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Pinnacle West Capital 10-K 2009 Documents found in this filing:Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
For the fiscal year ended December 31, 2008
OR
For the transition period from to
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
PINNACLE WEST CAPITAL CORPORATION Yes þ No o
ARIZONA PUBLIC SERVICE COMPANY Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.
PINNACLE WEST CAPITAL CORPORATION Yes o No þ
ARIZONA PUBLIC SERVICE COMPANY Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
PINNACLE WEST CAPITAL CORPORATION Yes þ No o
ARIZONA PUBLIC SERVICE COMPANY Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or in any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes o No þ
State the aggregate market value of the voting and non-voting common equity held by
non-affiliates, computed by reference to the price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of the last business day of each registrant’s
most recently completed second fiscal quarter:
The number of shares outstanding of each registrant’s common stock as of February 16, 2009
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 20, 2009 are incorporated by reference into Part III
hereof.
Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a)
and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed
under that General Instruction.
This combined Form 10-K is separately filed by Pinnacle West Capital Corporation and Arizona
Public Service Company. Each registrant is filing on its own behalf all of the information
contained in this Form 10-K that relates to such registrant and, where required, its subsidiaries.
Except as stated in the preceding sentence, neither registrant is filing any information that does
not relate to such registrant, and therefore makes no representation as to any such information.
TABLE OF CONTENTS
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GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – Allowance for Funds Used During Construction
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APSES – APS Energy Services Company, Inc., a subsidiary of the Company
Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs
Cholla – Cholla Power Plant
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
DOE – United States Department of Energy
EITF – FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
FIN – FASB Interpretation Number
FIP – Federal Implementation Plan
Fitch – Fitch, Inc.
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hour, one million watts per hour
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
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Note – a Note to Pinnacle West’s Consolidated Financial Statements in Item 8 of this report
(references to the Supplemental Notes to APS’ Financial Statements are preceded by an “S,” e.g.,
Note S-1)
NPC – Nevada Power Company
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned or contracted by the Company that is
over and above the amount required to serve APS’ retail customers and traditional wholesale
contracts
Palo Verde – Palo Verde Nuclear Generating Station
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy (PWEC) – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006
Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PSA – power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West
Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
Secured Revolver – SunCor’s
principal loan facility, which is secured primarily by an interest in land,
commercial properties, land contracts and homes under construction
SFAS – Statement of Financial Accounting Standards
Silverhawk – Silverhawk Power Station
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
TCA – transmission cost adjustor
TEP – Tucson Electric Power Company
VIE – variable-interest entity
West Phoenix – West Phoenix Power Plant
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INTRODUCTION
Filing Format
This Annual Report on Form 10-K is a combined report being filed by two separate registrants:
Pinnacle West and APS. The information required with respect to each company is set forth within
the applicable items.
The Management’s Discussion and Analysis of Financial Condition and Results of Operations
included under Item 7 of this report is divided into the following two sections:
Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and
Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial
Statements, the majority of which also relates to APS, and Supplemental Notes to APS’ Financial
Statements.
PART I
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 and El Dorado 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.
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Business Segments
Pinnacle West has two principal business segments (determined by products, services and the
regulatory environment):
Electric power demand is generally a seasonal business. In Arizona, demand for power peaks
during the hot summer months. 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. See “2008 General Rate Case” in Note 3 for a discussion of APS’
pending retail rate case before the ACC.
Employees
At December 31, 2008, Pinnacle West employed approximately 7,500 people, including the
employees of its subsidiaries. Of these employees, approximately 6,900 were employees of APS,
including employees at jointly-owned generating facilities (approximately 3,300 employees) for
which APS serves as the generating facility manager. Approximately 600 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 website, (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 (the “Exchange Act”), and its proxy statement
filed pursuant to Section 14(a) of the Exchange Act.
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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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 website. The information on Pinnacle West’s website is
not incorporated by reference into this report.
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at
the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068,
P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).
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 of this report, these factors include,
but are not limited to:
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REGULATION AND COMPETITION
Retail
The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must
also approve any transfer or encumbrance of APS’ property used to provide retail electric service
and approve or receive prior notification of certain transactions between Pinnacle West, APS and
their respective affiliates.
APS is subject to varying degrees of competition from other investor-owned utilities in
Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical
districts and similar types of governmental or non-profit organizations. In addition, some
customers, particularly industrial and large commercial customers, may own and operate generation
facilities to meet their own energy requirements.
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose
alternate energy suppliers. However, there are currently no active retail competitors offering
unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court
found that the rules were in part unconstitutional and in other respects unlawful, the latter
finding being primarily on procedural grounds, and invalidated all ACC orders authorizing
competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of
Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders
authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to
review the Court of Appeals decision.
To date, the ACC has taken no final or substantive action on either the rules or the prior
orders authorizing competitive electric service providers in response to the final Court of Appeals
decision. However, as a result of a new request for authorization to provide competitive retail
electric service by Sempra Energy Solutions, LLC, the ACC directed the ACC staff to investigate
whether such retail competition was in the public interest and what legal impediments remain to
competition in light of the Court of Appeals decision referenced above. The ACC staff’s report on
the results of its investigation is due to be filed with the ACC on December 31, 2009. At present,
only limited electric retail competition exists in Arizona and only with certain entities not
regulated by the ACC. APS cannot predict when, and the extent to which, additional competitors
will re-enter APS’ service territory.
Wholesale
General
The FERC regulates rates for wholesale power sales and transmission services. See “Formula
Transmission Tariff” in Note 3 for information regarding APS’ transmission rates. During 2008,
approximately 6.3% of APS’ electric operating revenues resulted from such sales and services. APS’
wholesale activity primarily consists of managing fuel and purchased power risks in connection with
the costs of serving retail customer energy requirements. APS also sells, in the wholesale market,
its generation output that is not needed for APS’ Native Load and, in doing so, competes with other
utilities, power marketers and independent power producers. Additionally, subject to specified
parameters, APS markets, hedges and trades in electricity and fuels.
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BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
General
APS was incorporated in 1920 under the laws of the State of Arizona and currently has
approximately 1.1 million customers. APS does not distribute any products. During 2008, no single
purchaser or user of energy accounted for more than 1.8% of electric revenues. See “Overview” and
“Regulation and Competition” above for additional background information about APS.
At December 31, 2008, APS employed approximately 6,900 people, including employees at
jointly-owned generating facilities for which APS serves as the generating facility manager. APS’
principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona
85072-3999 (telephone 602-250-1000).
Portfolio Resources
APS’ sources of energy during 2008 were: coal – 37.4%; nuclear – 24.2%; purchased power –
20.3%; and gas – 18.1%. In accordance with GAAP, a substantial portion of APS’ purchased power
expense is netted against wholesale sales on the Consolidated Statements of Income. See Note 18.
The disclosure below provides a more detailed description of each of APS’ current sources of
energy.
Generation Facilities
APS’ portfolio of owned or leased generating capacity is provided in the table below:
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Coal Fueled Generating Facilities
Four Corners – Four Corners is a coal-fired power plant located in the northwestern corner of
New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units
4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term
lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016,
with options on APS’ part to extend the contract for five to fifteen additional years. The Four
Corners plant site is leased from the Navajo Nation and is also subject to an easement from the
federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below
for additional information.
Cholla – Cholla is a coal-fired power plant located in northeastern Arizona. APS operates
the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates
that unit for PacifiCorp. Cholla’s common facilities are jointly owned by APS and PacifiCorp. APS
purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under
long-term leases of coal reserves with the Navajo Nation, the federal government and private
landholders. There are currently two coal contracts in place with two separate suppliers for
Cholla. One supplier is ramping down its supply to the plant, which will be complete in 2009, and
the other is ramping up its supply to the plant to provide Cholla’s full coal requirement by 2010.
This agreement runs through 2024. Additionally, APS may purchase a portion of Cholla’s coal
requirements on the spot market to take advantage of competitive pricing options and to supplement
coal required for increased operating capacity. APS believes that the current fuel contracts and
competitive fuel supply options ensure the continued operation of Cholla for its useful life. In
addition, APS has a long-term coal transportation contract.
Navajo Generating Station – The Navajo Generating Station is a coal-fired power plant located
in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo
Units 1, 2 and 3. The Navajo Generating Station’s coal requirements are purchased from a supplier
with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is
under contract with its coal supplier through 2011, with options to extend through 2019. The
Navajo Generating Station plant site is leased from the Navajo Nation and is also subject to an
easement from the federal government. See “Plant and Transmission Line Leases and Easements on
Indian Lands” below for additional information.
See Note 11 for information regarding APS’ coal mine reclamation obligations.
Natural Gas Fueled Generating Facilities
APS has seven natural gas power plants located throughout Arizona, consisting of Redhawk,
located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance,
located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson;
Douglas, located in the town of Douglas; and Yucca, located near Yuma. APS owns and operates each
plant with the exception of one combustion turbine unit and one steam unit at Yucca that are
operated by APS and owned by the Imperial Irrigation District.
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Nuclear Generating Facility
Palo Verde Nuclear Generating Station – Palo Verde is a nuclear power plant located about 50
miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3
and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1%
combined interest in that Unit. See “Palo Verde Leases” below for additional information regarding
the Palo Verde Unit 2 sale leaseback transactions.
Palo Verde Fuel Cycle – The fuel cycle for Palo Verde is comprised of the following stages:
The Palo Verde participants are continually identifying their future resource needs and
negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all
of Palo Verde’s requirements for uranium concentrates and conversion services through 2011. The
participants have also contracted for all of Palo Verde’s enrichment services through 2013 and all
of Palo Verde’s fuel assembly fabrication services until at least 2015.
Spent Nuclear Fuel and Waste Disposal – See “Palo Verde Nuclear Generating Station” in Note
11 for a discussion of spent nuclear fuel and waste disposal.
Palo Verde Leases – In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. APS accounts for these leases as
operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases
or to purchase the property for fair market value at the end of the lease terms. We are analyzing
this matter, and will continue to do so as we approach the end of the lease terms, to determine
which option or options to pursue. See Notes 9 and 20 for additional information regarding the
Palo Verde Unit 2 sale leaseback transactions.
Regulatory – Operation of each of the three Palo Verde units requires an operating license
from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in
April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period
of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three
Palo Verde units at full power. APS applied for renewed operating licenses for Palo Verde Unit 1,
Unit 2 and Unit 3 on December 15, 2008 for a period of 20 years beyond the expirations of the
current licenses. The NRC is currently reviewing the application.
NRC Inspection – On February 22, 2007, the NRC issued a “white” finding (low to moderate
safety significance) due to electrical output issues with the Unit 3 emergency diesel generator
that occurred in 2006. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC
“yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems,
resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column
of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime.
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Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need
for improvements, APS’ management conducted site-wide assessments of equipment and operations.
On June 21, 2007, the NRC issued an initial confirmatory action letter confirming APS’
commitments regarding specific actions APS will take to improve Palo Verde’s performance. From
October 1, 2007 through November 2, 2007, a team of NRC inspectors performed on-site in-depth
inspections of Palo Verde’s equipment and operations. The NRC’s inspection results were documented
in an NRC letter to APS dated February 1, 2008 (the “Inspection Report”). The Inspection Report
indicated that the facility is being operated safely, but also identified certain performance
deficiencies. Based on its review of the APS Palo Verde improvement plan, the NRC issued a revised
confirmatory action letter (the “Revised CAL”) on February 15, 2008 that outlines the actions APS
must take in order for the NRC to return the Palo Verde site to the NRC’s routine inspection and
assessment process. This Revised CAL was anticipated as part of the NRC’s inspection procedure and
a substantial majority of the actions required therein was contained in APS’ improvement plan.
The NRC has continued to provide increased oversight at Palo Verde. The Palo Verde management
team has implemented a substantial majority of its improvement plan and has been subject to routine
periodic NRC inspections throughout 2008. On February 5, 2009, APS submitted a letter to the NRC
stating that it has completed a substantial majority of the actions contained in the Revised CAL
and believes the Revised CAL can be closed. APS will continue cooperating fully with the NRC
throughout this process and anticipates receiving a response from the NRC within the next several
months related to the closure of the Revised CAL.
Nuclear Decommissioning Costs – The NRC rules on financial assurance requirements for the
decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive
financial assurance mechanism if the licensee recovers estimated total decommissioning costs
through cost-of-service rates or through a “non-bypassable charge.” The “non-bypassable systems
benefits” charge is the charge that the ACC has approved for APS’ recovery of certain types of
costs. “Non-bypassable” means that if a customer chooses to take energy from an “energy service
provider” other than APS, the customer will still have to pay this charge as part of the customer’s
APS electric bill.
Other mechanisms are prescribed, including prepayment, if the requirements for exclusive
reliance on an external sinking fund mechanism are not met. APS currently relies on an external
sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo
Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently
included in APS’ ACC jurisdictional rates. Decommissioning costs are recoverable through a
non-bypassable system benefits charge, which allows APS to maintain its external sinking fund
mechanism. See Note 12 for additional information about APS’ nuclear decommissioning costs.
Palo Verde Liability and Insurance Matters – See “Palo Verde Nuclear Generating Station” in
Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS,
for Palo Verde.
Alternative Generation Sources
In connection with its ongoing resource planning efforts, APS continues to focus on increasing
the percentage of its energy that is produced by renewable resources. On November 1,
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2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy
Standard”). Under the Renewable Energy Standard, electric utilities that are regulated by the ACC
must supply an increasing percentage of their retail electric energy sales from eligible renewable
resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable
energy requirement increases from 1.5% in 2007 to 15% in 2025. The requirement for 2009 is 2.0%.
In addition, an increasing percentage of that requirement must be supplied from distributed
resources (generally speaking, small-scale renewable technologies that are located on customers’
properties). The distributed resource requirement increases from 5% of the overall renewable
energy requirement in 2007 to 30% in 2012 and subsequent years. The requirement for 2009 is 15%.
APS currently has a diverse portfolio of renewable resources including wind, geothermal, solar and
biomass, which collectively generate over 120 MW of renewable energy for our customers. All of the
current renewable generation projects, except for solar, are acquired through long-term purchased
power agreements.
On February 8, 2008, APS entered into a Renewable Energy Purchase and Sale Agreement under
which APS agreed to purchase the energy and related renewable energy credits from a concentrated
solar power plant for a period of thirty years after the plant begins commercial operation. The
plant, which will have a nameplate rating of 280 MW and a projected annual output of 900,000 MWh,
will be located near Gila Bend, Arizona, which is about 70 miles southwest of Phoenix. The
agreement is subject to various conditions, including the developer obtaining project financing.
If these conditions are met, commercial operation is expected in 2012.
On February 28, 2008, APS signed a Renewable Energy Purchase and Sale Agreement under which
APS agreed to purchase the energy and related renewable energy credits from a wind power plant
located in New Mexico for a period of thirty years after the plant begins commercial operation in
2009. The plant has a nameplate rating of 100 MW and a projected annual output of 300,000 MWh.
APS continues to actively consider opportunities to enhance its renewable energy portfolio,
both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its
customer base.
Purchased Power Agreements
In addition to its own available generating capacity, APS purchases electricity under various
arrangements. APS’ purchased power capacity under long-term contracts, as of December 31, 2008, is
summarized in the table below. APS also purchases power through short-term markets to supplement
its long-term resources and hedge its energy requirements.
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APS continually assesses its need for additional capacity resources to assure system
reliability, although APS does not expect to need new capacity, beyond current plans, until around
2015. APS remains committed to seeking proposals from the competitive wholesale market for filling
its future resource needs, including renewable resource capacity.
Reserve Margin
APS’ 2008 peak one-hour demand on its electric system was recorded on August 1, 2008 at
7,025,900 kW, compared to the 2007 peak of 7,545,100 kW recorded on August 13, 2007. Taking into
account additional capacity then available to APS under long-term purchase power contracts, as well
as APS’ generating capacity, APS’ capability of meeting system demand on August 1, 2008, amounted
to 6,883,000 kW, for an installed reserve margin of negative 2.3%. The power actually available to
APS from its resources fluctuates from time to time due in part to planned and unplanned
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plant and transmission outages and technical problems. The available capacity from sources
actually operable at the time of the 2008 peak amounted to 5,831,000 kW, for a margin of negative
21.9%. Firm purchases totaling 2,626,000 kW, including short-term seasonal purchases and unit
contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load
requirement with an actual reserve margin of 20.6%.
Resource Plan
On January 29, 2009, APS submitted a Resource Plan Report to the ACC proposing a diverse
portfolio of generation resources to address the projected 60% increase in customer peak demand by
2025, which equates to approximately 6,500 MW of new capacity resources and accounts for both new
resources needed to meet growing customers loads as well as resources that will be needed to
replace expiring long-term purchases. The primary components of the Resource Plan include:
The Resource Plan would allow Arizona to increase its commitment to non-fossil fuel resources
because it does not include new coal-fired generation resources. The Resource Plan states that the
risk of future climate change legislation and the resulting potential for significant increases in
cost currently make coal-fired generation an unattractive resource choice. The Resource Plan also
addresses the transmission infrastructure expansion that will be required to accommodate the new
resources.
Under the Resource Plan, APS’ energy mix would change. Nuclear energy would increase to 32%
of its mix, renewable energy sources would increase to 16%, and
energy efficiency would increase to 7%. Coal-fired energy would decrease to 24% and gas-fired generation would decrease to 21%.
APS has requested the ACC to (a) either formally approve the Resource Plan or acknowledge that
APS has considered all relevant resources, risks and uncertainties and that the Resource Plan is
reasonable and in the public interest; (b) determine that the pursuit of renewable resources above
the Renewable Energy Standard is in the public interest; (c) determine that taking the initial
steps to preserve APS’ ability to pursue a new nuclear baseload resource is in the public interest;
and (d) determine that it is appropriate for APS to proceed to implement the Resource Plan. APS
cannot predict the outcome of this matter.
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Transmission and Distribution Facilities
APS’ transmission facilities consist of approximately 5,825 pole miles of overhead lines and
approximately 45 miles of underground lines, 5,601 miles of which are located in Arizona. APS’
distribution facilities consist of approximately 11,392 miles of overhead lines and approximately
16,630 miles of underground primary cable, all of which are located in Arizona. APS shares
ownership of some of its transmission facilities with other companies. The following table shows
APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance
Sheets at December 31, 2008:
Plant and Transmission Line Leases and Easements on Indian Lands
The Navajo Generating Station and Four Corners are located on land held under leases from the
Navajo Nation and also under easements from the federal government. The easement and lease for the
Navajo Generating Station expire in 2019 and the easement and lease for Four Corners expire in
2016. Each of the leases contains an option to extend for an additional 25-year period from the
end of the existing lease term, for a rental amount tied to the original rent payment adjusted
based on an index. The easements do not contain an express renewal option and it is unclear what
conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal
of the Navajo Generating Station and Four Corners leases and easements is uncertain. As noted
above under “Portfolio Resources – Coal Fueled Generating Facilities,” the coal contracted for use
in these plants is also located on Indian reservations.
Certain portions of the transmission lines that carry power from several of our power plants
are located on Indian lands pursuant to easements or other rights-of-way that are effective for
specified periods. Some of these rights-of-way have expired and our renewal applications have not
yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the
future and renewal action by the applicable tribe will be required at that time. The majority of
our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and
Navajo Generating Station plant leases provide Navajo Nation consent to certain of the
rights-of-way for transmission lines related to those plants at a specified rental rate for the
original term of the rights-of-way and for a like payment in any renewal period. In addition, a
1985 amendment to the leases provides a formula for calculating payments for certain new and
renewal rights-of-way. However, some of our rights-of-way are not covered by the leases, or are
granted by other Indian tribes. In recent negotiations with other utilities or companies for
renewal of similar rights-of-way, certain of the affected Indian tribes have required payments
substantially in excess of amounts that we have paid in the past for such rights-of-way or that are
typical for similar permits across non-Indian lands; however, we are unaware of the underlying
agreements and/or specific circumstances surrounding these renewals. The ultimate cost of renewal
of the rights-of-way for our transmission lines is
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uncertain. We are monitoring these rights-of-way and easement issues and have initiated
discussions with the Navajo Nation regarding them. We are currently unable to predict the outcome
of this matter.
Environmental Matters
EPA Environmental Regulation
Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These
regulations required states to submit state implementation plans (SIPs) by December 2007 to
demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class
I Areas,” including several on the Colorado Plateau. SIPs are required to consider and potentially
apply “best available retrofit technology” (BART) for certain older major stationary sources. The
rules allow nine western states and Indian tribes to follow an alternate implementation plan and
schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional
haze rules by providing guidelines, known as the BART guidelines, for states to use in determining
which facilities must install controls and the type of controls the facilities must use. The EPA
also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court
remand of that rule.
ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the
Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional
Haze SIPs were due to EPA Region 9 in December 2007, but are actually expected to be submitted
during 2009. As part of the rulemaking process, ADEQ is requiring certain sources in the state to
conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the
plants are potentially subject to BART and requesting that we either perform a BART analysis on
each plant or provide information demonstrating that we are not subject to BART. We completed a
BART analysis for Cholla and submitted our BART recommendations to ADEQ on February 4, 2008. Our
recommendations include the installation of certain pollution control equipment that we believe
constitutes BART. Once we receive ADEQ’s final determination as to what constitutes BART for
Cholla, we will have five years to complete the installation of the equipment and to achieve the
emission limits established by ADEQ. However, in order to coordinate with the plant’s other
scheduled activities, we are currently implementing portions of our recommended plan for Cholla on
a voluntary basis. Costs related to the implementation of these portions of our recommended plan
are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis
of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).
Because we believed that ADEQ’s baseline modeling for West Phoenix may have contained some
errors, we re-performed the baseline modeling using correct input and have determined that West
Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ, and ADEQ has
verbally informed us that West Phoenix is not subject to BART.
In addition, EPA Region 9 requested us to perform a BART analysis for Four Corners. We
completed the analysis and submitted it to the EPA on January 30, 2008. In December 2008, we
provided additional data in response to a request from the EPA. Our recommendations include the
installation of certain pollution control equipment that we believe constitutes BART. Once we
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receive the EPA’s final determination as to what constitutes BART for Four Corners, we will
have five years to complete the installation of the equipment and to achieve the emission limits
established by EPA Region 9. However, in order to coordinate with the plant’s other scheduled
activities, we will begin implementing initial portions of our recommended plan later this year for
Four Corners on a voluntary basis. Costs related to the implementation of these portions of our
recommended plan are included in our environmental expenditure estimates (see “Management’s
Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in
Item 7).
While we continue to monitor this matter, at the present time we cannot predict whether the
agencies will agree with our BART recommendations or, if the agencies disagree with our
recommendations, the nature of the BART controls the agencies may ultimately mandate and the
resulting financial or operational impact.
Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control
mercury emissions from coal-fired power plants. This rule establishes performance standards
limiting mercury emissions from coal-fired power plants and establishes a two phased market-based
emissions trading program. Under the trading program, the EPA has assigned each state a mercury
emissions “budget” and each state must submit to the EPA a plan detailing how it will meet its
“budget.”
In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally
incorporates the EPA’s model cap-and-trade program, but it includes additional requirements,
including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever
is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall
below the specified control level, and the requirement, beginning in 2013, to consider clean coal
technologies as part of permitting any new generation.
On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the
EPA rule that allowed for the creation of the CAMR, and on March 14, 2008, the court issued the
mandate to vacate these rules. On May 20, 2008, the D.C. Circuit denied the EPA’s request to
reconsider its decision. On October 17, 2008, the U.S. Solicitor General, on behalf of the EPA,
petitioned the Supreme Court for a writ of certiorari to review the judgment of the D.C. Circuit
Court of Appeals’ vacatur of the CAMR. In filing the petition, the U.S. contended, among other
things, that the Court of Appeals’ decision “effectively divests EPA of the discretion that
Congress conferred on the agency to consider alternative regulatory approaches to combating air
pollution from power plants.” Unless and until this decision is overturned, the law in effect
prior to the adoption of the CAMR becomes the applicable law, and requires the EPA to develop an
emission limit for mercury that represents the maximum achievable control technology. It is
expected to take the EPA several years to establish its standard, followed by a period of several
years during which existing plants would implement any controls needed to comply with the standard.
The court’s ruling also invalidates CAMR-based portions of ADEQ’s mercury rule (the trading
provisions of the rule), although the state-only emission limits remain in effect. On July 25,
2008, the Arizona Utilities Group (comprised of APS, Arizona Electric Power Cooperative, Salt River
Project, Tucson Electric Power Company, and Tri-State Generation and Transmission Association)
filed with ADEQ a Petition for Reconsideration and Repeal of the state mercury rule. The petition
asserts that ADEQ does not have statutory authority to administer and enforce the state mercury
rule, in light of the vacatur of the CAMR and the requirement that EPA promulgate a Maximum
Achievable Control Technology (“MACT”) standard. ADEQ granted the petition in part
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and agreed to begin rulemaking efforts to repeal those portions of ADEQ’s mercury rule that
are no longer valid in light of the vacatur of the federal CAMR. However, ADEQ denied the petition
with respect to certain compliance deadlines and, unless the Arizona Utilities Group reaches an
agreement with ADEQ on revisions to the state mercury rule, APS and others will have to comply with
the 90% mercury removal or 0.0087 lbs/GWh levels discussed above by
2013. On February 17, 2009,
APS signed a consent order with ADEQ under which APS will strive to achieve 50% mercury removal
commencing in 2011 and will fully comply with the ADEQ mercury rule by 2016, rather than by 2013 as
the rule currently prescribes.
While we continue to monitor this matter, we cannot predict the final outcome of the petition
to the Supreme Court, additional actions by ADEQ resulting from the federal court’s decision or the
Arizona Utilities Group petition, or the scope, timing or impact of any alternate rules that may be
enacted to address mercury emissions.
We have installed, and continue to install, certain of the equipment necessary to meet the
current mercury standards. However, due to the U.S. Court of Appeals decision described above, we
will monitor the type and timing of any necessary equipment installation. The estimated costs
expected to be incurred over the next three years for such equipment are included in our
environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial
Condition and Results of Operation – Capital Expenditures” in Item 7).
Federal Implementation Plan In September 1999, the EPA proposed FIPs to set air quality
standards at certain power plants, including Four Corners and the Navajo Generating Station. On
September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of
these plants.
Four Corners FIP
On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four
Corners. The FIP essentially federalizes the requirements contained in the New Mexico State
Implementation Plan, which Four Corners has historically followed. The FIP also includes a
requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a
petition for review in the United States District Court of Appeals for the Tenth Circuit seeking
revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra
Club intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a
petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and
we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a
20% opacity limit on certain fugitive dust emissions, which the EPA filed a motion to remand and
vacate in early December 2007, and a 20% stack opacity limit on Units 4 and 5. Briefing in this
case is now complete, and oral arguments as requested by the EPA were completed in May 2008. After
briefing was completed, the EPA voluntarily moved to vacate the fugitive dust provisions of the
FIP. The court has not yet ruled on that motion; however, in light of that motion, APS asked for,
and the EPA granted, an administrative stay of the fugitive dust provisions, and the Navajo Nation
EPA amended our Four Corners permit to specify that those requirements do not apply unless and
until the court denies the EPA’s motion. Although we cannot predict the outcome or the timing of
these matters, we do not believe that they will have a material adverse impact on our financial
position, results of operations or cash flows.
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Navajo Generating Station FIP
The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently
predict the effect of this proposed FIP on its financial position, results of operations or cash
flows, or whether the proposed FIP will be adopted in its current form.
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.
By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River
Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric
utility companies, owns a parcel of property on which a transmission pole and a portion of a
transmission line are located. The property abuts the Gila River Indian Community boundary and, at
one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is
only seeking payment from APS and four other PRPs for past cleanup-related costs involving
contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the
EPA in its letter to APS, we do not expect that the resolution of this matter will have a material
adverse impact on our financial position, results of operations, or cash flows.
Manufactured Gas Plant Sites APS is currently investigating properties, which it now owns or
which were previously owned by it or its corporate predecessors, that were at one time sites of, or
sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate
these sites. APS does not expect these matters to have a material adverse effect on its financial
position, results of operations, cash flows or liquidity.
Navajo Nation Environmental Issues
Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are
held under easements granted by the federal government as well as leases from the Navajo Nation.
See “Portfolio Resources – Coal Fueled Generating Facilities” above for additional information
regarding these plants.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control
Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively,
the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection
Agency authority to promulgate regulations covering air quality, drinking water and pesticide
activities, including those activities that occur at Four Corners and the Navajo Generating
Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station
participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District,
challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Generating
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Station. The Court has stayed these proceedings pursuant to a request by the parties, and the
parties are seeking to negotiate a settlement.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the
Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to
recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the
Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo
Generating Station participants each filed a petition with the Navajo Supreme Court for review of
the operating permit regulations. Those proceedings have been stayed, pending the settlement
negotiations mentioned above. APS cannot currently predict the outcome of this matter.
On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Generating
Station, and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their
disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. On March 21, 2006,
the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose
of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act
Title V, Part 71 federal permit program over Four Corners and the Navajo Generating Station. The
EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day.
Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of
the pending litigation in the Navajo Nation Supreme Court, as well as the pending litigation in the
Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts
have dismissed the claims accordingly. The agreement does not address or resolve any dispute
relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.
Water Supply
Assured supplies of water are important for APS’ generating plants. At the present time, APS
has adequate water to meet its needs. However, conflicting claims to limited amounts of water in
the southwestern United States have resulted in numerous court actions.
Both groundwater and surface water in areas important to APS’ operations have been the subject
of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS
is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial
District Court in New Mexico to adjudicate rights to a stream system from which water for Four
Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if
Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for
an agreed upon cost, sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the Lower Gila River
Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action
pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic
area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to
the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As
operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo
Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo
Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are
also located within the geographic area subject to the summons. APS’ claims dispute the court’s
jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks
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confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision
confirming that certain groundwater rights may be available to the federal government and Indian
tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the
lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has
continued in the trial court. In December 2005, APS and other parties filed a petition with the
Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order
regarding procedures for determining whether groundwater pumping is affecting surface water rights.
The Court denied the petition in May 2007, and the trial court is now proceeding with
implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set
in this matter.
APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an
action pending in the Apache County, Arizona, Superior Court, which was originally filed on
September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area
subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims
dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks
confirmation of such rights. A number of parties are in the process of settlement negotiations
with respect to certain claims in this matter. Other claims have been identified as ready for
litigation in motions filed with the court. No trial date concerning APS’ water rights claims has
been set in this matter.
Although the above matters remain subject to further evaluation, APS does not expect that the
described litigation will have a material adverse impact on its financial position, results of
operations, cash flows or liquidity.
The Four Corners region, in which Four Corners is located, has been experiencing drought
conditions that may affect the water supply for the plants if adequate moisture is not received in
the watershed that supplies the area. APS is continuing to work with area stakeholders to
implement agreements to minimize the effect, if any, on future operations of the plant. The effect
of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome,
if any, of the drought or whether the drought will adversely affect the amount of power available,
or the price thereof, from Four Corners.
Climate Change
Legislative and Regulatory Initiatives. In the past several years, the United States Congress
has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not
yet received sufficient Congressional approval 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. In 2007, the United States Supreme Court ruled
that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a
result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under
the Clean Air Act. The court held that the only way the EPA can avoid regulating greenhouse gases
is if it determines that the emissions do not contribute to climate change, or if the EPA provides
a reasonable explanation for why it cannot or will not exercise its discretion to regulate these
emissions. While this decision applies only to emissions from new motor vehicles, if the EPA
determines that greenhouse gas emissions can reasonably be anticipated to endanger public health or
welfare, this determination will likely impact other Clean Air Act programs as well, and could
potentially result in new regulatory requirements for our power plants.
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In addition to federal legislative initiatives, state specific initiatives may also impact our
business. While Arizona has not yet enacted any state specific legislation regarding greenhouse
gas emissions, AB 32 is a California statute mandating the reduction of greenhouse gas emissions to
1990 levels by 2020. In December 2008, the California Air Resources Board issued a final scoping
plan which is intended to form the basis of rules required under AB 32. On January 1, 2012, the
regulations based on the 2009 scoping plan will become effective. We are monitoring this and other
state legislative developments to evaluate whether, and the extent to which, any resulting statutes
or rules in California or other states may affect our business, including our sales into the
impacted states or the ability of our out-of-state power plant participants to meet their
obligations.
If any emission reduction legislation or regulations are enacted, we will assess our
compliance alternatives, which may include replacement of existing equipment, installation of
additional pollution control equipment, purchase of allowances, curtailing certain operations, or
other actions. Although associated capital expenditures or operating costs resulting from
greenhouse gas emission regulations or legislation could be material, we believe that we would be
able to recover the costs of these environmental compliance initiatives through our rates.
Regional Initiative. In 2007, six western states (Arizona, California, New Mexico, Oregon,
Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an
accord, the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions from
automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also
joined the Initiative. In August 2007, the Initiative participants set a goal of reducing
greenhouse gas emissions 15% below 2005 levels by 2020. Since May 2008, several draft documents
have been issued for public comment. We are reviewing the recommendations and requirements in
these documents, which currently provide only a general framework for the proposed program. Over
the next year, the Initiative participants intend to develop detailed rules to more fully establish
and define the program. Since details are not yet available, such as the number of allowances each
source may receive, we are unable to quantify the potential financial and operational impacts on
our business. In addition, we believe that the implementation of any such program in Arizona would
require legislative action. As a result, while we continue to monitor the progress and impact of
the Initiative, at the present time we cannot predict what detailed form it will ultimately take,
whether it will be implemented or, if it is implemented, what impact it will have on our
operations.
Company Response to Climate Change Initiatives. We have undertaken a number of initiatives to
address emission concerns, including renewable energy procurement and development, promotion of
programs and rates related to energy conservation, renewable energy use and energy efficiency, and
implementation of an active technology innovation effort to evaluate potential emerging new
technologies. APS currently has a diverse portfolio of renewable resources including wind,
geothermal, solar and biomass and we are focused on increasing the percentage of our energy that is
produced by renewable resources. (See “Portfolio Resources – Alternative Generation Sources”
above.) In January 2009, we submitted a Resource Plan Report to the ACC proposing our future plans
for additional diverse resources. See “Portfolio Resources – Resource Plan” above for information
regarding the Resource Plan Report, which was designed, in part, to increase Arizona’s commitment
to non-fossil resources.
In addition, we are currently developing a Climate Management Report to comply with an ACC
order that directed APS to undertake a climate management plan, carbon emission reduction study and
commitment and action plan with public input and ACC review. We expect to complete the report in
early 2009.
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In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters
are companies that voluntarily joined the non-profit organization before May 2008 to measure and
report greenhouse gas emissions in a common, accurate and transparent manner consistent across
industry sectors and borders. Pinnacle West has also reported, and will continue to report,
greenhouse gas emissions in its annual Corporate Responsibility Report, which is available on our
website (www.pinnaclewest.com). In addition to emissions data, the report provides
information related to the Company, its approach to sustainability and its workplace and
environmental performance. The information on Pinnacle West’s website, including the Corporate
Responsibility Report, is not incorporated by reference into this report.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of Arizona and is a developer of residential,
commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The
principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe,
Arizona 85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 480
employees at December 31, 2008.
At December 31, 2008, SunCor had total assets of about $547 million. SunCor’s assets consist
primarily of land with improvements, commercial buildings, golf courses and other real estate
investments. SunCor focuses on real estate development of master-planned communities, and
mixed-use residential, commercial, office and industrial projects.
SunCor projects include six master-planned communities and several commercial and residential
projects. Four of the master-planned communities and the commercial and residential projects are
in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.
SunCor’s operating revenues were approximately $131 million in 2008, $213 million in 2007 and
$400 million in 2006. SunCor’s net loss was approximately $26 million in 2008. SunCor’s net loss
in 2008 included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was
approximately $24 million in 2007 and $61 million in 2006. Certain components of SunCor’s real
estate sales activities, which are included in the real estate segment, are required to be reported
as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with
SFAS No. 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets.” See Notes 22 and
23.
See “Liquidity and Capital Resources – Other Subsidiaries – SunCor” in “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a
discussion of SunCor’s long-term debt, liquidity and capital requirements.
BUSINESS OF OTHER SUBSIDIARIES
APSES was incorporated in 1998 under the laws of Arizona and provides energy-related products
and services (such as energy master planning, energy use consultation and facility audits,
cogeneration analysis and installation, and project management) and competitive commodity-related
energy services (such as direct access commodity contracts, energy procurement and energy supply
consultation) to commercial and industrial retail customers in the western United States.
Recently, APSES has discontinued its commodity-related energy services (see Note 22). APSES had
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approximately 60 employees as of December 31, 2008. APSES’ principal offices are located at 60 E.
Rio Salado Parkway, Suite 1001, Tempe, Arizona 85281 (telephone 602-744-5060).
APSES had a net loss of $1 million in 2008, a net loss of $4 million in 2007 and a net loss of
$3 million in 2006. At December 31, 2008, APSES had total assets of $70 million.
El Dorado was incorporated in 1983 under the laws of Arizona. El Dorado owns minority
interests in several energy-related investments and Arizona community-based ventures. El Dorado’s
short-term goal is to prudently realize the value of its existing investments. On a long-term
basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the
business of generating, distributing and marketing electricity. El Dorado’s offices are located at
400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).
El Dorado had a net loss of $10 million in 2008, a net loss of $6 million in 2007 and a net
loss of $4 million in 2006. Income taxes related to El Dorado are recorded by Pinnacle West. At
December 31, 2008, El Dorado had total assets of $28 million.
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, liquidity and
results of operations.
APS is subject to comprehensive regulation by several federal, state and local regulatory
agencies that significantly influence its business, liquidity 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. Decisions made by the ACC could have a material adverse impact on
our results of operations, financial position or liquidity.
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.
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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, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash and air
pollution control wastes. These laws and regulations can result in increased capital, operating,
and other costs, particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require APS to obtain and comply with a wide
variety of environmental licenses, permits, 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.
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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
gases, including a 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. In addition, in 2007, the United States Supreme Court ruled that
greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a
result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under
the Clean Air Act. 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 capital expenditures and operating costs in
the form of taxes, emissions allowances or required equipment upgrades and could have a material
adverse impact on all fossil fuel fired generation facilities
(particularly coal fired facilities,
which constitute approximately 28% of our generation capacity). If the EPA determines that
greenhouse gas emissions can reasonably be anticipated to endanger public health or welfare, this
determination may impact other Clean Air Act Programs and could potentially result in new
regulatory requirements for our power plants, which could also result in substantial additional
costs. Excessive costs to comply with future legislation or regulations could force APS and other
similarly-situated electric power generators to close some coal-fired facilities.
There are inherent risks in the ownership and operation of nuclear facilities, such as
environmental, health, regulatory 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
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adversely affect our results of operations and financial condition. A major incident at a
nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or
licensing of any domestic nuclear unit.
The operation of Palo Verde requires licenses that need to be periodically renewed and/or
extended. In December 2008, we applied for renewed operating licenses for all three Palo Verde
units for 20 years beyond the expirations of the current licenses. 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, including increased purchased power expenses.
The ownership and operation of power generation and transmission facilities on Indian lands
could result in uncertainty related to continued easements and rights-of-way, which could have a
significant impact on our business.
Certain portions of the transmission lines that carry power from several of our power plants
are located on Indian lands pursuant to easements or other rights-of-way that are effective for
specified periods. We are currently unable to predict the outcome of discussions with the
appropriate Indian tribes with respect to future renewal of these easements and rights-of-way.
Deregulation or restructuring of the electric industry may result in increased competition,
which could have a significant adverse impact on our business and our results of operations.
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. Retail competition could have a significant adverse financial impact on APS due to an
impairment of assets, a loss of retail customers, lower profit margins or increased costs of
capital. Although some very limited retail competition existed in APS’ service area in 1999 and
2000, there are currently no active retail competitors offering unbundled energy or other utility
services to APS’ customers. As a result, 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
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the relatively low barriers to entry, we expect wholesale competition to increase, which could
adversely affect our business.
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.
Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and
an increased threat of forest fires. Forest fires could threaten our communities and electric
transmission lines. Any damage caused as a result of forest fires could negatively impact our
results of operations.
Our results of operations can be adversely affected by current economic conditions.
Customer growth in APS’ service territory was 1.4% during 2008. Customer growth averaged 3% a
year for the three years 2006 through 2008. We currently expect customer growth to decline,
averaging about 1% per year for 2009 through 2011 due to factors reflecting the economic conditions
both nationally and in Arizona. We currently expect our retail sales growth in 2009 to be below
average because of potential effects on customer usage from the economic conditions mentioned above
and retail rate increases, which would adversely affect our results of operations.
The lack of access to sufficient supplies of water could have a material adverse impact on our
business and results of operations.
Assured supplies of water are important for APS’ generating plants. Water in the southwestern
United States is limited and various parties have made conflicting claims regarding the right to
access and use such limited supply of water. Both groundwater and surface water in areas important
to APS’ generating plants have been the subject of inquiries, claims and legal proceedings. In
addition, the Four Corners region, in which Four Corners is located, has been experiencing drought
conditions that may affect the water supply for the plants if adequate moisture is not received in
the watershed that supplies the area. Our inability to access sufficient supplies of water could
have a material adverse impact on our business and results of operations.
Our cash flow largely depends on the performance of our subsidiaries.
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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.
Our inability to reduce capital expenditures could materially and adversely affect our
business, financial condition and results of operation.
Unexpected developments that may prevent us from reducing capital expenditures and other costs
while maintaining reliability and customer service levels could have a material adverse impact on
our financial position, results of operations, cash flows or liquidity.
Financial market disruptions may increase our financing costs or limit our access to the
credit markets, which may adversely affect our liquidity and our ability to implement our financial
strategy.
We rely on access to short-term money markets, longer-term capital markets and the bank
markets as a significant source of liquidity and for capital requirements not satisfied by the cash
flow from our operations. We believe that we will maintain sufficient access to these financial
markets. However, certain market disruptions may increase our cost of borrowing or adversely
affect our ability to access one or more financial markets. Such disruptions could include:
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In addition, the credit commitments of our lenders under our bank facilities may not be
satisfied for a variety of reasons, including unexpected periods of financial distress, which could
materially adversely affect the adequacy of our liquidity sources.
Changes in economic conditions could result in higher interest rates, which would increase our
interest expense on our debt and reduce funds available to us for our current plans. Additionally,
an increase in our leverage could adversely affect us by:
Recent sub-prime mortgage issues, the collapse of the credit markets, the weak housing market
and the overall weakening of the economy have adversely affected the financial markets, generally
resulting in increased interest rates for corporate debt, reduced access to the capital markets,
and actual or potential downgrades of bond insurers and banks, among other negative matters. In
general, the Company and APS have been unable to access the commercial paper markets since
September 2008. As a result, existing bank lines have been used as a source of liquidity on which
we depend. In addition, the interest rates on certain issues of APS’ pollution control bonds that
are periodically reset through auction processes have recently increased. These bonds are
supported by bond insurance policies provided by Ambac Assurance Corporation (“Ambac”), and the
interest rates on those bonds are directly affected by the rating of the bond insurer. 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.
The 2007 and 2008 financial results of SunCor, our real estate subsidiary, reflect the weak
real estate market and current economic conditions. SunCor’s principal loan facility is secured primarily by an interest in land, commercial properties,
land contracts and homes under construction (the “Secured Revolver”). At December 31, 2008,
SunCor had borrowings of approximately $120 million under this facility. The Secured Revolver
matures on January 30, 2010. In addition to the Secured Revolver, at December 31, 2008,
SunCor had approximately $68 million of outstanding debt under other credit facilities that
mature at various dates and also contain certain loan covenants. The majority of this
indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.
If SunCor is unable to meet its financial covenants under the Secured Revolver or its other
outstanding credit facilities, SunCor could be required to immediately repay its outstanding
indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt
acceleration would have a material adverse impact on SunCor’s business and its financial
position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company
does not believe that SunCor’s inability to meet its financial covenants under the Secured
Revolver or its other outstanding credit facilities would have a material adverse impact on
Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected
in Pinnacle West’s consolidated financial statements.
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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 or withdrawal could adversely
affect the market price of Pinnacle West’s and APS’ securities, limit our access to capital and
increase our borrowing costs, which would diminish our financial results. We would be required to
pay a higher interest rate in future financings, and our potential pool of investors and funding
sources could decrease. In addition, borrowing costs under certain of our existing credit
facilities depend on our credit ratings. A downgrade would also require us to provide substantial
additional support in the form of letters of credit or cash or other collateral to various
counterparties. If our short-term ratings were to be lowered, it could completely eliminate any
possible future access to the commercial paper market. We note that the ratings from rating
agencies are not recommendations to buy, sell or hold our securities and that each rating should be
evaluated independently of any other rating.
The use of derivative contracts in the normal course of our business 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 and coal, to the extent that
unhedged positions exist. We have established procedures to manage risks associated with these
market fluctuations by utilizing various commodity derivatives, including exchange-traded futures
and options and over-the-counter forwards, options, and swaps. As part of our overall risk
management program, we enter into derivative transactions to hedge purchases and sales of
electricity and fuels. The changes in market value of such
contracts have a high correlation to price changes in the hedged commodity. To the extent that
commodity markets are illiquid, we may not be able to execute our risk management strategies, which
could result in greater unhedged positions than we would prefer at a given time.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
use a risk management process to assess and monitor the financial exposure of all counterparties.
Despite the fact that the majority of trading counterparties are rated as investment grade by the
rating agencies, there is still a possibility that one or more of these companies could default,
which could result in a material adverse impact on our earnings for a given period.
Changing interest rates and market conditions could result in financial losses that negatively
impact our results of operations.
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
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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:
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.
Our stock price could be affected because a substantial number of shares of our common stock
could be available for sale in the future.
Sales in the public market of a substantial number of shares of common stock could depress the
market price of the common stock and could impair our ability to raise capital through the sale of
additional equity securities. Because of the number of shares of our common stock that we are
authorized to issue under our articles of incorporation, a substantial number of shares of our
common stock could be available for future sale.
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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.
Certain provisions of our articles of incorporation and bylaws and of Arizona law make it
difficult for shareholders to change the composition of our board and may discourage takeover
attempts.
These provisions, which could preclude our shareholders from receiving a change of control
premium, include the following:
In addition, we have adopted a shareholder rights plan that may have the effect of
discouraging unsolicited takeover proposals, including takeover proposals that could result in a
premium over the market price of our common stock. The shareholder rights plan will expire on
March 26, 2009.
While these provisions have the effect of encouraging persons seeking to acquire control of us
to negotiate with our Board of Directors, they could enable the Board to hinder or
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frustrate a transaction that some, or a majority, of our shareholders might believe to be in
their best interests and, in that case, may prevent or discourage attempts to remove and replace
incumbent directors.
SunCor’s business and financial performance could continue to 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:
As noted above (see the Risk Factor relating to “financial market disruptions”), at
December 31, 2008, SunCor had borrowings of approximately $120 million under its principal
loan facility, the Secured Revolver. The Secured Revolver matures on January 30, 2010. In
addition to the Secured Revolver, at December 31, 2008, SunCor had approximately $68
million of outstanding debt under other credit facilities that mature at various dates and also
contain certain loan covenants. The majority of this indebtedness is due in 2009, and SunCor
is in the process of renegotiating these facilities.
If SunCor is unable to meet its financial covenants under the Secured Revolver or its other
outstanding credit facilities, SunCor could be required to immediately repay its outstanding
indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt
acceleration would have a material adverse impact on SunCor’s business and its financial
position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company
does not believe that SunCor’s inability to meet its financial covenants under the Secured
Revolver or its other outstanding credit facilities would have a material adverse impact on
Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected
in Pinnacle West’s consolidated financial statements.
During 2008 the real estate market weakened significantly resulting in lower land and home
sales and depressed real estate prices. As a result, in 2008 we recognized certain impairment
charges. If conditions in the broader economy or the real estate markets
worsen, or as a result of a change in SunCor’s strategy, we may
be required to record additional impairements.
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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 2008 fiscal
year and that remain unresolved.
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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
“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.
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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, for information relating to the FERC proceedings on
California and Pacific Northwest energy market
issues, and for information regarding a billing dispute with SRP.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS Not applicable.
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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
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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 has announced that he will retire effective April 30, 2009. He will remain
a member of the Company’s Board of Directors and APS’ Board of Directors.
Mr. Brandt was elected to the Board of Directors of the Company and APS in January 2009.
Effective April 30, 2009, Mr. Brandt will continue to serve as President of Pinnacle West and will
also assume the positions of Pinnacle West’s Chairman of the Board and Chief Executive Officer.
Also effective April 30, 2009, Mr. Brandt will continue to serve as Chief Executive Officer of APS
and will assume the position of APS’ Chairman of the Board. Mr. Brandt was elected President and
Chief Operating Officer of Pinnacle West in March 2008. Prior to that time, he was Executive Vice
President of Pinnacle West (September 2003 – March 2008) and 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 Chief Executive Officer of APS in March 2008. Mr.
Brandt was elected President of APS in December 2006, a position he held until January 2009. 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.
Mr. Hatfield was elected to his present position effective July 2008. Prior to that time, he
was Senior Vice President and Chief Financial Officer of OGE Energy Corp. since 1999. His previous
experience includes nearly 14 years with OGE Energy Corp. in a variety of financial and management
leadership roles, including serving as Vice President and Treasurer, and more than 28 years of
electric and gas industry experience.
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).
Mr. Froggatt was elected to his present position for APS and Pinnacle West in December 2008.
Prior to that time, he was Vice President and Controller of APS (October 2002 – December 2008),
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 December 2008. Prior to that time, she was
Vice President and Treasurer of Pinnacle West and APS (February 2004 – December 2008), 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 January 2009. Prior
to that time, he was Senior Vice President, Planning and Administration of APS (November 2007 –
January 2009), Vice President, Planning of APS (September 2003 – November 2007), Vice President,
Finance and Planning of APS (October 2002 – September 2003) and Vice President, Regulation and
Planning of Pinnacle West (June 2001 – October 2002).
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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) and Vice President, HR
Relationship Leader, Global Corporate Travel Division (August 2003 – January 2007).
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).
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PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange.
At the close of business on February 16, 2009, Pinnacle West’s common stock was held of record by
approximately 29,295 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 2008 and 2007.
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, 2008, APS did not have any
outstanding preferred stock.
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Issuer Purchases of Equity Securities
The following table contains information about our purchases of our common stock during the
fourth quarter of 2008.
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ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION SELECTED CONSOLIDATED FINANCIAL DATA
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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY
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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.
While customer growth in APS’ service territory has been an important driver of our revenues
and earnings, it has significantly slowed, reflecting recessionary economic conditions both
nationally and in Arizona. Customer growth averaged 3% a year for the three years 2006 through
2008. We currently expect customer growth and retail electricity sales growth (excluding the
effects of weather variations) to average about 1% per year during 2009 through 2011. We currently
project that our customer growth will begin to accelerate as the economy recovers.
The near-term economic conditions are reflected in the recent volatility and disruption of the
credit markets, as discussed in detail under “Liquidity and Capital Resources – Pinnacle West
Consolidated” below. Despite these conditions, Pinnacle West and APS currently have ample
borrowing capacity under their respective credit facilities and have been able to access these
facilities, ensuring adequate liquidity for each company.
Our cash flows and profitability are affected by the electricity 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 –
Pinnacle West Consolidated,” are substantial because of increased costs related to environmental
compliance and controls and system reliability, as well as continuing, though slowed, customer
growth in APS’ service territory.
APS needs timely recovery through rates of its capital and operating expenditures to maintain
adequate financial health. See “Factors Affecting Our Financial Outlook” below. On March 24,
2008, APS filed a rate case with the ACC, which it updated on June 2, 2008, requesting, among other
things, an increase in retail rates to help defray rising infrastructure costs, approval of an
impact fee and approval of new conservation rates. See Note 3 for details regarding this rate
case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the
case.
The 2007 and 2008 financial results of SunCor, our real estate subsidiary, reflect the weak
real estate market and current economic conditions, which have adversely affected SunCor’s ability
to access capital. SunCor’s net loss in 2008 included a $53 million (pre-tax) real estate
impairment charge. If conditions in the broader economy or the real
estate markets worsen, or as a result of a change in SunCor’s
strategy, we may be required to record additional impairments (see
Note 23).
In addition to SunCor’s Secured Revolver, under which approximately $120 million in borrowings were
outstanding at December 31, 2008, SunCor had approximately $68 million of outstanding debt under
other credit facilities that mature at various dates and also contain certain loan covenants. The
majority of this indebtedness, except for the Secured Revolver, is due in 2009, and SunCor is in the process of renegotiating these
facilities. If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit
facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of
its credit facilities as a result of cross-default provisions. Such a debt acceleration would have
a material adverse impact on SunCor’s business and its financial position. The Company has not
guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s
inability to meet its financial covenants under the Secured Revolver or its other outstanding
credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity,
although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial
statements.
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Our other principal first tier subsidiaries, El Dorado and APSES, are not expected to have any
material impact on our financial results, or to require any material amounts of capital, over the
next three years.
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 customer base and to sustain
reliability.
See “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:
The following table presents income from continuing operations for our regulated electricity
and real estate segments and reconciles those amounts to net income in total for the years ended
2008, 2007, and 2006 (dollars in millions):
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PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
2008 Compared with 2007
Our consolidated net income decreased approximately $65 million, to $242 million in 2008 from
$307 million in 2007. The major factors that increased (decreased) our net income for the year
ended December 31, 2008 compared with the prior year are summarized in the following table (dollars
in millions):
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Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $209 million higher for the year ended December
31, 2008 compared with the prior year primarily because of:
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Real Estate Segment Revenues
Real estate segment revenues were $82 million lower for the year ended December 31, 2008
compared with the prior year primarily because of:
All Other Revenues
All other revenues were $78 million lower for the year ended December 31, 2008 compared with
the prior year primarily because of planned reductions of marketing and trading activities.
2007 Compared with 2006
Our consolidated net income decreased approximately $20 million, from $327 million for 2006 to
$307 million for 2007. The major factors that increased (decreased) net income for the year ended
December 31, 2007 compared with the prior year are summarized in the following table (dollars in
millions):
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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:
Real Estate Segment Revenues
Real estate segment revenues were $187 million lower for the year ended December 31, 2007
compared with the prior year primarily because of:
All Other Revenues
Other revenues were $13 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.
LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated
Cash Flows
The following table presents net cash provided by (used for) operating, investing and
financing activities for the years ended December 31, 2008, 2007 and 2006 (dollars in millions):
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2008 Compared with 2007
The increase of approximately $156 million in net cash provided by operating activities is
primarily due to lower current income taxes; lower real estate investments resulting from the weak
real estate market; and increased retail revenue related to higher Base Fuel Rates, partially
offset by increased collateral and margin cash provided as a result of changes in commodity prices.
The decrease of approximately $58 million in net cash used for investing activities is
primarily due to a real estate commercial property sale in 2008; lower levels of capital
expenditures (see table and discussion below); and increased contributions in aid of construction
related to changes in 2008 in APS’ line extension policy (see Note 3), partially offset by lower
cash proceeds from the net sales and purchases of investment securities.
The decrease of approximately $134 million in net cash provided by financing activities is
primarily due to the use of the proceeds from the sale of a real estate commercial property to pay
down long-term debt in 2008, partially offset by higher levels of short-term debt borrowings.
2007 Compared with 2006
The increase of approximately $264 million in net cash provided by operating activities is
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.
The increase of approximately $304 million in net cash used for investing activities is
primarily due to the proceeds of $208 million received in 2006 from the 2005 sale of Silverhawk and
an increase in cash used for capital expenditures and capitalized interest (see table and
discussion below), partially offset by higher cash proceeds from the net sales and purchases of
investments.
The increase of approximately $77 million in net cash provided by financing activities is
primarily due to higher levels of short-term borrowings, partially offset by a decrease in net new
long-term debt (issuances net of redemptions and refinancing).
Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for 2006, 2007 and 2008 and
estimated capital expenditures, net of contributions in aid of construction, for the next three
years:
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CAPITAL EXPENDITURES
(dollars in millions)
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, partially offset by contributions in aid of construction in
accordance with APS’ line extension policy.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil
and nuclear plants. Examples of the types of projects included in this category are additions,
upgrades and capital replacements of various power plant equipment such as turbines, boilers and
environmental equipment. Environmental expenditures differ for each of the years 2009, 2010 and
2011, with the lowest year estimated at approximately $25 million, and the highest year estimated
at approximately $80 million. We are also monitoring the status of certain environmental matters,
which, depending on their final outcome, could require modification to our environmental
expenditures. (See “Business of Arizona Public Service Company
– Environmental Matters – EPA
Environmental Regulation – Regional Haze Rules” and
“Environmental Matters – EPA Environmental
Regulation – Mercury” in Item 1.)
In early 2008, we announced and began implementing a cost reduction effort that included the
elimination of approximately $200 million of capital
expenditures for the years 2008 – 2012. These
capital expenditure reductions are reflected in the estimates provided above. Due primarily to our
reduced customer growth outlook as well as the deferral of upgrades and other capital projects, we
have identified additional capital expenditure reductions of over $500 million at APS (net of the
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change in
amounts collected for projected line extensions) over the years 2009 – 2011. These
reductions are across all areas – distribution, generation, transmission and general plant, and
are reflected in the estimates provided above. (See “Pinnacle
West Consolidated – Factors
Affecting Our Financial Outlook – Customer and Sales Growth” below for additional information on
our growth outlook.)
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 21, 2009, the Pinnacle West Board of Directors declared a quarterly dividend of
$0.525 per share of common stock, payable on March 2, 2009, to shareholders of record on February
2, 2009.
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 2006 through 2008,
total distributions from APS were $510 million and total distributions received from SunCor were
$15 million. For 2008, cash distributions from APS were $170 million and there were no
distributions from SunCor. An existing ACC order requires APS to maintain a common equity ratio of
at least 40% 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, 2008, APS’ common equity ratio, as defined, was approximately 54%.
The credit and liquidity markets experienced significant stress beginning the week of
September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been
negatively impacted by the market stress, they have both been able to access existing credit
facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds
consisting of U.S. Treasury and government agency securities and repurchase agreements
collateralized fully by U.S. Treasury and government agency securities.
At December 31, 2008, 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. Credit commitments totaling approximately $17 million from Lehman
Brothers are no longer available due to its September 2008 bankruptcy filing. The remaining $283
million revolver is available to support the issuance of up to $250 million in commercial paper
(see discussion above) or to be used as bank borrowings, including issuances of letters of credit
of up to $94 million. At December 31, 2008, Pinnacle West had outstanding $144 million of
borrowings under its revolving credit facility and approximately $7 million of letters of credit.
Pinnacle West had no commercial paper outstanding at December 31, 2008. In general, the Company
and APS have been unable to access the commercial paper markets since September 2008. At December
31, 2008, Pinnacle West had remaining capacity available
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under its revolver of approximately $132 million and had cash and investments of approximately
$6 million.
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 $35 million to our pension plan in
2008. On a cash funded basis, which is based on Internal Revenue Code regulations, our preliminary
estimate of the qualified plan’s funded status (market value of assets to liabilities) as of
January 1, 2009 is 98.6%. The plan’s IRS cash funded status was 94.3% as of January 1, 2008. Most
of the increase from the prior year was due to gains in the long-duration bonds and interest rate
swaps that we utilized in 2008 to better match the interest rate sensitivity of the plan’s assets
to that of the plan’s liabilities. The required minimum contribution to our pension plan is
estimated to be approximately $36 million in 2009 and approximately $25 million in 2010. The
expected contribution to our other postretirement benefit plans in 2009 is estimated to be
approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’
share is approximately 96% of both plans.
See Note 3 for information regarding Pinnacle West’s approval from the ACC regarding a
potential equity infusion into APS of up to $400 million.
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of
proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock
purchase and dividend reinvestment plan) and employee stock plans.
APS
APS’ capital requirements consist primarily of capital expenditures and mandatory redemptions
of long-term debt. APS pays for its capital requirements with cash from operations and, to the
extent necessary, equity infusions from Pinnacle West and external financings. 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.
APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion
at December 31, 2008. APS has two committed revolving credit
facilities totaling $900 million, of
which $400 million terminates in December 2010 and $500 million terminates in September 2011.
Credit commitments totaling about $34 million from Lehman Brothers are no longer available due to
its September 2008 bankruptcy filing. The remaining $866 million is available either to support
the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including
issuances of letters of credit up to $583 million. At December 31, 2008, APS had borrowings of
approximately $522 million and no letters of credit under its revolving lines of credit. APS had
no commercial paper outstanding at December 31, 2008. In general, the Company and APS have been
unable to access the commercial paper markets since September 2008. At December 31, 2008, APS had
remaining capacity available under its revolvers of $344 million and had cash and investments of
approximately $72 million.
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The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount
of approximately $343 million, are reset every seven days through auction processes. These bonds
are supported by bond insurance policies provided by Ambac, and the interest
rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond
insurers, including Ambac, have had downgrades of their credit ratings. Downgrades of bond
insurers result in downgrades of the insured bonds, which increases the possibility of a “failed
auction” and results in higher interest rates during the failed auction periods. When auctions of
APS bonds fail, the APS bondholders receive the maximum 14% annual interest rate for the week of
the failed auction. For the twelve months ended December 31, 2008, we had ninety-nine failed
auctions, which represented about 17% of all of our auctions. The average interest rate at December 31, 2008 on the auction rate securities was 12.4%.
Bond auctions continued to fail
through mid-January; however, since that time, we have had only one
failure. The average interest rate at February 18, 2009 on the auction rate securities was 5.7%.
We continue to closely monitor
this market and, if market and business conditions allow, we are
planning on refunding and reissuing these bonds during 2009.
We do not expect, however, that our auction rate interest exposure will have a material adverse
impact on our financial position, results of operations, cash flows or liquidity.
On September 11, 2008, APS repurchased at par two series of pollution control bonds that had
no credit enhancements. The repurchase included $7 million of its 1996 Series A Coconino County
Pollution Control Bonds and $20 million of its 1999 Series A Coconino County Pollution Control
Bonds. APS borrowed funds under its revolving lines of credit to re-purchase the bonds as
permitted under the bond indenture. APS intends to keep the $27 million outstanding until we
complete our planned refunding and reissuance of these bonds, if market and
business conditions allow, in 2009.
Although provisions in APS’ articles of incorporation and ACC financing orders establish
maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these
provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC
issued a financing order in which it approved APS’ request, subject to specified parameters and
procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to
(i) 7% of APS’ capitalization plus (ii) $500 million (which is required to be used for purchases of
natural gas and power) and (b) APS’ long-term debt authorization from approximately $3.2 billion to
$4.2 billion in light of the projected growth of APS and its customer base and the resulting
projected financing needs. This financing order expires
December 31, 2012; however, all debt previously authorized and
outstanding on December 31, 2012 will remain authorized and valid
obligations of APS.
Other
Financing Matters – See Note 3 for information regarding the PSA approved by the ACC.
Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery
of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA
adjustments.
See Note S-5 for information regarding an ACC order permitting Pinnacle West to infuse up to
$400 million of equity into APS, on or before December 31, 2009, if Pinnacle West deems it
appropriate to do so to strengthen or maintain APS’ financial integrity.
See “Cash Flow Hedges” in Note 18 for information related to the change in our margin account.
Other Subsidiaries
SunCor
– The weak real estate market and current economic conditions have adversely affected
SunCor’s financial results and its ability to access capital. During the past three years,
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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 2008 and projected capital expenditures for the next three years.
SunCor’s principal loan facility, the Secured Revolver, is secured primarily by an interest in
land, commercial properties, land contracts and homes under construction. On February 19, 2009,
SunCor and the Secured Revolver lenders extended the maturity date of the Secured Revolver to
January 30, 2010 (classified as current maturities of long-term debt at December 31, 2008). SunCor
is required to repay amounts under the Secured Facility in order to
reduce the
lenders’ commitments to a balance of $100 million by
December 31, 2009. The Secured Revolver requires compliance with certain loan covenants pertaining to debt to net worth, debt service,
liquidity, cash flow coverage and restrictions on debt. In addition to the Secured Revolver, at
December 31, 2008, SunCor had approximately $68 million of outstanding debt under other credit
facilities that mature at various dates and also contain certain loan covenants. The majority of
this indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.
If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit
facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of
its credit facilities as a result of cross-default provisions. Such a debt acceleration would have
a material adverse impact on SunCor’s business and its financial position. The Company has not
guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s
inability to meet its financial covenants under the Secured Revolver or its other outstanding
credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity,
although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial
statements.
SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60
million which was subsequently repaid in June 2008.
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 $188 million as of December 31, 2008,
including $120 million of debt classified as current maturities of long-term debt under revolving
lines of credit totaling $150 million. SunCor’s long-term debt, including current maturities, was
$183 million and total short-term debt was $5 million at December 31, 2008. See Notes 5 and 6. SunCor
had cash and investments of approximately $27 million at December 31, 2008.
El
Dorado – El Dorado expects minimal capital requirements over the next three years and
intends to focus on prudently realizing the value of its existing investments.
APSES
– APSES expects minimal capital expenditures over the next three years.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements
also include an interest coverage test. Pinnacle West and APS comply with these covenants and each
anticipates it will continue to meet these and other significant covenant requirements. For both
Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
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consolidated capitalization not exceed 65%. At December 31, 2008, the ratio was approximately 51%
for Pinnacle West and 49% for APS. The provisions regarding interest coverage require minimum cash
coverage of two times. The interest coverage was approximately 4.5 times under APS’ bank financing
agreements as of December 31, 2008. 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 18, 2009 are shown below.
The ratings reflect the respective views of the rating agencies, from which an explanation of the
significance of their ratings may be obtained. There is no assurance that these ratings will
continue for any given period of time. The ratings may be revised or withdrawn entirely by the
rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision
or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve
to increase the cost of and limit access to capital. It may also require substantial additional
collateral related to certain derivative instruments, natural gas transportation, fuel supply, and
other energy-related contracts.
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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, 2008, APS would have been required to assume
approximately $174 million of debt and pay the equity participants approximately $162 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 relate to
commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10
million bond on behalf of APS in connection with the interim base rate surcharge approved by the
ACC in December 2008. See “2008 General Rate Case — Interim Rate Surcharge” in Note 3. Our credit
support instruments enabled 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. At December 31, 2008, we had no guarantees that were in default. Our guarantees have
no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We
generally agree to indemnification provisions related to liabilities arising from or related to
certain of our agreements, with limited exceptions depending on the particular agreement. See Note
21 for additional information regarding guarantees and letters of credit.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of
December 31, 2008 (dollars in millions):
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This
table excludes $69 million in unrecognized tax benefits because the
timing of the future cash outflows in uncertain.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosures at the date of the financial statements and during the reporting
period. Some of those judgments can be subjective and complex, and actual results could differ
from those estimates. We consider the following accounting policies to be our most critical
because of the uncertainties, judgments and complexities of the underlying accounting standards and
operations involved.
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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 $795 million, including $8 million related to the PSA, of regulatory assets on the
Consolidated Balance Sheets at December 31, 2008.
Also included in the balance of regulatory assets at December 31, 2008 is a regulatory asset
of $473 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 $588 million of regulatory liabilities on the Consolidated Balance Sheets
at December 31, 2008, 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, 2008 reported pension liability on the Consolidated Balance
Sheets and our 2008 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):
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The following chart reflects the sensitivities that a change in certain actuarial assumptions
would have had on the December 31, 2008 reported other postretirement benefit obligation on the
Consolidated Balance Sheets and our 2008 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):
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
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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)).
See
“Market Risks – Commodity Price Risk” below for quantitative analysis. See “Fair Value
Measurements” below for additional information on valuation. See Note 1 for discussion on
accounting policies and Note 18 for a further discussion on derivative and energy trading
accounting.
Fair Value Measurements
We apply fair value measurements to derivative instruments, nuclear decommissioning trusts and
cash equivalents. We adopted SFAS No. 157, “Fair Value Measurements,” for our financial assets and
liabilities on January 1, 2008. SFAS No. 157 defines fair value as the price that would be received
to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. SFAS No. 157 establishes criteria to be considered when
measuring fair value and expands disclosures about fair value measurements. In accordance with
SFAS No. 157 we use inputs, or assumptions that market participants would use, to determine fair
market value, and the significance of a particular input determines how the instrument is
classified in the fair value hierarchy. We utilize valuation techniques that maximize the use of
observable inputs and minimize the use of unobservable inputs. The determination of fair value
sometimes requires subjective and complex judgment. Our assessment of the inputs and the
significance of a particular input to fair value measurement may affect the valuation of the
instruments and their placement within the fair value hierarchy. Actual results could differ from
our estimates of fair value. See Note 14 for further fair value measurement discussion, Note 1 for
discussion on accounting policies and Note 18 for a further discussion on derivative and energy
trading accounting.
Our nuclear decommissioning trusts invest in fixed income securities and equity securities.
The fair values of these securities are based on observable inputs for identical or similar assets.
See Note 12 for further discussion of our nuclear decommissioning trusts.
Real Estate Investment Impairments
We had real estate investments of $415 million and home inventory of $51 million on our
consolidated balance sheets at December 31, 2008. We assess impairment of these assets in
accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”
For purposes of evaluating impairment, we classify our real estate assets, such as land under
development, land held for future development, and commercial property, as “held and used.” When
events or changes in circumstances indicate that the carrying value of real estate assets
considered held and used may not be recoverable, we compare the undiscounted cash flows that we
estimate will be generated by each asset to its carrying amount. If the carrying amount exceeds
the undiscounted cash flows, we adjust the asset to fair value and recognize an impairment charge.
The adjusted value becomes the new book value (carrying amount) for held and used assets. We may
have real estate assets classified as held and used with fair values that are lower than their
carrying amounts, but are not deemed to be impaired because the undiscounted cash flows exceed the
carrying amounts.
Real estate home inventory is considered to be held for sale for the purposes of evaluating
impairment in accordance with the provisions of SFAS No. 144. Home inventories are reported at
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the lower of carrying amount or fair value less cost to sell. Fair value less cost to sell is
evaluated each period to determine if it has changed. Losses (and gains not to exceed any
cumulative loss previously recognized) are reported as adjustments to the carrying amount.
We determine fair value for our real estate assets primarily based on the future cash flows
that we estimate will be generated by each asset discounted for market risk. Our impairment
assessments and fair value determinations require significant judgment regarding key assumptions
such as future sales prices, future construction and land development costs, future sales timing,
and discount rates. The assumptions are specific to each project and may vary among projects. The
discount rates we used to determine fair values at December 31,
2008 ranged from 17% to 27%. Due
to the judgment and assumptions applied in the estimation process, with regard to impairments, it
is possible that actual results could differ from those estimates. If conditions in the broader economy or the real estate markets
worsen, or as a result of a change in SunCor’s strategy, we may
be required to record additional impairments.
OTHER ACCOUNTING MATTERS
See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted
effective January 1, 2008, and the following related accounting guidance:
See Notes 18 and S-3 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB
Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we
adopted January 1, 2008.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was
effective for us on January 1, 2008. This guidance provides companies with an option to report
selected financial assets and liabilities at fair value. We did not elect the fair value option
for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on
our financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and
Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and
hedging activities. The Statement is effective for us on January 1, 2009. It did not have a
material impact on our financial statements.
In December 2008, the FASB issued FASB Staff Position No. 132(R)-1, “Employers’ Disclosures
about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer disclosures
about plan assets of a defined benefit pension or other postretirement plan. The guidance is
effective for us on December 31, 2009. We do not expect it to have a material impact on our
financial statements.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which was
adopted January 1, 2007.
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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 2006 through 2008, retail electric revenues comprised approximately 91% 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 below under “Liquidity and Capital Resources
– Pinnacle West Consolidated,” are substantial because of environmental compliance and controls,
system reliability, and continuing, though slowed, customer growth in APS’ service territory. APS
needs timely recovery through rates of its capital and operating expenditures to maintain adequate
financial health. On March 24, 2008, APS filed a rate case with the ACC, which it updated on June
2, 2008, requesting, among other things, an increase in retail rates to help defray rising
infrastructure costs, approval of an impact fee and approval of new conservation rates. See Note 3
for details regarding this rate case, including the ACC’s approval of an interim base rate
surcharge pending the outcome of the case.
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 Note 3 for information regarding the PSA. 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 1.4%
during 2008. Customer growth averaged 3% a year for the three years 2006 through 2008. We
currently expect customer growth to decline, averaging about 1% per year for 2009 through 2011 due
to factors reflecting the economic conditions both nationally and in Arizona. For the three years
2006 through 2008, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual
rate of 2.9%; adjusted to exclude the effects of weather variations, such retail sales growth
averaged 2.9% a year. We currently estimate that total retail electricity sales in kilowatt-hours
will grow 1% on average per year during 2009 through 2011, excluding the effects of weather
variations. We currently expect our retail sales growth in 2009 to be below average because of
potential effects on customer usage from the economic conditions mentioned above and retail rate
increases (see Note 3).
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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 under normal business
conditions 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 and fuels. See “Formula Transmission Tariff” in Note
3 for information regarding APS’ recent filing with the FERC requesting a change to the formula
rate.
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 7.8% of the assessed value for 2008, 8.3% of the assessed value for 2007 and 8.9% of assessed
value for 2006. 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. (See Note 6.) The primary factors affecting borrowing levels are
expected to be our capital expenditures, long-term debt maturities, and internally generated cash
flow. Capitalized interest offsets a portion of interest expense while capital projects are under
construction. We stop accruing capitalized interest on a project when it is placed in commercial
operation.
Climate Change Recent concern over climate change could have a significant impact on our
capital expenditures and operating costs in the form of taxes, emissions allowances or required
equipment upgrades. The timing and type of compliance measures and related costs are impacted by
current and future regulatory and legislative actions, which we are closely monitoring. See
“Business of Arizona Public Service Company – Climate Change” in Item 1 for more information
regarding climate change initiatives.
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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 loss was approximately $26 million in 2008. SunCor’s net loss in
2008 included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was
approximately $24 million in 2007 and $61 million in 2006. See Note 23 for further discussion.
This estimate reflects continuation of the slowdown in the western United States real estate
markets. See “Liquidity and Capital Resources – Other
Subsidiaries – SunCor” and Note 6 for a
discussion of SunCor’s long-term debt, liquidity, and capital requirements.
The historical results of APSES 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” and “Risk Factors” above 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,
2008 and 2007. The interest rates presented in the tables below represent the weighted-average
interest rates as of December 31, 2008 and 2007 (dollars in thousands):
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Pinnacle
West – Consolidated
The tables below present contractual balances of APS’ long-term debt at the expected maturity
dates as well as the fair value of those instruments on December 31, 2008 and 2007. The interest
rates presented in the tables below represent the weighted-average interest rates as of December
31, 2008 and 2007 (dollars in thousands):
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APS
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity and natural gas. Our energy risk management committee,
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 and fuels. 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 2008 and 2007 (dollars in millions):
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The tables below show the fair value of maturities of our derivative contracts (dollars in
millions) at December 31, 2008 by maturities and by the type of valuation that is performed to
calculate the fair values. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for
more discussion of our valuation methods.
The table below shows the impact that hypothetical price movements of 10% would have on the
market value of our risk management and trading assets and liabilities included on Pinnacle West’s
Consolidated Balance Sheets at December 31, 2008 and 2007 (dollars in millions):
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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 Note 3 for information about rate matters affecting APS.
2008 Compared with 2007
APS’ net income decreased approximately $22 million, to $262 million in 2008 from $284 million
in 2007. The major factors that increased (decreased) net income for the year ended December 31,
2008 compared with the prior year are summarized in the following table (dollars in millions):
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Electric operating revenues were $197 million higher for the year ended December 31, 2008
compared with the prior year primarily because of:
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2007 Compared with 2006
Our net income increased approximately $14 million, to $284 million for 2007 from $270 million
for 2006. 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):
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Electric operating revenues were $278 million higher for the year ended December 31, 2007
compared with the prior year primarily because of:
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LIQUIDITY
AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY
Cash Flows
The following table presents APS’ net cash provided by (used for) operating, investing and
financing activities for the years ended December 31, 2008, 2007 and 2006 (dollars in millions):
2008 Compared with 2007
The increase of approximately $19 million in net cash provided by operating activities is
primarily due to lower current income taxes and increased retail revenue related to higher Base
Fuel Rates, partially offset by increased collateral and margin cash provided as a result of
changes in commodity prices.
The decrease of approximately $2 million in net cash used for investing activities is
primarily due to lower levels of capital expenditures (see table and discussion above) and
increased contributions in aid of construction related to changes in 2008 in our line extension
policy (see Note 3), substantially offset by lower cash proceeds from the net sales and purchases
of investment securities.
The increase of approximately $28 million in net cash provided by financing activities is
primarily due to higher levels of short-term borrowings, partially offset by decreased equity
infusions from Pinnacle West and the repurchase of pollution control bonds (see Note 6).
2007 Compared with 2006
The increase of approximately $372 million in net cash provided by operating activities is
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.
The increase of approximately $167 million in net cash used for investing activities is
primarily due to an increase in cash used for capital expenditures (see table and discussion above)
and
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increased allowance for borrowed funds used during construction, partially offset by higher
cash proceeds from the net sales and purchases of investment securities.
The decrease of approximately $266 million in net cash provided by financing activities is
primarily due to a decrease in net new long-term debt (issuances net of redemptions and
refinancing) and a decrease in equity infusions from Pinnacle West, partially offset by higher
levels of short-term borrowings to fund day-to-day operations and liquidity needs.
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, 2008
(dollars in millions):
This
table excludes $68 million in unrecognized tax benefits because the
timing of the future cash outflows is uncertain.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK See “Factors Affecting Our Financial Outlook” in Item 7 above for a discussion of quantitative
and qualitative disclosures about market risk.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.
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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, 2008.
The effectiveness of our internal control over financial reporting as of December 31, 2008 has
been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated
in their report which is included herein and also relates to the Company’s consolidated financial
statements.
February 19, 2009
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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, 2008 and 2007, 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, 2008. 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, 2008, 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.
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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, 2008 and 2007, and the
results of their operations and their cash flows for each of the three years in the period ended
December 31, 2008, 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, 2008,
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’ Accounting for Defined Benefit
Pension and Other Postretirement Plans, effective December 31, 2006.
/s/
Deloitte & Touche LLP
DELOITTE & TOUCHE LLP Phoenix, Arizona February 19, 2009 82
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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.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS (dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS (dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements.
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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). 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 discontinued its commodity-related energy
services (see Note 22). El Dorado is an investment firm. Pinnacle West Marketing & Trading began
operations in early 2007. These operations were previously conducted by a division of Pinnacle
West through the end of 2006. By the end of 2008, substantially all the contracts were transferred
to APS or expired.
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally
accepted in the United States of America (GAAP). The preparation of financial statements in
accordance with GAAP requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of
the financial statements and reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity and natural gas. We manage risks associated with these
market fluctuations by utilizing various instruments that qualify as derivatives, including
exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of
our overall risk management program, we use such instruments to hedge purchases and sales of
electricity and fuels. The changes in market value of such
contracts have a high correlation to price changes in the hedged transactions.
We account for our derivative contracts in accordance with 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
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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 value in accordance with SFAS No. 157, “Fair Value Measurements.” SFAS No.
157 defines fair value as the price that would be received for an asset or paid to transfer a
liability (exit price) in the principal or most advantageous market for the asset or liability in
an orderly transaction between willing market participants on the measurement date. Inputs to fair
value include observable and unobservable data. We maximize the use of observable inputs and
minimize the use of unobservable inputs when measuring fair value.
We determine fair market value using actively-quoted prices for identical instruments when
available. When actively quoted prices are not available for the identical instruments we use
prices for similar instruments or other corroborative market information or prices provided by
other external sources. Quarterly and calendar year quotes from independent brokers are converted
into monthly prices using historical relationships. We consider broker quotes observable inputs
when the quote is binding on the broker, we can validate the quote with market transactions, or we
can determine that the inputs the broker used to arrive at the quoted price are observable.
For options, long-term contracts and other contracts for which price quotes are not available,
we use unobservable inputs, such as models and other valuation methods, to determine fair market
value. The 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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.
See Note 14 for additional information about 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 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. (See Note 3).
Also included in the balance of regulatory assets at December 31, 2008 is a regulatory asset
for pension and other postretirement benefits in accordance with SFAS No. 158. This regulatory
asset represents the future recovery of these costs through retail rates as these amounts are
charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be
charged to OCI and result in lower future earnings.
The detail of regulatory assets is as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The detail of regulatory liabilities is as follows (dollars in millions):
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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Retirement 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, 2008 were as follows:
For the years 2006 through 2008, the depreciation rates ranged from a low of 1.11% to a high
of 12.46%. The weighted-average rate was 3.08% for 2008, 3.11% for 2007 and 3.14 % for 2006. 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
SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” See Note 12 for
more information on these investments.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance non-regulated
construction projects. The rate used to calculate capitalized interest was a composite rate of
5.2% for 2008, 5.8% for 2007 and 6.8% for 2006. Capitalized interest ceases when construction is
complete.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 7.0% for 2008, 8.2% for 2007 and 8.0% for
2006. 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 exclude sales taxes and franchise fees on electric revenues from both revenue and
taxes other than income taxes.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross
basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some
contracts to purchase energy are netted against other contracts to sell energy. This is called a
“book-out” and usually occurs for contracts that have the same terms (quantities and delivery
points) and for which power does not flow. We net these book-outs, which reduces both revenues and
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory, commercial property
and investments in joint ventures. Land includes acquisition costs, infrastructure costs,
capitalized interest and property taxes directly associated with the acquisition and development of
each project. Home inventory consists of construction costs, improved lot costs, capitalized
interest and property taxes on homes and condos under construction. Homes under construction are
classified as “real estate investments” on the Consolidated Balance Sheets; upon completion of
construction they are transferred to “home inventory” with the expectation that they will be sold
in a timely manner.
For the purposes of evaluating impairment in accordance with the provisions of SFAS No. 144,
“Accounting for the Impairment or Disposal of Long-Lived Assets,” we classify our real estate
assets, including land under development, land held for future development, and commercial property
as “held and used.” When events or changes in circumstances indicate that the carrying values of
real estate assets considered held and used may not be recoverable, we compare the undiscounted
cash flows that we estimate will be generated by each asset to its carrying amount. If the
carrying amount exceeds the undiscounted cash flows, we adjust the asset to fair value and
recognize an impairment charge. The adjusted value becomes the new book value (carrying amount)
for held and used assets.
Real estate home inventory is considered to be held for sale for purposes of evaluating
impairment in accordance with the provisions of SFAS No. 144. Home inventories are reported at the
lower of carrying amount or fair value less costs to sell. Fair value less costs to sell is
evaluated each period to determine if it has changed. Losses (and gains not to exceed any
cumulative loss previously recognized) are reported as adjustments to the carrying amount.
Investments in joint ventures for which SunCor does not have a controlling financial interest
are not consolidated, but are accounted for using the equity method of accounting. In addition,
see Note 22 – Discontinued Operations and Note 23 – Real Estate Impairment Charge.
Cash and Cash Equivalents
We consider all highly liquid investments with a maturity of three months or less at
acquisition to be cash equivalents.
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production
method is based on actual physical usage. APS divides the cost of the fuel by the estimated number
of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number
of thermal units produced within the current period. This calculation determines the current
period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent
nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges
APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel
disposal and Note 12 for information on nuclear decommissioning costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 largest amount of tax benefit that is greater than 50%
likely of being realized upon settlement for all known and measurable tax exposures. See Note 4.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily
APS’ software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142,
“Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite
useful lives. Amortization expense was $33 million in 2008, $37 million in 2007 and $39 million in
2006. Estimated amortization expense on existing intangible assets over the next five years is $29
million in 2009, $27 million in 2010, $21 million in 2011, $18 million in 2012 and $13 million in
2013. At December 31, 2008, the weighted average remaining amortization period for intangible
assets was 8 years.
2. New Accounting Standards
See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted
effective January 1, 2008, and the following related accounting guidance:
See Notes 18 and S-3 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB
Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we
adopted January 1, 2008.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was
effective for us on January 1, 2008. This guidance provides companies with an option to report
selected financial assets and liabilities at fair value. We did not elect the fair value option
for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on
our financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and
Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and
hedging activities. The Statement is effective for us on January 1, 2009. It did not have a
material impact on our financial statements.
In December 2008, the FASB issued FASB Staff Position No. 132(R)-1, “Employers’ Disclosures
about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer’s disclosures
about plan assets of a defined benefit pension or other postretirement plan. The guidance
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS is effective for us on December 31, 2009. We do not expect it to have a material impact on our
financial statements.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which was
adopted January 1, 2007.
3. Regulatory Matters
2008 General Rate Case
APS Request – On June 2, 2008, APS filed with the ACC updated financial statements, testimony
and other data in the general rate case originally filed on March 24, 2008. As requested by the
ACC staff, the updated information reflects a test year ended December 31, 2007, rather than the
September 30, 2007 test year used in APS’ original filing. As a result of the updated filing, APS
is requesting a net retail rate increase of $278.2 million effective no later than October 1, 2009,
which represents a base rate increase of $448.2 million less the reclassification of $170 million
of fuel and purchased power revenues from the existing PSA to base rates. As proposed by APS, the
updated request would result in an average rate increase of 8.5% for existing customers plus the
establishment of a new growth-related impact fee to be charged to new connections.
The key financial provisions of the updated request include:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The update also requests that the ACC adopt certain goals for APS to improve its financial
strength, which include: allowing APS’ internal cash flow generation to cover its operating and
capital costs of providing service; stabilizing and improving APS’ credit ratings; and providing a
meaningful and ongoing opportunity for APS to achieve a reasonable return on the fair value of its
property.
In addition, APS requested various modifications to the Environmental Improvement Surcharge
and the Demand Side Management Adjustment Clause that would allow APS to expand its conservation
and demand-side management programs and support environmental upgrades to APS facilities in
response to and in anticipation of future environmental requirements.
Interim Rate Surcharge – On December 18, 2008, the ACC approved an emergency interim base
rate surcharge for APS. This surcharge became effective for retail customer bills issued after
December 31, 2008 and will continue in effect until a decision in the general rate case becomes
effective. This surcharge is expected to increase annual pretax retail revenues approximately
$65.2 million, and is subject to refund with interest pending the final outcome of APS’ general
retail rate case. In June 2008, APS had requested an interim increase of approximately $115
million in annual pretax retail revenues.
The decision requires that APS (a) examine its operations and expenses, targeting additional
cuts of at least $20 million, report the results of its study to the ACC no later than March 18,
2009, and reinvest the savings and surcharge revenues “in infrastructure and technology necessary
to serve APS customers and reduce the need for external debt financing”; (b) file with the ACC
periodic reports of communications with credit ratings agencies; and (c) post a $10 million bond or
letter of credit until the ACC issues a final order in APS’ general retail rate case.
ACC Staff Rate Case Recommendation – On December 19, 2008, the ACC staff and other
intervenors filed their initial written testimony with the ACC in the general retail rate case. In
its filed testimony, the ACC staff recommends a number of cost disallowances and test-year
adjustments that decrease APS’ base rate request by $141.6 million. The principal components of the
revenue increase recommended by the ACC staff are $155.1 million for non-fuel increases and $11.4
million for fuel and purchased power costs reflected in base rates (net of the reclassification of
$140.1 million of existing PSA revenues to base rates).
In its recommendations, the ACC staff also proposed, among other things:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The ACC staff also recommended that the ACC reject the following APS proposals:
Other Intervenors’ Recommendations – Other intervenors in the rate case include the Arizona
Residential Utility Consumer Office (“RUCO”), an office established by the Arizona legislature to
represent the interests of residential utility consumers before the ACC; and Arizonans for Electric
Choice and Competition (“AECC”), a coalition that advocates on behalf of commercial and
industrial utility customers. These other intervenors’ testimony includes the following
recommendations:
Settlement Discussions and Procedural Schedule – On January 30, 2009, APS began settlement
discussions with the parties to the general rate case. An ACC ALJ has issued a procedural order
staying the procedural schedule in the rate case for thirty days to allow the parties to
participate in settlement discussions. While it is in effect, the stay vacates previously
established dates for testimony filings and the discovery process. Additional stays may be
requested by the parties, depending on the settlement discussions. Hearings in the rate case were
previously scheduled to begin on April 2, 2009.
2007 Retail Rate Order
In June 2007, the ACC issued an order in a general retail rate case that APS filed in late
2005. The order approved a $322 million increase in APS’ annual retail base revenues, effective
July 1, 2007, which included a $315 million fuel-related increase and a $7 million non-fuel related
increase. The order also authorized APS’ recovery of approximately $34 million of 2005 PSA
deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007,
disallowed approximately $14 million in 2007 of 2005 PSA deferrals because it found the Palo Verde
outage costs giving rise to those amounts resulted from APS’ imprudence, modified the PSA in
various respects and increased the Base Fuel Rate. In addition, the order provided that the 2007
PSA adjustor, which took effect on February 1, 2007 and that was scheduled to expire on January 31,
2008, remain in effect as long as necessary to allow APS to collect $46 million of PSA deferrals
resulting from the mid-2007 implementation of the new Base Fuel Rate. The 2007 PSA adjustor
expired as of the last billing cycle in July 2008.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PSA Mechanism
The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, and which
was modified by the ACC in 2007, provides for the adjustment of retail rates to reflect variations
in retail fuel and purchased power costs. The PSA is subject to specified parameters and
procedures, including the following:
PSA Balance
The following table shows the changes in the deferred fuel and purchased power regulatory
asset for the year ended December 31, 2008 and 2007 (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The PSA annual adjustor rate is reset for a “PSA Year” effective for a twelve-month period
beginning February 1 each year. The PSA rate for the PSA Year that began February 1, 2008 was set
at $0.004 per kWh. The PSA rate for the PSA year that began February 1, 2009 was set at $0.0053
per kWh. The PSA rate may not be increased more than $0.004 per kWh in a year without permission
of the ACC. Any uncollected deferrals during the 2009 PSA Year resulting from this limit will be
included in the historical component of the PSA rate for the PSA Year beginning February 1, 2010.
Formula Transmission Tariff
In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed
rates to a formula rate-setting methodology in order to more accurately reflect the costs that APS
incurs in providing transmission services. The formula rate is updated each year effective June 1
on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the
previous fiscal year, and projected capital expenditures. A large portion of the rate represents
charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).
In order to recover the Retail Transmission Charges, APS must file an application with the ACC
under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission
Charges can be reflected in APS’ retail rates.
In 2008, APS was authorized to implement increases in its annual transmission revenues based
on calculations filed with the FERC using data for its 2006 and 2007 fiscal years. Increases in
APS’ annual transmission revenues of $28 million became effective March 1, 2008 and $15 million
became effective June 1, 2008. The ACC allowed APS to reflect the related increased Retail
Transmission Charges in its retail rates through the TCA resulting in increases of annual retail
revenues of $27 million effective March 1, 2008 and $13 million effective July 3, 2008.
Equity Infusion Approval
On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to
infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do
so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing
regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an
equity infusion into APS that exceeds $150 million in a single calendar year. On August 6, 2008,
the ACC issued an order permitting the infusion to occur on or before December 31, 2009.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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.
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 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 accepted conditionally by the FERC in an order issued
January 17, 2008. In compliance with the January 17, 2008 order, the Pinnacle West Companies filed
a revised mitigation plan to implement cost-based rates for sales in the Phoenix Valley during the
summer months. On May 30, 2008, the FERC issued a letter order accepting our mitigation plan. The
first summer period under this cost-based mitigation began on June 1, 2008. This proceeding is now
concluded.
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 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 was the subject of an IRS review and the IRS finalized its examination in the
second quarter of 2008,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS which included a settlement on the tax accounting method change and
favorable resolution of other various tax matters. As a result of this settlement and the lapse of
federal statutes prior to 2005, we recognized net income tax benefits of approximately $30 million,
including approximately $23 million related to interest.
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. The following is a tabular reconciliation of the total amounts of
unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period
that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets
(dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2008 and 2007 were
approximately $16 million and $5 million, respectively, 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 consolidated
statement of income as income tax expense. The amount of interest recognized in the consolidated
statement of income related to unrecognized tax benefits was a pre-tax benefit of $51 million for
2008 and pre-tax expense of $3 million for 2007.
The total amount of accrued liabilities for interest recognized in the consolidated balance
sheets related to unrecognized tax benefits as of December 31, 2008 and 2007 was $6 million and $57
million, respectively. To the extent that matters are settled favorably, this amount could reverse
and decrease our effective tax rate. Additionally, as of December 31, 2008, we have recognized $1
million of interest expense to be paid on the underpayment of income taxes for certain adjustments
that we have filed, or will file, with the IRS.
The tax year ended December 31, 2005 and all subsequent tax years remain subject to
examination by the IRS. With few exceptions, we are no longer subject to state income tax
examinations by tax authorities for years before 1999. We do not anticipate that there will be any
significant increases or decreases in our unrecognized tax benefits within the next 12 months.
The components of income tax expense are as follows (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following chart compares pretax income from continuing operations at the 35% federal
income tax rate to income tax expense – continuing operations (dollars in thousands):
The following table shows the net deferred income tax liability recognized on the Consolidated
Balance Sheets (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 2008 and December 31, 2007 due to terminate in December 2010. Credit commitments
totaling approximately $17 million from Lehman Brothers are no longer available due to its
September 2008 bankruptcy filing. The remaining $283 million revolver 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 of up to $94 million. At December 31, 2008 Pinnacle West had $144
million of borrowings under its revolving credit facility and approximately $7 million of letters
of credit. Pinnacle West had no commercial paper outstanding at December 31, 2008. In general,
the Company and APS have been unable to access the commercial paper markets since September 2008.
Pinnacle West had remaining capacity available under its revolver of approximately $132 million and
had cash and investments of approximately $6 million. At December 31, 2007, Pinnacle West had no
borrowings under the line of credit and approximately $5 million of letters of credit and
commercial paper borrowings of $115 million. The commitment fees were 0.15 % in 2008 and 2007.
The weighted average interest rates were 2.713% at December 31, 2008 and 5.73% at December 31,
2007. All Pinnacle West and APS bank lines of credit and commercial paper agreements are
unsecured.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS APS had two committed revolving credit facilities totaling $900 million at December 31, 2008
and December 31, 2007, of which $400 million terminates in December 2010 and $500 million terminates
in September 2011. Credit commitments totaling about $34 million from Lehman Brothers are no
longer available due to its September 2008 bankruptcy filing. The remaining $866 million is
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 of up to $583 million. At December
31, 2008, APS had borrowings of approximately $522 million and no letters of credit under its
revolving lines of credit. APS had no commercial paper outstanding as of December 31, 2008. In
general, the Company and APS have been unable to access the commercial paper markets since
September 2008. At December 31, 2008, APS had remaining capacity available under its revolvers of
$344 million and had cash and investments of approximately $72 million. At December 31, 2007, APS
had borrowings of $218 million under its $500 million line of credit and $4 million of letters of
credit issued under its $400 million line of credit. APS had no commercial paper outstanding at
December 31, 2007. The commitment fees for the $500 million line of credit were 0.10% at December
31, 2008 and December 31, 2007. The commitment fees for the $400 million line of credit were 0.11%
at December 31, 2008 and December 31, 2007. The weighted average interest rates were 2.09% at
December 31, 2008 and 5.36% at December 31, 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
(which is required to be used for purchases of natural gas and power) and (b) APS’ long-term debt authorization from
approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer
base and the resulting projected financing needs. This financing
order expires December 31, 2012; however, all debt previously
authorized and outstanding on December 31, 2012 will remain
authorized and valid obligations of APS.
SunCor had two revolving lines of credit totaling $170 million at December 31, 2008, and
December 31, 2007. The $150 million credit facility is secured and matures January 30, 2010 and the $20 million unsecured loan facility matured January 31, 2009. See Note 6 for
additional information on the secured credit facility. The unsecured loan facility includes approximately $5 million in borrowings.
SunCor is currently in the process of renegotiating this facility and, if unable to do so, will repay the amounts outstanding. At December 31, 2008 and December 31,
2007 Suncor had borrowings of $120 million and $85 million under the $150 million credit facility.
At December 31, 2008 and December 31, 2007 Suncor had borrowings of $5 million and $9 million under
the $20 million credit facility. The commitment fees ranged from 0.125% to 0.250% in 2008 and were
0.125% in 2007 for the $150 million line of credit. The commitment fees for the $20 million line
of credit were 0.50% in 2008 and 2007. The weighted-average interest rate was 4.11% at December
31, 2008 and 7.27% at December 31, 2007. Interest was based on LIBOR plus 2.0% for 2008 and 2007.
SunCor had other short-term borrowings of $5 million at December 31, 2008 and $8 million at
December 31, 2007. These loans are made up of multiple notes primarily with variable interest
rates based on LIBOR plus 2.5% at December 31, 2008 and 2007.
6. Long-Term Debt and Liquidity Matters
Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is
collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The
following table presents the components of long-term debt on the Consolida | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||