing activities was $714 million for 2006, compared with $645 million for 2005, a decrease in net cash flow of $69 million.
This cash flow decrease was primarily due to:
•
A net decrease of $1 million due to miscellaneous factors.
The cash flow decreases were partially offset by:
•
Less cash used for capital expenditures (including, in 2005, the acquisition of the PWEC Dedicated Assets and the Sundance Plant) and allowance for borrowed funds used during construction of $646 million (see table and discussion above).
Financing Cash Flows
Net cash provided by financing activities was $86 million for 2007, compared with $352 million for 2006, a decrease in net cash flow of $266 million.
The cash flow decrease was primarily due to:
•
A decrease of $311 million in net new long-term debt (issuances net of redemptions and refinancing) to fund APS’ construction program and for general corporate purposes; and
•
A decrease of $173 million due to decreased equity infusions from Pinnacle West.
The cash flow decreases were partially offset by:
•
A net increase of $218 million in short-term borrowings to fund day-to-day operations and liquidity needs.
Net cash provided by financing activities was $352 million for 2006, compared with net cash used for financing activities in 2005 of $76 million, an increase in net cash flow of $428 million.
This cash flow increase was primarily due to:
•
An increase of $466 million in net new long-term debt issuances net of redemptions and refinancings in order to fund our construction program and for other general corporate purposes.
This cash flow increase was partially offset by:
•
A decrease of $37 million due to decreased equity infusions from Pinnacle West; and
•
A net decrease of $1 million due to miscellaneous factors.
Liquidity
For additional discussion see “Liquidity and Capital Resources - Pinnacle West Consolidated.”
Contractual Obligations
The following table summarizes contractual requirements for APS as of December 31, 2007 (dollars in millions):
(a)
The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2007 (see Note 6).
(b)
APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 11).
(c)
These contractual obligations include commitments for capital expenditures and other obligations.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See “Pinnacle West Consolidated - Factors Affecting Our Financial Outlook” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s consolidated financial statements.
February 27, 2008
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, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded
as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the consolidated statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’s Accounting for Defined Benefit Pension and Other Postretirement Plans” effective December 31, 2006.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 27, 2008
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading, and Pinnacle West Energy (dissolved as of August 31, 2006). Significant intercompany accounts and transactions between the consolidated companies have been eliminated.
APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and competitive commodity energy to commercial and industrial retail customers in competitive markets in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006.
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
exception for contracts that meet the normal purchases and sales criteria specified in the standard. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.
We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.
For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
See Note 2 for information about a new accounting standard on fair value measurements.
See Note 18 for additional information about our derivative and energy trading accounting policies.
Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters.
The detail of regulatory assets is as follows (dollars in millions):
(a)
Subject to a carrying charge.
(b)
See “Reacquired Debt Costs” below.
(c)
There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.
The detail of regulatory liabilities is as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a)
In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)
Subject to a carrying charge.
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
•
material and labor;
•
contractor costs;
•
capitalized leases;
•
construction overhead costs (where applicable); and
•
capitalized interest or an allowance for funds used during construction.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the costs calculated in accordance with SFAS No. 143.
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, 2007 were as follows:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years 2005 through 2007, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.11% for 2007, 3.14 % for 2006 and 3.0% for 2005. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.
Investments
El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” See Note 12 for more information on these investments.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.8% for 2007, 6.8% for 2006 and 5.7% for 2005. Capitalized interest ceases when construction is complete.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
AFUDC was calculated by using a composite rate of 8.2% for 2007, 8.0% for 2006 and 7.7% for 2005. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Electric Revenues
We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We
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exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April 2005, in accordance with a 2005 ACC order, we also exclude city franchise fees from both electric revenues and operating expenses.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.
All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis.
Real Estate Revenues
SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 - Discontinued Operations.
Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Homes under construction classified as “real estate investments” on the Consolidated Balance Sheets are transferred to “home inventory” upon completion of construction with the expectation that they will be sold in a timely manner. In previous years, “home inventory” was classified as “other current assets” on the Consolidated Balance Sheets. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In addition, see Note 22 - Discontinued Operations.
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Cash and Cash Equivalents
We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.
Investments in auction rate securities have interest rates that are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investment in debt securities on our Consolidated Balance Sheets.
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the most probable resolution of all known and measurable tax exposures. See Note 4.
Reacquired Debt Costs
APS defers gains and losses incurred upon early retirement of debt. These costs are amortized equally on a monthly basis over the remaining life of the original debt consistent with its ratemaking treatment.
Stock-based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries. Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both
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SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements. See Note 16.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $37 million in 2007, $39 million in 2006 and $33 million in 2005. Estimated amortization expense on existing intangible assets over the next five years is $29 million in 2008, $20 million in 2009, $19 million in 2010, $12 million in 2011 and $10 million in 2012. At December 31, 2007, the weighted average remaining amortization period for intangible assets was 5 years.
2. New Accounting Standards
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This new guidance is effective for us on January 1, 2008, with early application permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
3. Regulatory Matters
Retail Rate Order
Retail Rate Increase On June 28, 2007, the ACC issued an order (the “Retail Rate Order”) in a general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315
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million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC disallowed approximately $14 million of 2005 Deferrals because it found the Palo Verde outage costs giving rise to those amounts resulted from APS’ imprudence.
PSA Modifications The Retail Rate Order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the Retail Rate Order, 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 (currently $0.0325 per kWh);
•
under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;
•
an adjustment is made annually each February 1st and goes into effect automatically unless suspended by the ACC;
•
the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•
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) an “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;
•
amounts to be recovered or refunded through the sum of the PSA components discussed in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh change in the PSA rate in any PSA Year; and
•
the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was scheduled to expire on January 31, 2008, will remain in effect as long as necessary after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-2007 implementation of the new Base Fuel Rate.
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PSA Balance
The following table shows the changes in the deferred fuel and purchased power regulatory asset for the years ended December 31, 2007 and 2006 (dollars in millions):
The PSA rate for the PSA Year beginning February 1, 2008 was set at the maximum $0.004 per kWh. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included in the Historical Component of the PSA rate for the PSA Year beginning February 1, 2009.
2006 Deferrals
In May 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. APS recorded approximately $79 million of 2006 Deferrals, virtually all of which were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concluded that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs, which have been fully recovered, were prudently incurred.
Line Extension Schedule
The Retail Rate Order required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. These changes would permit APS to collect, on a current basis, costs related to line extensions.
On October 24, 2007, APS filed a proposed amendment to its line extension schedule, including a proposal to treat line extension payments received as non-refundable other electric revenues. APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The ACC Staff issued a recommended order that was consistent with APS’ proposed line extension amendments in all significant respects except for the authorized accounting treatment. The ACC staff proposed that payments received for new or upgraded service be treated as contributions in aid of construction (“CIAC”), rather than as non-refundable other electric revenues as APS requested. CIAC treatment would result in a positive cash flow that will partially offset capital expenditures, but without any revenue impact. On February 13, 2008, the ACC voted to approve the ACC staff recommended order, with minor modifications.
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Rate Requests for Transmission and Ancillary Services
On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would have resulted in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).
On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, which are underway. The proposed rates become effective March 1, 2008, subject to refund based upon the ultimate outcome of proceedings at the FERC on this matter.
On December 31, 2007, APS filed with the ACC an application to increase annual pretax retail revenues by approximately $30 million, effective March 1, 2008, to cover the Retail Transmission Charges authorized by the FERC. This retail rate increase implements an ACC-approved mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February 13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC proceedings on this matter.
Other
On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. As part of this order, APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005.
Federal
FERC Order
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The
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FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.
On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007. This compliance filing was conditionally accepted by FERC in an order issued January 17, 2008, requiring an additional compliance filing by the Pinnacle West Companies by February 19, 2008.
Based upon an analysis of this matter and preliminary calculations of the refund obligations, at this time neither Pinnacle West nor APS believes that this proceeding will have a material adverse effect on its financial position, results of operations or cash flows.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment, which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
We adopted FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the
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guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $5 million of tax positions that, if recognized, would decrease our effective tax rate.
We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $57 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, 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.
As of December 31, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.
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):
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The components of the net deferred income tax liability were as follows (dollars in thousands):
5. Lines of Credit and Short-Term Borrowings
Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2007 and December 31, 2006, which was available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current line terminates in December 2010. Pinnacle West had no outstanding borrowings under the lines of credit at December 31, 2007 and December 31, 2006. Pinnacle West had approximately $5 million of letters of credit issued under the line at December 31, 2007 and approximately $4 million of letters of credit issued under the line at December 31, 2006. The commitment fees were 0.15% in 2007 and 2006. Pinnacle West had commercial paper borrowings of $115 million outstanding at December 31, 2007 and $28 million outstanding at December 31, 2006. The weighted average interest rates were 5.73% at December 31, 2007 and 5.625% at December 31, 2006. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.
APS had two committed lines of credit with various banks totaling $900 million at December 2007 and 2006, all of which were available either to support the issuance of up to $250 million in
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commercial paper or to be used for bank borrowings, including the issuance of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. APS may increase the $500 million line to $600 million if certain conditions are met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2007 and December 31, 2006. APS had bank borrowings outstanding of $218 million under the $500 million line of credit at December 31, 2007 and no borrowings outstanding at December 31, 2006. The weighted average interest rate was 5.361% at December 31, 2007. APS had approximately $4 million of letters of credit issued under the $400 million line at December 31, 2007 and 2006.
Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
SunCor had two revolving lines of credit totaling $170 million at December 31, 2007, and December 31, 2006 maturing in October 2008 and December 2008. The commitment fees were 0.125% in 2007 and 2006 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2007 and 2006. SunCor had $94 million outstanding at December 31, 2007 and $118 million outstanding at December 31, 2006. The weighted-average interest rate was 7.27% at December 31, 2007 and 7.09% at December 31, 2006. Interest was based on LIBOR plus 2.0% for 2007 and 2006. The balance is included in current maturities of long-term debt on the Consolidated Balance Sheets at December 31, 2007 and 2006. SunCor had other short-term loans in the amount of $8 million at December 31, 2007 and $8 million at December 31, 2006. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2007 and 2006.
6. Long-Term Debt
Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2007 and 2006 (dollars in thousands):
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Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financing agreements contain a pricing grid in which interest costs we pay are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4
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billion, and total capitalization was approximately $6.2 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.
SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of December 31, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $217 million.
As a result of the restrictions in the preceding two paragraphs, as of December 31, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December 31, 2007, our consolidated net assets were approximately $3.5 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2007, 2006 and 2005 is as follows (dollars in thousands):
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(a)
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.
(b)
Represents shares of common stock withheld from certain stock awards for tax purposes.
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.
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For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. The fair market value of investments in our retirement and postretirement plans is determined using actively-quoted prices when available. When actively-quoted prices are not available, we use prices provided by external sources, models or other valuation methods. 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 the application of these methods.
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans are attributable to APS and therefore are recoverable in rates. Accordingly these changes are recorded as a regulatory asset.
The following table provides details of the plans’ benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2007 and 2006 (dollars in thousands):
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The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2007 and 2006 (dollars in thousands):
The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2007 and 2006 (dollars in thousands):
The following table shows the details related to accumulated other comprehensive loss before income taxes as of December 31, 2007 and 2006 (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2008 (dollars in thousands):
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2008, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Assets
Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset allocation at December 31, 2007 and 2006 is as follows:
The Board of Directors has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.
The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the other postretirement benefit plans. The investment policy for other postretirement benefit plans’ assets is similar to that of the pension plan assets described above.
Contributions
The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
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(a)
The expected future other benefit payments take into account the Medicare Part D subsidy.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2007, costs related to APS’ employees represented 97% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. At December 31, 2007, approximately 15% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $7 million for 2007, $6 million for 2006 and $6 million for 2005. APS recorded expenses for this plan of approximately $6 million in 2007, $6 million in 2006 and $6 million in 2005.
9. Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases and to purchase the property for fair market value at the end of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.
In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $73 million in 2007, $72 million in 2006 and $71 million in 2005. APS’ lease expense was $66 million in 2007, $64 million in 2006 and $58 million in 2005.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2008 to 2015.
Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2007 (dollars in thousands):
(a)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(b)
Weighted average of interests.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.
APS currently estimates it will incur $147 million (in 2007 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2007, APS had a regulatory liability of $11 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an 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 $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fuel and Purchased Power Commitments
Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2008 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $418 million in 2008; $358 million in 2009; $293 million in 2010; $218 million in 2011; $216 million in 2012; and $1.6 billion thereafter. APS estimates the contract requirements to be approximately $375 million in 2008; $358 million in 2009; $293 million in 2010; $212 million in 2011; $210 million in 2012; and $1.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
Of the various fuel and purchased power contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.
The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):
(a)
Total take-or-pay commitments are approximately $884 million. The total net present value of these commitments is approximately $588 million.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2007 and $75 million at December 31, 2006 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.
California Energy Market Issues and Refunds in the Pacific Northwest
FERC
In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
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the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Several parties sought rehearing of this decision at the Ninth Circuit. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at the FERC will have no material adverse impact on our financial position, results of operations or cash flows.
On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC, and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. The Ninth Circuit issued the mandate for this proceeding on December 4, 2007. The outcome of the further proceedings cannot be predicted at this time.
On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed on December 17, 2007. Although the FERC ruling in this matter is being appealed and the FERC has not yet calculated the specific refund amounts at issue, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.
On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot currently predict the outcome of this matter.
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 jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.
Salt River Project
Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.
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. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.
Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.
Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The generation sites are strategically located to serve APS Native Load customers. Management expects to continuously use the sites and, thus, cannot estimate a potential closure date. The asset retirement obligations associated with our non-regulated assets are immaterial.
The following schedule shows the change in our asset retirement obligations for 2007 and 2006 (dollars in millions):
In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of gains on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2007 and December 31, 2006 (dollars in millions):
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):
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2007 is as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Selected Quarterly Financial Data (Unaudited)
Consolidated quarterly financial information for 2007 and 2006 is as follows (dollars in thousands, except per share amounts):
Earnings per share:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. Fair Value of Financial Instruments
We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2007 and 2006 due to their short maturities.
We hold short-term investments in fixed income securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2007 and 2006 due to the short-term reset of interest rates.
APS also holds investments in fixed income and domestic equity securities for purposes other than trading in its nuclear decommissioning trust. The December 31, 2007 and 2006 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
On December 31, 2007, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations was $3.29 billion, with an estimated fair value of $3.20 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations was $3.23 billion on December 31, 2006, with an estimated fair value of $3.19 billion. On December 31, 2007, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was $2.87 billion, with an estimated fair value of $2.79 billion. The carrying value of APS’ long-term debt excluding capital lease obligations was $2.87 billion on December 31, 2006, with an estimated fair value of $2.84 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
15. Earnings Per Share
The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2007, 2006 and 2005:
Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 579,000 shares in 2007, 593,000 shares in 2006 and 106,000 shares in 2005. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,834,871 shares in 2007, 100,010,108 shares in 2006 and 96,589,949 shares in 2005.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options to purchase 114,213 shares of common stock were outstanding at December 31, 2007 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 437,401 at December 31, 2006 and 495,367 at December 31, 2005.
16. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries.
The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, performance cash awards, dividend equivalents and stock to eligible individuals. We have reserved 8 million shares of common stock for issuance under the 2007 plan plus additional shares that become available for issuance under prior stock plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable under any award granted under a Prior Plan will be added to the number of shares of stock available for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery of such shares to the participant. In addition, any shares of stock that have been issued in connection with any award granted under a Prior Plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company. No more than 500,000 shares of stock may be granted to any one participant during a calendar year. The maximum performance-based award (other than a performance cash award) payable to any one participant during a performance period is 500,000 shares of stock or the cash equivalent. The plan also provides for the granting of new incentive and non-qualified stock options at a price per share equal to at least 100% of the fair market value of the common stock at the time of grant. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.
The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares but no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options but no new awards may be granted under the plan. Options vest by thirds over a three-year period beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also includes outstanding shares of restricted stock.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units vest over a four-year period from 2006 through 2009, unless the employee is eligible to retire, in which case the employee’s Retention Units are immediately vested and the compensation expense is immediately recognized. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash to settle the payment on the first business day of 2007 was $1.6 million.
In 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were granted to officers and key employees. Each officer and key employee had to elect to receive payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock. The fair value of the stock election is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock Units will be redeemed February 20th of calendar years 2008, 2009, 2010 and 2011. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest. Restricted Stock Units vest over a four-year period from 2007 through 2010, unless the employee is eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested (with the same redemption dates) and the compensation expense is immediately recognized; however, the Restricted Stock Units will be redeemed on the pre-established valuation dates. As the Restricted Stock Unit cash election award is accounted for as a liability award, the fair market value of the outstanding Restricted Stock Unit cash election is measured at each balance sheet date, using Pinnacle West’s closing stock price.
The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $6 million in 2007, $13 million in 2006 and $6 million in 2005. The compensation cost that Pinnacle West has capitalized was immaterial in 2007, 2006 and 2005. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $2 million in 2007, $5 million in 2006 and $2 million in 2005. APS’ share of compensation cost that has been charged against income was $6 million in 2007, $12 million in 2006 and $5 million in 2005.
The following table is a summary of option activity under our equity incentive plans as of December 31, 2007 and changes during the year:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
There were no options granted during the years 2005 through 2007. The intrinsic value of options exercised was $2 million for 2007, $5 million for 2006 and $4 million for 2005.
The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2007 and changes during the year:
As of December 31, 2007, there was $7 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 1.3 years. The total fair value of shares vested during 2007 was $6 million, $10 million for 2006 and $3 million for 2005.
The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2007, 2006 and 2005:
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(a)
Restricted stock units, performance shares, special grant and stock ownership incentive awards priced at the closing market price on the grant date.
Cash received from options exercised under our share-based payment arrangements was $8 million for 2007, $22 million for 2006 and $17 million for 2005. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1 million for 2007, $2 million for 2006 and $1 million for 2005.
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 during 2008.
17. Business Segments
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and investment activities.
Financial data for 2007, 2006 and 2005 is provided as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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(a)
All other activities relate to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
(b)
Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the other segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.
(c)
The other segment primarily relates to the sale and operations of Silverhawk. See Note 22.
18. Derivative and Energy Trading Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2007, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.
For its regulated operations, APS defers for future rate recovery 90% of gains and losses on derivatives that would otherwise be recognized in income. In the following discussion, amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.
We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
Both non-trading and trading derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.
All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
During 2008, we estimate that a net gain of $18 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).
The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2007 and 2006 (dollars in thousands):
During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps. We historically presented the buy side and the sell side of such swaps at fair value gross on our Consolidated Balance Sheets, which resulted in mark-to-market
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset or liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on results of operations, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $1 million at December 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Consolidated Balance Sheets. There was no collateral provided to us by counterparties at December 31, 2007 and $54 million was provided at December 31, 2006, and is included in other current liabilities on the Consolidated Balance Sheets.
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities 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 net income 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, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Derivative Accounting” for a discussion of our credit valuation adjustment policy.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2007, 2006 and 2005 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a)
Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.
(b)
As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
20. Variable-Interest Entities
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $38 million at December 31, 2007 and $39 million at December 31, 2006.
21. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2007 are as follows (dollars in millions):
At December 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $83 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at December 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2008. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
22. Discontinued Operations
SunCor (real estate segment) - In 2007, 2006 and 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
from discontinued operations of approximately $10 million ($17 million pretax) in 2007; $9 million ($15 million pretax) in 2006; and $15 million ($25 million pretax) in 2005.
Silverhawk (other) - In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The chart below includes the revenues and expenses related to the operations of Silverhawk.
Other - Includes activities related to APSES in 2007 and to El Dorado in 2006 and 2005.
The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005 (dollars in millions):
(a)
Income before income taxes includes an interest expense allocation, net of capitalized amounts, of $13 million in 2005. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s financial statements.
February 27, 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, 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, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” effective December 31, 2006.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 27, 2008
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-1. Income Taxes
APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgement which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
We adopted FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Balance Sheets (dollars in thousands):
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $4 million of tax positions that, if recognized, would decrease our effective tax rate.
We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $56 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, 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 APS’ income tax expense are as follows (dollars in thousands):
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
The components of the net deferred income tax liability were as follows (dollars in thousands):
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2007 and 2006 is as follows (dollars in thousands):
S-3. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2007, APS hedged certain exposures to these risks for a maximum of 39 months.
Cash Flow Hedges
The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
During 2008, APS estimates that a net gain of $1 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
The following table summarizes APS’ assets and liabilities from risk management and trading activities at December 31, 2007 and 2006 (dollars in thousands):
During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps. We historically presented the buy side and the sell side of such swaps at fair value gross on our Balance Sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset or liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. Collateral provided to counterparties was $1 million at December 31, 2007 and was $2 million at December 31, 2006 and is included in other current assets on the balance sheet. There was no cash collateral provided to us by counterparties at December 31, 2007 and $1 million was provided at December 31, 2006, and is included in other current liabilities on the Balance Sheets.
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-4. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for 2007, 2006 and 2005 (dollars in thousands):
(a)
As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
S-5. Related Party Transactions
From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):
NOTES TO ARIZONA PUBLIC SERVICE COMPANY
Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. However, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”
On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
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, 2007. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) Management’s Annual Reports on Internal Control Over Financial Reporting
Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 74 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 129 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 75 of this report and “Report of Independent Registered Public Accounting Firm” on page 130 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.
(d) Changes In Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2007 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE OF PINNACLE WEST
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance,” “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, 2008 (the “2008 Proxy Statement”) and to the Supplemental Item - “Executive Officers of Pinnacle West” in Part I of this report.
Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com. Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on Pinnacle West’s website.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance - How are directors compensated?” and “Executive Compensation” in the 2008 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” in the 2008 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2007 with respect to our compensation plans and individual compensation arrangements under which our equity securities are authorized for issuance.
EQUITY COMPENSATION PLAN INFORMATION
This amount includes shares subject to outstanding options as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.
The weighted average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.
Awards can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, dividend equivalents, and restricted stock units..
Equity Compensation Plans Approved By Security Holders
Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were approved by our shareholders: (a) the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no new stock awards may be granted; (b) the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the “2002 Plan”), under which no new stock awards may be granted; and (c) the Pinnacle West Capital
Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), which was approved by our shareholders at our 2007 annual meeting of shareholders. Although we cannot issue additional awards under the 2002 Plan, shares subject to outstanding awards under the 2002 Plan that expire or are cancelled or terminated will be available for issuance under the 2007 Plan. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
The Company does not have any equity compensation plans under which shares can still be issued that have not been approved by shareholders.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance” and to “Related Party Transactions” in the 2008 Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
Reference is hereby made to “Audit Matters - What fees were paid to our independent registered public accountants in 2006 and 2007?” and “What are the Audit Committee’s pre-approval policies?” in the 2008 Proxy Statement.
APS
The following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:
(1)
The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.
(2)
The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits.
(3)
The aggregate fees billed primarily for tax compliance and tax planning.
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be
performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
a
Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b
Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.
c
An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d
Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
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.
Date: February 27, 2008
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
/s/ William J. Post
(William J. Post, Chairman of the
Board of Directors and Chief Executive Officer)
Power of Attorney
We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, 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/ William J. Post
(William J. Post, Chairman
Principal Executive Officer and Director
February 27, 2008
of the Board of Directors and
Chief Executive Officer)
/s/ Jack E. Davis
(Jack E. Davis, President
Director
February 27, 2008
and Chief Operating Officer)
/s/ Donald E. Brandt
(Donald E. Brandt,
Principal Accounting Officer and Principal Financial Officer
February 27, 2008
Executive Vice President and
Chief Financial Officer)
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.
Power of Attorney
We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, 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.