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15: EX-21.1 Subsidiaries of the Registrant HTML 11K
16: EX-23.1 Consent of Experts or Counsel HTML 11K
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18: EX-31.1 Certification per Sarbanes-Oxley Act (Section 302) HTML 16K
19: EX-31.2 Certification per Sarbanes-Oxley Act (Section 302) HTML 16K
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25: EX-99.30 Miscellaneous Exhibit HTML 19K
Securities registered pursuant to Section 12(b) of the Act:
Title Of Each Class
Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION
Common Stock,
New York Stock Exchange
No Par Value
Pacific Stock Exchange
ARIZONA PUBLIC SERVICE COMPANY
None
None
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 Noo
ARIZONA PUBLIC SERVICE COMPANY Yes o No þ
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 þ No o
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 Noo
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated
filer” in Rule 12b-2 of the Exchange Act.
PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o Accelerated filero Non-accelerated filer þ
Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act
Rule 12b-2). 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:
PINNACLE WEST CAPITAL
CORPORATION $4,359,721,018. as of June 30, 2005
ARIZONA PUBLIC SERVICE
COMPANY $0 as of June 30, 2005
The
number of shares outstanding of each registrant’s common stock
as of March 7, 2006
Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 17, 2006 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.
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
NPC – Nevada Power Company
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned 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, also known as ANPP
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company
PPL Sundance – PPL Sundance Energy, LLC
PRP – potentially responsible parties under the Superfund Act
PSA – power supply adjustor
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
PX – California Power Exchange
RFP – request for proposals
RTO – regional transmission organization
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
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
Sundance
Plant – 420 megawatt generating facility located approximately 55 miles southeast of
Phoenix, Arizona
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
Trading – energy-related activities entered into with the objective of generating profits on
changes in market prices
2004 Settlement Agreement – an agreement proposing terms under which APS’ general rate case was
settled, as approved by the ACC in 2005
VIE – variable-interest entity
WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission
lines in the southwestern United States
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:
•
Pinnacle West Consolidated—This section describes the financial condition and
results of operations of Pinnacle West and its subsidiaries on a consolidated basis.
It includes discussions of Pinnacle West’s regulated utility and non-utility
operations. A substantial part of Pinnacle West’s revenues and earnings are derived
from its regulated utility, APS.
•
APS—This section includes a detailed description of the results of operations and
contractual obligations of APS.
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 relate 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 significant subsidiaries are SunCor, which is engaged in real estate
development and investment activities, and APS Energy Services, which provides competitive energy
services and products in the western United States. 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 owns any generating plants and has ceased operations. Each of these
subsidiaries, and El Dorado Investment Company, another subsidiary,
are discussed in greater detail
below. See “Business of SunCor Development Company,” “Business of APS Energy Services
Company, Inc.,” “Business of Pinnacle West Energy Corporation,” and “Business of El Dorado
Investment Company,” in this Item 1.
Business Segments
Pinnacle West has three principal business segments (determined by products, services and the
regulatory environment):
•
the regulated electricity segment (75% of operating revenues in 2005), which
consists of traditional regulated retail and wholesale electricity businesses
(primarily electric service to Native Load customers) and related activities, and
includes electricity generation, transmission and distribution;
•
the real estate segment (11% of operating revenues in 2005), which consists of
SunCor’s real estate development and investment activities; and
•
the marketing and trading segment (12% of operating revenues in 2005), which
consists of competitive energy business activities, including wholesale marketing and
trading and APS Energy Services’ commodity-related energy services.
See Note 17 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for
financial information about the business segments.
APS Rate Proceedings
The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory
resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail
in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8, APS has pending
before the ACC a general retail rate case, an application for an emergency interim rate increase,
and an application for two separate surcharges under the PSA.
Employees
At December 31, 2005, Pinnacle West employed approximately 7,300 people, including the
employees of its subsidiaries. Of these employees, approximately 6,400 were employees of APS,
including employees at jointly-owned generating facilities (approximately 3,000 employees) for
which APS serves as the generating facility manager. Approximately 900 people were employed by
Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located
at 400 North Fifth Street, Phoenix, Arizona85004 (telephone 602-250-1000).
Available Information
Pinnacle West makes available free of charge on or through its internet site,
(www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are
electronically filed with, or furnished to, the SEC: its Annual Report on Form 10-K, its Quarterly
Reports on Form 10-Q, its Current Reports on Form 8-K and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934.
Pinnacle West also has a Corporate Governance webpage. You can access Pinnacle West’s
Corporate Governance webpage through its internet site, www.pinnaclewest.com, by clicking on the
“About Us” link to the heading “Corporate Commitments.” Pinnacle West posts the following on its
Corporate Governance webpage:
•
Corporate Governance Guidelines;
•
Board Committee Summary;
•
Charters for Pinnacle West’s Audit Committee, Corporate Governance Committee,
Finance and Operating Committee and Human Resources Committee;
•
Code of Ethics for Financial Professionals; and
•
Ethics Policy and Standards of Business Practices.
Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards
of Business Practices, and any waivers that are required to be disclosed by the rules of either the
SEC or the New York Stock Exchange, on its internet site. The information on Pinnacle West’s
internet site is not incorporated by reference into this report.
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at
the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068,
P.O. Box 53999, Phoenix, Arizona85072-3999 (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:
•
state and federal regulatory and legislative decisions and actions, including the
outcome and timing of APS’ retail rate proceedings pending before the ACC;
•
the timely recovery of PSA deferrals;
•
the ongoing restructuring of the electric industry, including the introduction of
retail electric competition in Arizona and decisions impacting wholesale competition;
•
the outcome of regulatory, legislative and judicial proceedings, both current and
future, relating to the restructuring;
•
market prices for electricity and natural gas;
•
power plant performance and outages;
•
transmission outages and constraints;
•
weather variations affecting local and regional customer energy usage;
•
customer growth and energy usage;
•
regional economic and market conditions, including the results of litigation and
other proceedings resulting from the California energy situation, volatile fuel and
purchased power costs and the completion of generation and transmission construction
in the region, which could affect customer growth and the cost of power supplies;
•
the cost of debt and equity capital and access to capital markets;
•
current credit ratings remaining in effect for any given period of time;
•
our ability to compete successfully outside traditional regulated markets (including
the wholesale market);
•
the performance of our marketing and trading activities due to volatile market
liquidity and any deteriorating counterparty credit and the use of derivative contracts
in our business (including the interpretation of the subjective and complex accounting
rules related to these contracts);
•
changes in accounting principles generally accepted in the United States of America
and the interpretation of those principles;
•
the performance of the stock market and the changing interest rate environment,
which affect the amount of required contributions to Pinnacle West’s pension plan and
APS’ nuclear decommissioning trust funds, as well as the reported costs of providing
pension and other postretirement benefits;
•
technological developments in the electric industry;
•
the strength of the real estate market in SunCor’s market areas, which include
Arizona, Idaho, New Mexico and Utah; and
•
other uncertainties, all of which are difficult to predict and many of which are
beyond the control of Pinnacle West and APS.
REGULATION AND COMPETITION
Retail
The ACC regulates APS’ retail electric rates and its 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 Pinnacle West, APS and their respective
affiliates.
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 unconstitutional, 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. In 2005, the Arizona Supreme
Court declined to review the Court of Appeals decision. To date, the ACC has taken no action on
either the rules or the orders authorizing competitive electric service providers in response to
the final Court of Appeals decision. As a result, 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.
APS is subject to varying degrees of competition from other investor-owned utilities in
Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as
cooperatives, municipalities, electrical districts and similar types of governmental or non-profit
organizations (principally Salt River Project). APS also faces competition from low-cost,
hydroelectric power and parties that have access to low-priced preferential, federal power and
other governmental subsidies. In addition, some customers, particularly industrial and large
commercial customers, may own and operate generation facilities to meet their own energy
requirements.
Wholesale
General
The FERC regulates rates for wholesale power sales and transmission services. During 2005,
approximately 5.3% of APS’ electric operating revenues resulted from such sales and services. APS’
marketing and trading division focuses primarily on managing APS’ fuel and purchased power risks in
connection with its costs of serving retail customer energy requirements. The division also sells,
in the wholesale market, APS’ 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, the marketing and trading division, subject to specified parameters, markets, hedges
and trades principally in electricity and fuels.
Regional Transmission Organizations
In a December 1999 order, the FERC established characteristics and functions that must be met
by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include
independence from market participants, operational control over a region large enough to support
efficient and non-discriminatory markets and exclusive authority to maintain short-term
reliability. On October 16, 2001, APS and other owners of electric transmission lines in the
southwestern U.S. filed with the FERC a request for a declaratory order confirming that their
proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an
RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if
modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic
framework for a standard market design for the southwestern United States. Since that time, APS
and other supporters of the WestConnect efforts have been evaluating a phased approach to RTO
implementation of regional structures in the desert Southwest.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
General
APS
was incorporated in 1920 under the laws of the state of Arizona and
currently has approximately 1,033,500 customers. APS does not distribute any products. During 2005, no single purchaser
or user of energy (other than Pinnacle West) accounted for more than 7.5% of electric revenues.
See “Overview – General” and “Regulation and Competition” above for additional background
information about APS’ business.
At December 31, 2005, APS employed approximately 6,400 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, Arizona85072-3999 (telephone 602-250-1000).
See “Properties – Capacity” in Item 2 for information about APS’ power plants by fuel types.
2005 Energy Mix
APS’ sources of energy during 2005 were: purchased power – 51.8%; coal – 26.3%; nuclear –
15.1%; and gas – 6.8%. In accordance with GAAP, a substantial portion of our purchased power
contracts was netted against wholesale sales contracts on the Statements of Income. See Note 18 of
Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
Coal Supply
Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a
jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from coal
suppliers that mine all of the coal under a long-term lease of coal reserves with the Navajo
Nation, the federal government and private landholders. 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.
Four Corners Four Corners is a coal-fired power plant located in the northwestern corner of
New Mexico. It is a jointly-owned facility operated by APS. 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 July 2016, with options to extend the contract for five
to fifteen additional years beyond the current plant site lease expiration in 2017.
Navajo Generating Station The Navajo Generating Station is a coal-fired power plant located
in northern Arizona. It is a jointly-owned facility operated by Salt River Project. 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 the current plant site lease expiration in
2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in
2019. Items that may impact the fuel price include lease provisions that allow for a
renegotiation of the coal royalty in 2007 and 2017 and a fuel contract requirement for a five-year
price review in 2007. In addition, the December 31, 2005 closure of the Mohave Generating Station
has not had a significant impact on the cost structure for the Black
Mesa – Kayenta Mine complex. APS does not have an ownership
interest in the Mohave Generating Station, but understands the plant
could be restarted. However, if
the Mohave Generating Station is permanently closed, there is a potential for increased costs to
the Navajo Generating Station, which is served by the Kayenta Mine. APS does not currently expect
this matter to have a material adverse effect on its financial position, results of operations,
cash flows or liquidity.
See “Legal Proceedings” in Item 3 for information about a lawsuit relating to royalties for
coal paid by the participants at the Navajo Generating Station.
See “Properties – Capacity” in Item 2 for information about APS’ ownership interests in
Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Pinnacle West’s
Consolidated Financial Statements in Item 8 for information regarding APS’ coal mine
reclamation obligations.
Natural Gas Supply
See Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a
discussion of APS’ natural gas supply.
Nuclear Fuel Supply
Palo Verde Fuel Cycle Palo Verde is a nuclear power plant located about 50 miles west of
Phoenix, Arizona. It is a jointly-owned facility operated by APS. The fuel cycle for Palo Verde
is comprised of the following stages:
•
mining and milling of uranium ore to produce uranium concentrates;
•
conversion of uranium concentrates to uranium hexafluoride;
•
enrichment of uranium hexafluoride;
•
fabrication of fuel assemblies;
•
utilization of fuel assemblies in reactors; and
•
storage and disposal of spent nuclear fuel.
The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium
concentrates and conversion services through 2008. The Palo Verde participants have also
contracted for all of Palo Verde’s enrichment services through 2010, 80% of 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
of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of spent
nuclear fuel and waste disposal.
Purchased Power
In addition to its own available generating capacity (see “Properties” in Item 2), APS
purchases electricity under various arrangements. One of the most important of these is a
long-term contract with Salt River Project. The amount of electricity available to APS is based in
large part on customer demand within certain areas now served by APS pursuant to a related
territorial agreement. The generating capacity available to APS pursuant to the contract is 350
MW. In 2005, APS received 552,014 MWh of energy under the contract and paid about $66.6 million
for capacity availability and energy received. This contract may be canceled by Salt River Project
on three years’ notice. By letter dated June 7, 2004, Salt River Project gave notice to APS to
reduce capacity by 150 MW effective June 16, 2007. To date, this letter is the only notice Salt
River Project has given under the contract. APS may also cancel the contract on five years’
notice, which may be given no earlier than December 31, 2006.
In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with
PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak
season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter
season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW
of capacity and a related amount of energy available to it under the agreement for its
respective seasons. In 2005, APS received 571,492 MWh of energy under the capacity exchange. APS
must also make additional offers of energy to PacifiCorp each year through October 31, 2020.
Pursuant to this requirement, during 2005, PacifiCorp received offers of 1,090,700 MWh and
purchased 372,473 MWh.
APS continually assesses its need for additional capacity resources to assure system
reliability. Under the terms of the 2004 Settlement Agreement, APS committed to seek proposals
from the competitive wholesale market for filling its future resource needs. The current
reliability RFP identifies the amount of capacity and energy needed to reliably meet expected
customer demands and sought proposals for at least 1,000 MW of new generating capacity for 2007 and
beyond. APS has entered into contracts for more than 650 MW of capacity and expects to finalize
the remaining contract by the end of the first quarter of 2006.
APS also has a renewable RFP seeking at least 100 MW of renewable capacity with a capability
of producing at least 250,000 MWh annually. In accordance with the terms of the 2004 Settlement
Agreement, power must be deliverable to the APS transmission system and its pricing must not exceed
125% of conventional resource alternatives. During 2005, APS conducted a competitive procurement
process for renewable energy resources. The process resulted in the acquisition of approximately
145 MW of renewable energy resources via purchased power agreements. At an ACC Open Meeting on
November 8, 2005, the ACC approved APS’ acquisition of out-of-state renewable resources. The ACC
also ordered APS to work with the ACC staff to evaluate two in-state projects and report back
within two months. APS has completed this evaluation process and has filed a report with the ACC.
The ACC agreed with APS’ evaluation that the in-state projects were not economical.
Construction Program
During the years 2003 through 2005, APS incurred approximately $1.7 billion in capital
expenditures. APS’ capital expenditures for the years 2006 through 2008 are expected to be
primarily for expanding transmission and distribution capabilities to meet growing customer needs,
for upgrading existing utility property and for environmental purposes. APS’ capital expenditures
were approximately $809 million in 2005. APS’ capital expenditures, including expenditures for
environmental control facilities, for the years 2006 through 2008, net of contributions in aid of
construction, have been estimated as follows (dollars in millions):
Estimate
Major facilities:
2006
2007
2008
Distribution
$
322
$
323
$
362
Transmission
120
169
203
Generation
184
207
279
Other
23
16
13
Total
$
649
$
715
$
857
The above amounts exclude capitalized interest costs and include capitalized property taxes
and approximately $35 million per year for nuclear fuel. APS conducts a continuing review of its
construction program.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Capital Needs and Resources by Company” in Item 7 for additional information about APS’
construction programs.
Environmental Matters
EPA Environmental Regulation
Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These
regulations require states to submit state implementation plans by 2008 to make reasonable progress
towards achieving natural visibility conditions in certain specified areas, including Class I Areas
in the Colorado Plateau, and to consider and potentially apply the best available retrofit
technology (“BART”) for major stationary sources.
The rules allow nine western states and tribes to follow an alternate implementation plan and
schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
Five western states, including Arizona, have submitted proposed state implementation plans to the
EPA to implement the Annex Rule.
On February 18, 2005, the U.S. Court of Appeals for the District of Columbia granted a
petition for review of the Annex Rule, filed by the Center for Energy and Economic Development
(CEED). APS, Phelps Dodge Corporation, and the Environmental Defense were intervenors in the
litigation in support of the EPA and the Annex Rule. Although the Court concluded that the EPA has
the authority to promulgate a BART alternative, the Court ruled that the EPA must first conduct a
BART analysis of eligible sources to demonstrate that the alternate plan would achieve greater
emissions reductions than BART. On June 15, 2005, 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. On August 1, 2005, the EPA proposed a rule to, among other things, reconcile
the Annex Rule with the CEED decision. We are currently evaluating the impact of this proposed
rule. The Company cannot currently predict the outcome of this matter.
Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule to regulate 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 trading
program. Under the trading program, the EPA has assigned each state a “budget” for reducing
coal-fired power plant mercury emissions, and each state must submit to the EPA a plan detailing
how it will meet its “budget.” In the first phase of the program, beginning in 2010, mercury
emissions will be reduced from a total of 48 tons per year to 38 tons. In 2018, mercury emissions
will be further reduced to 15 tons. APS is currently evaluating the potential impact of this rule
and, as a result, cannot currently estimate the expenditures which may be required.
By November 2006, the ADEQ will submit a state implementation plan to the EPA to implement the
Clean Air Mercury Rule or an alternative mercury program, as authorized by the EPA. The mercury
program for Four Corners will be implemented by EPA Region IX or, if it seeks and
obtains program approval, by the Navajo Nation. APS is still evaluating the potential impacts of the
state implementation plan on Cholla and of the Clean Air Mercury Rule on Cholla and Four Corners
and cannot currently estimate the expenditures which may be required.
Federal Implementation Plan In September 1999, the EPA proposed a FIP to set air quality
standards at certain power plants, including the Navajo Generating Station and Four Corners. The
FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico
regulation of Four Corners, with minor modifications. APS does not currently expect the FIP to
have a material adverse effect on its financial position, results of operations, cash flows or
liquidity.
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, neither APS nor Pinnacle West can currently
estimate the expenditures which may be required.
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.
APS is the Four Corners operating agent. APS owns all of Four Corners Units 1, 2 and 3, and a 15%
interest in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station Units
1, 2 and 3.
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
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 and the Navajo Nation executed a Voluntary Compliance
Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention
and Control Act. The fundamental premise of the VCA is that the Navajo Nation EPA may regulate air
issues for Four Corners and the Navajo Generating Station only because the participants have agreed
to submit to such regulation for the term of the agreement and under certain circumstances. If the
EPA approves the Navajo Nation’s air programs consistent with
the VCA, APS would seek dismissal of the
pending litigation in the Navajo Nation Supreme Court and the pending litigation in
the Navajo Nation District Court to the extent the claims relate to the Clean Air Act. The
agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot
currently predict the outcome of this matter.
West Phoenix Power Plant
During the period from November 2004 through March 2005, the Maricopa County Air Quality
Department (“MCAQD”) issued a series of Notices of Violation (“NOVs”) to APS’ West Phoenix Power
Plant that generally allege that the plant failed to comply with applicable permit requirements.
APS is currently engaged in discussions with MCAQD concerning the NOVs. We do not expect the
resolution of these matters to have a material adverse effect on our financial position, results of
operations, or cash flows.
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 before a state 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 Palo Verde participants to the use
of groundwater and effluent at Palo Verde are potentially at issue in this action. As project
manager of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde
participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde.
Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also
located within the geographic area subject to the summons. APS’ claims dispute the court’s
jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks
confirmation of such
rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain
groundwater rights may be available to the federal government and Indian tribes. In addition, in
September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria
for resolving groundwater claims. Litigation on both of these issues has continued in the trial
court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court
requesting
interlocutory review of a September 2005 trial court order regarding procedures for
determining whether groundwater pumping is affecting surface water rights. The Court has not yet
ruled on the petition. 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. APS’ groundwater resource utilized
at Cholla is within the geographic area subject to the adjudication and is therefore 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, neither APS nor Pinnacle West
expects 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 operations of the plant for 2006 and later
years. 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.
Federal Energy Legislation
On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. The Company
does not expect the Act to materially affect its operations.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of the State 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, Arizona85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 700
employees at December 31, 2005.
At December 31, 2005, SunCor had total assets of about $487 million. SunCor’s assets consist
primarily of land with improvements, commercial buildings, golf courses and other real estate
investments. SunCor intends to continue its focus on real estate development of master-planned
communities, mixed-use residential, commercial, office and industrial projects. During the past
several years, SunCor has focused its business strategy on real estate development and investment
activities.
SunCor projects under development include five master-planned communities and several
commercial and residential projects. The commercial and residential projects and two of the
master-planned communities are in Arizona. Other master-planned communities are located near St.
George, Utah, Boise, Idaho and Santa Fe, New Mexico.
SunCor’s operating revenues were approximately $338 million in 2005, $350 million in 2004 and
$362 million in 2003. SunCor’s net income was approximately $56 million in 2005, $45 million in
2004 and $56 million in 2003. 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 Note 22 of Notes to Pinnacle West’s
Consolidated Financial Statements in Item 8.
See Note 6 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for
information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7
for a discussion of SunCor’s capital requirements.
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and was
formerly engaged principally in the operation of unregulated generating plants. Pinnacle West
Energy had approximately 30 employees as of December 31, 2005. Pinnacle West Energy’s principal
offices are located at 400 North Fifth Street, Phoenix, Arizona85004 (telephone 602-250-4145).
Pinnacle West Energy transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold
its 75% interest in Silverhawk to NPC on January 10, 2006. As a result Pinnacle West Energy no
longer owns any generating plants and has ceased operations. At December 31, 2005, Pinnacle West
Energy had total assets of $217 million, substantially all of which were assets held for sale
related to Silverhawk.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and
provides competitive commodity-related energy services (such as direct access commodity contracts,
energy procurement and energy supply consultation) and energy-related products and services (such
as energy master planning, energy use consultation and facility audits, cogeneration analysis and
installation and project management) to commercial, industrial and institutional retail customers
in the western United States. APS Energy Services had approximately 80 employees as of December31, 2005. APS Energy Services’ principal offices are located at 400 East Van Buren Street,
Phoenix, Arizona85004 (telephone 602-250-5000).
APS Energy Services had a net loss of $6 million in 2005, and net income of $3 million in 2004
and $16 million in 2003. At December 31, 2005, APS Energy Services had total assets of $88
million.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State 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, Arizona85004 (telephone 602-250-3517).
El Dorado had pretax income of $4 million in 2005, $40 million in 2004 and $7 million in 2003.
Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2005, El Dorado
had total assets of $38 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.
We are subject to comprehensive government regulation by several federal, state and local
regulatory agencies that significantly affect our business and our results of operations.
APS is subject to comprehensive regulation by several federal, state and local regulatory
agencies that significantly influence its business and results of operations. The ACC regulates
APS’ retail electric rates and APS’ issuance of securities. The ACC must also approve any transfer
of APS’ property used to provide retail electric service and approve or receive prior notification
of certain transactions between us, APS and our respective affiliates. Our financial condition and
results of operations are dependent upon the satisfactory resolution of APS’ retail rate
proceedings pending before the ACC. See Note 3 of Notes to Pinnacle West’s Consolidated Financial
Statements in Item 8.
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. 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.
We cannot predict the outcome of APS’ retail rate proceedings pending before the ACC.
As noted above, our financial condition and results of operations are dependent upon the
satisfactory resolution of APS’ retail rate proceedings pending before the ACC. These proceedings
consist of a general retail rate case, an application for an emergency interim rate increase, and
an application for two separate surcharges under the PSA. See Note 3 of Notes to Pinnacle West’s
Consolidated Financial Statements in Item 8. We cannot predict the timing or the outcome of these
proceedings or the resulting levels of regulated revenues.
We are subject to numerous environmental laws and regulations that may increase our cost of
operations, impact our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our
present and future operations, including air emissions, water quality, wastewater discharges, solid
waste, and hazardous waste. These laws and regulations can result in increased capital, operating,
and other costs, particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and comply with a wide
variety of environmental licenses, permits, inspections and other approvals. 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 are not fully recoverable from APS’ customers, could have
a material adverse effect on our financial position, results of operations or cash flows.
There are inherent risks in the operation of nuclear facilities, such as environmental, health
and financial risks and the risk of terrorist attack.
Through APS, we have an ownership interest in and operate, on behalf of a group of owners,
Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo
Verde is subject to environmental, health and financial risks such as the ability to dispose of
spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential
liabilities arising out of the operation of these facilities, and the costs of securing the
facilities against possible terrorist attacks and unscheduled outages due to equipment and other
problems. We maintain nuclear decommissioning trust funds and external insurance coverage to
minimize our 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 fines or shut down a unit, or both, depending upon its
assessment of the severity of the situation, until compliance is achieved. In addition, although
we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur,
it could materially and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the
operation or licensing of any domestic nuclear unit.
Deregulation or restructuring of the electric industry may result in increased competition,
which could have a significant adverse impact on our business and our financial results.
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. Retail competition could have a significant adverse financial impact on us 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 the service area of APS 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 our load forecasts, plans for power supply and
wholesale energy sales and related revenues. As a result of the changing regulatory environment
and the relatively low barriers to entry, we expect wholesale competition to increase.
Our results of operations can be adversely affected by milder weather.
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, we
have historically sold less power, and consequently earned less income, when weather conditions are
milder. As a result, unusually mild weather could diminish our results of operations and harm our
financial condition.
Our cash flow largely depends on the performance of our subsidiaries.
We conduct our operations primarily through subsidiaries. Substantially all of our
consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon
the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries
are separate and distinct legal entities and have no obligation to make distributions to us.
The debt agreements of some of our subsidiaries may restrict their ability to pay dividends,
make distributions or otherwise transfer funds to us. An ACC financing order requires APS to
indefinitely 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. As defined in the
ACC financing order approving the arrangement, common equity ratio is common equity divided by
common equity plus long-term debt, including current maturities of long-term debt. At December 31,2005, APS’ common equity ratio, as defined, was approximately 54%.
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.
If we are not able to access capital at competitive rates, our ability to implement our
financial strategy will be adversely affected.
We rely on access to short-term money markets, longer-term capital markets and the bank
markets as a significant source of liquidity and for capital requirements not satisfied by the cash
flow from our operations. We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings. However, certain market disruptions may increase our
cost of borrowing or adversely affect our ability to access one or more financial markets. Such
disruptions could include:
•
an economic downturn;
•
the bankruptcy of an unrelated energy company;
•
increased market prices for electricity and gas;
•
terrorist attacks or threatened attacks on our facilities or those of unrelated
energy companies; or
•
the overall health of the utility industry.
Changes in economic conditions could result in higher interest rates, which would increase our
interest expense on our debt and reduce funds available to us for our current plans. Additionally,
an increase in our leverage could adversely affect us by:
•
increasing the cost of future debt financing;
•
increasing our vulnerability to adverse economic and industry conditions;
•
requiring us to dedicate a substantial portion of our cash flow from operations to
payments on our debt, which would reduce funds available to us for operations, future
business opportunities or other purposes; and
•
placing us at a competitive disadvantage compared to our competitors that have less
debt.
A further reduction in our credit ratings could materially and adversely affect our business,
financial condition and results of operations.
We cannot be sure that any of our current ratings will remain in effect for any given period
of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its
judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing
costs, which would diminish our financial results. We would likely be required to pay a higher
interest rate in future financings, and our potential pool of investors and funding sources could
decrease. In addition, borrowing costs under certain of our existing credit facilities depend on
our credit ratings. A downgrade could also require us to provide additional support in the form of
letters of credit or cash or other collateral to various counterparties. If our short-term ratings
were to be lowered, it could limit our access to the commercial paper market. We note that the
ratings from rating agencies are not recommendations to buy, sell or hold our securities and that
each rating should be evaluated independently of any other rating.
The use of derivative contracts in the normal course of our business and changing interest
rates and market conditions could result in financial losses that negatively impact our results of
operations.
Our operations include managing market risks related to commodity prices and, subject to
specified risk parameters, engaging in marketing and trading activities intended to profit from
market price movements. We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions allowances. We have
established procedures to manage risks associated with these market fluctuations by utilizing
various commodity derivatives, including exchange-traded futures and options and over-the-counter
forwards, options, and swaps. As part of our overall risk management program, we enter into
derivative transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a high correlation to
price changes in the hedged commodity.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
use a risk management process to assess and monitor the financial exposure of all counterparties.
Despite the fact that the majority of trading counterparties are rated as investment grade by the
rating agencies, there is still a possibility that one or more of these companies could default,
resulting in a material adverse impact on our earnings for a given period.
Changing
interest rates will affect interest paid on variable-rate debt and
interest earned on variable-rate securities in
our pension 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 is also
impacted by the discount rate, which is the interest rate used to discount future pension
obligations. Declining interest rates impact the discount rate, and may result in increases in
pension costs, cash contributions, and charges to other comprehensive income. The pension plan and
nuclear decommissioning trust funds also have risks associated with changing market values of fixed
income and equity investments. A significant portion of the pension costs and all of the nuclear
decommissioning costs are recovered in regulated electricity prices.
Actual results could differ from estimates used to prepare our financial statements.
In preparing our financial statements in accordance with accounting principles generally
accepted in the United States of America, management must often make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues, expenses and related
disclosures at the date of the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from those estimates. We
consider the following accounting policies to be our most critical because of the uncertainties,
judgments and complexities of the underlying accounting standards and operations involved.
•
Regulatory Accounting — Regulatory accounting allows for the actions of regulators,
such as the ACC and the FERC, to be reflected in our financial statements. Their
actions may cause us to capitalize costs that would otherwise be included as an expense
in the current period by unregulated companies. If future recovery of costs ceases to
be probable, the assets would be written off as a charge in current
period earnings. A major component of our regulatory assets is the retail fuel and purchased power costs
deferred under the PSA. APS defers for future rate recovery 90% of the difference
between actual retail fuel and purchased power costs and the amount of such costs
currently included in base rates. We had $324 million, including $173 million related
to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31,2005. Included in the $173 million is approximately $45 million related to the 2005
unplanned Palo Verde outages, which currently are the subject of inquiry by the ACC.
Since December 25, 2005, Palo Verde Unit 1 has been operating at reduced power levels
due to a non-safety related acoustic impact in one of the unit’s shutdown cooling
lines. Unit 1 is currently operating at approximately
25% power. APS estimates that these reduced power levels and a
planned Unit 1 outage to resolve the Unit 1 issue will
result in additional PSA deferrals of approximately $85 million
pretax in
2006. See Notes 1 and 3 for more information about
regulatory assets and liabilities, APS’ pending retail rate proceedings, and the PSA.
•
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.
•
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, will determine whether we use accrual accounting (for contracts
designated as normal) or fair value (mark-to-market) accounting. Mark-to-market
accounting requires that changes in the fair value are recognized periodically in
income unless certain hedge criteria are met. For fair value hedges, the gain or loss
on the derivative as well as the offsetting loss or gain on the hedged item associated
with the hedged risk are recognized in earnings. For cash flow hedges, the effective
portion of changes in the fair value of the derivative are recognized in common stock
equity (as a component of other comprehensive income (loss)) and are recognized in
earnings when the related transaction occurs.
The market price of our common stock may be volatile.
The market price of our common stock could be subject to significant fluctuations in response
to factors such as the following, some of which are beyond our control:
•
variations in our quarterly operating results;
•
operating results that vary from the expectations of management, securities analysts
and investors;
•
changes in expectations as to our future financial performance, including financial
estimates by securities analysts and investors;
•
developments generally affecting industries in which we operate, particularly the
energy distribution and energy generation industries;
•
announcements by us or our competitors of significant contracts, acquisitions, joint
marketing relationships, joint ventures or capital commitments;
•
announcements by third parties of significant claims or proceedings against us;
•
favorable or adverse regulatory developments;
•
our dividend policy;
•
future sale of our equity or equity-linked securities; and
•
general domestic and international economic conditions.
In addition, the stock market in general has experienced volatility that has often been
unrelated to the operating performance of a particular company. These broad market fluctuations
may adversely affect the market price of our common stock.
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. At December 31, 2005, there were no material restrictions on
our ability to pay dividends under any such agreement.
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 2005 fiscal
year and that remain unresolved.
APS’ present generating facilities have capacities as follows:
Capacity (kW)
Coal:
Units 1, 2 and 3 at Four Corners
560,000
15% owned Units 4 and 5 at Four Corners
222,000
Units 1, 2 and 3 at Cholla
615,000
14% owned Units 1, 2 and 3 at the Navajo Generating Station
315,000
Subtotal
1,712,000
Gas or Oil:1
Two steam units at Ocotillo and two steam units at Saguaro
430,000
Twenty-two combustion turbine units
993,000
Seven combined cycle units
1,965,000
Subtotal
3,388,000
Nuclear:
29.1% owned or leased Units 1, 2, and 3 at Palo Verde
1,107,000
Solar
5,715
Total
6,212,715
1
APS purchased a ten-unit (42,000 kW each) combustion turbine site (Sundance) on
May 15, 2005.
Reserve Margin
APS’ 2005 peak one-hour demand on its electric system was recorded on July 18, 2005 at
6,999,600 kW, compared with the 2004 peak of 6,402,100 kW recorded on August 11, 2004. 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 July 18, 2005, amounted to
6,383,000 kW, for an installed reserve margin of negative 13.3%. The power actually available to
APS from its resources fluctuates from time to time due in part to planned and unplanned plant and
transmission outages and technical problems. The available capacity from sources actually operable
at the time of the 2005 peak amounted to 3,820,000 kW, for a margin
of a negative 51.4%. Firm
purchases totaling 4,653,000 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 19.3%.
See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel –
Purchased Power” in Item 1 for information about certain of APS’ long-term power agreements.
The Navajo Generating Station and Four Corners are located on land held under easements from
the federal government and also under leases from the Navajo Nation. These are long-term
agreements with options to extend, and APS does not believe that the risks with respect to
enforcement of these easements and leases are material. The majority of coal contracted for use in
these plants and certain associated transmission lines are also located on Indian reservations.
See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Coal
Supply” in Item 1.
Palo Verde Nuclear Generating Station
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.
In 2004, the NRC determined that there had been a safety concern with Palo Verde’s procedures
related to safety injection system piping. This led to a “yellow” finding under the NRC’s
inspection criteria and put Palo Verde in the “degraded safety cornerstone” column of the NRC’s
performance matrix, resulting in a supplemental NRC inspection. The NRC completed its supplemental inspection
during 2005 and issued its report, closing one finding and indicating
it would follow
up on another finding at some later time upon notice from APS.
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, including costs for low income
programs, demand side management, consumer education, environmental, renewables, etc.
“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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for
additional information about APS’ nuclear decommissioning costs.
See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s
Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the
Palo Verde participants, including APS, for Palo Verde.
Property Not Held in Fee or Subject to Encumbrances
Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other
companies. The following table shows APS’ interests in those jointly-owned facilities recorded on
the Consolidated Balance Sheets at December 31, 2005:
Percent Owned
Generating facilities (a):
Palo Verde Units 1 and 3
29.1
%
Palo Verde Unit 2 (see “Palo Verde Leases”
below)
17.0
%
Four Corners Units 4 and 5
15.0
%
Navajo Generating Station Units 1, 2, and 3
14.0
%
Cholla common facilities (b)
62.6
%(c)
Transmission facilities:
ANPP 500KV System
35.8
%(c)
Navajo Southern System
31.4
%(c)
Palo Verde – Yuma 500KV System
23.9
%(c)
Four Corners Switchyards
27.5
%(c)
Phoenix – Mead System
17.1
%(c)
Palo Verde – Estrella 500KV System
55.5
%(c)
Harquahala
80.0
%(c)
(a)
This table does not reflect Pinnacle West Energy’s 75% interest in Silverhawk at December 31,2005. Pinnacle West Energy sold this interest to NPC on January 10, 2006.
(b)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common
facilities at Cholla are jointly-owned.
(c)
Weighted-average of interests.
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 and to purchase the property for fair market value at the end of the lease terms. See Notes
9 and 20 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional
information regarding the Palo Verde Unit 2 sale leaseback transactions.
APS’ transmission facilities consist of approximately 5,613 pole miles of overhead lines and
approximately 42 miles of underground lines, 5,457 miles of which are located within the State of
Arizona. APS’ distribution facilities consist of approximately 12,262 pole miles of overhead lines
and approximately 14,430 miles of underground lines, all of which are located within the State of
Arizona.
Other Information Regarding Our 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 — Overview” in Item 7 for a
discussion of issues relating to Palo Verde Unit 1.
See “Business of Arizona Public Service Company – Construction Program” in Item 1 and
“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity
and Capital Resources” in Item 7 for a discussion of APS’ construction program.
Information Regarding SunCor’s 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.
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 11 of Notes to the Pinnacle West Consolidated Financial Statements in Item 8 with
regard to a lawsuit against APS and the other Navajo Generating Station participants and for
information relating to the FERC proceedings on California energy market issues.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Executive Vice President,
Generation, APS and
President, Pinnacle West
Energy
Nancy C. Loftin
52
Vice President, General
Counsel and Secretary
Donald G. Robinson
52
Vice President, Planning, APS
Steven M. Wheeler
57
Executive Vice President,
Customer Service and
Regulation, APS
(1)
Member of the Board of Directors.
The executive officers of Pinnacle West are elected no less often than annually and may be
removed by the Board of Directors at any time. The terms served by the named officers in their
current positions and their principal occupations (in addition to those stated in the table) of such
officers for the past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive
Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the
following capacities: from August 1999 to February 2001 as President; from February 1997 to
February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr.
Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from
February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until
October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge
Corporation.
Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective
September 2003. Prior to that time he was Chief Operating Officer and Executive Vice President of
Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of
APS (September 1996 – October 1998). Mr. Davis is also President of APS (since October 1998) and
Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West
Energy.
Mr. Brandt was elected to his present position in September 2003 and was Senior Vice President
and Chief Financial Officer (December 2002 – September 2003). Prior to that time, he was Senior
Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services
company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in
September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003
– September 2003).
Mr. Flores was elected to his present position in September 2003. Prior to that time, he was
Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September
2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 –
July 1999).
Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was
Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle
West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).
Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was
Treasurer (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.
Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief
Executive Officer of Pinnacle West Energy in January 2003. Prior to that time, he was Senior Vice
President, Nuclear Generation of APS (September 1996 – July 1999).
Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in
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 in September 2003. Prior to that time, he
was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President,
Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting,
Regulation and Planning of Pinnacle West (prior to June 2001).
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). Prior to that time he was a partner with Snell & Wilmer L.L.P.
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 and Pacific Stock
Exchanges. At the close of business on March 7, 2006, Pinnacle West’s common stock was held of
record by approximately 32,846 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW
Dividends
2005
High
Low
Close
Per Share
1st Quarter
$
44.87
$
40.99
$
42.51
$
0.475
2nd Quarter
45.34
41.29
44.45
0.475
3rd Quarter
46.68
43.13
44.08
0.475
4th Quarter
44.97
39.81
41.35
0.500
Dividends
2004
High
Low
Close
Per Share
1st Quarter
$
40.81
$
36.90
$
39.35
$
0.450
2nd Quarter
41.50
36.30
40.39
0.450
3rd Quarter
42.99
39.63
41.50
0.450
4th Quarter
45.84
41.61
44.41
0.475
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 declared on APS’ common stock for each of the four
quarters for 2005 and 2004.
Common Stock Dividends
(Dollars in Thousands)
Quarter
2005
2004
1st Quarter
$
42,500
$
42,500
2nd Quarter
—
42,500
3rd Quarter
—
42,500
4th Quarter
127,500
42,500
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, 2005, APS did not have any
outstanding preferred stock.
Pinnacle West did not purchase any of its common stock during the fourth quarter of 2005.
PINNACLE WEST CAPITAL CORPORATION
SELECTED CONSOLIDATED FINANCIAL DATA
2005
2004
2003
2002
2001
(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity segment
$
2,237,145
$
2,035,247
$
1,978,075
$
1,890,391
$
1,984,305
Marketing and trading segment (a)
351,558
400,628
391,196
286,879
469,784
Real estate segment (a)
338,031
350,315
361,604
201,081
168,908
Other revenues
61,221
42,816
27,929
26,899
11,771
Total operating revenues
$
2,987,955
$
2,829,006
$
2,758,804
$
2,405,250
$
2,634,768
Income from continuing operations (b)
223,163
246,590
225,384
236,563
327,367
Discontinued operations – net of income
taxes (c)
(46,896
)
(3,395
)
15,195
(21,410
)
—
Cumulative effect of change in accounting
– net of income taxes (d) (e)
—
—
—
(65,745
)
(15,201
)
Net income
$
176,267
$
243,195
$
240,579
$
149,408
$
312,166
COMMON STOCK DATA
Book value per share – year-end
$
34.58
$
32.14
$
30.97
$
29.40
$
29.46
Earnings (loss) per weighted average
common share outstanding:
Continuing operations – basic
$
2.31
$
2.70
$
2.47
$
2.79
$
3.86
Discontinued operations (c)
(0.48
)
(0.04
)
0.17
(0.26
)
—
Cumulative effect of change
in accounting (d) (e)
—
—
—
(0.77
)
(0.18
)
Net income – basic
$
1.83
$
2.66
$
2.64
$
1.76
$
3.68
Continuing operations – diluted
$
2.31
$
2.69
$
2.47
$
2.78
$
3.85
Net income – diluted
$
1.82
$
2.66
$
2.63
$
1.76
$
3.68
Dividends declared per share
$
1.925
$
1.825
$
1.725
$
1.625
$
1.525
Indicated annual dividend rate
per share – year-end
$
2.00
$
1.90
$
1.80
$
1.70
$
1.60
Weighted-average common shares
outstanding – basic
96,483,781
91,396,904
91,264,696
84,902,946
84,717,649
Weighted-average common shares
outstanding – diluted
96,589,949
91,532,473
91,405,134
84,963,921
84,930,140
BALANCE SHEET DATA
Total assets
$
11,322,645
$
9,896,747
$
9,519,042
$
9,139,157
$
8,529,124
Liabilities and equity:
Long-term debt less current maturities
$
2,608,455
$
2,584,985
$
2,616,585
$
2,743,741
$
2,673,078
Other liabilities
5,289,226
4,361,566
4,072,678
3,709,263
3,356,723
Total liabilities
7,897,681
6,946,551
6,689,263
6,453,004
6,029,801
Common stock equity
3,424,964
2,950,196
2,829,779
2,686,153
2,499,323
Total liabilities and equity
$
11,322,645
$
9,896,747
$
9,519,042
$
9,139,157
$
8,529,124
(a)
Includes reclassifications of revenue in 2004 and 2003 related to items accounted for as
discontinued operations of SunCor and Silverhawk. See Note 22 of Notes to Pinnacle West’s
Consolidated Financial Statements in Item 8.
(b)
Includes regulatory disallowance of $84 million after tax in 2005. See Note 3 of Notes to
Pinnacle West’s Consolidated Financial Statements in Item 8.
(c)
Amounts related to Silverhawk, SunCor and NAC discontinued operations. Prior year amounts
have been reclassified to discontinued operations to conform to current year presentation.
See Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
(d)
Represents change in accounting standards related to energy trading activities in 2002.
(e)
Represents change in accounting standards related to derivatives in 2001.
The following discussion should be read in conjunction with Pinnacle West’s Consolidated
Financial Statements and Arizona Public Service Company’s Financial Statements and the related
Notes that appear in Item 8 of this report.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated
electric utility that provides retail and wholesale electric service to most of the state of
Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson
metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a
substantial part of our revenues and earnings, and is expected to continue to do so. Customer
growth in APS’ service territory is about three times the national average and remains a
fundamental driver of our revenues and earnings.
The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and
APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending
before the ACC. As discussed in greater detail in Note 3, APS has pending before the ACC:
•
a general retail rate case pursuant to which APS is requesting a 21.3%, or $453.9
million, increase in its annual retail electricity revenues effective no later than
December 31, 2006;
•
an application for an emergency interim rate increase of $299 million, or
approximately 14%, to be effective April 1, 2006 (the increase would accelerate
recovery of the fuel and purchased power component of APS’ general rate case and is not
an additional increase and would be subject to refund); and
•
an application for a temporary rate increase of approximately 2.6%, through two
separate PSA surcharges, to recover $59.9 million in retail fuel and purchased power
costs deferred by APS in 2005 under the PSA.
APS has been operating Palo Verde Unit 1 at reduced power levels since December 25, 2005 due
to a non-safety related acoustic impact in one of the unit’s shutdown cooling lines. Unit 1 is
currently operating at approximately 25% power. APS has concluded
after comprehensive analysis that the preferred solution will require
Unit 1 to undergo an outage of approximately five weeks in order
for APS to effect the necessary modifications to the Unit. APS
anticipates that Unit 1 will begin this outage in the June
timeframe. In addition, an outage for preparatory work of
approximately one week, beginning March 18, 2006, will take
place prior to this outage. This preferred solution was initially
planned for installation in the spring of 2007. APS
estimates that, through February 28, 2006, Unit 1’s reduced
power level has resulted in incremental replacement power costs of
approximately $20 million after income taxes, approximately
$18 million of which has been incurred since January 1,2006. Based on current forward market energy prices, APS estimates
that (a) operating Unit 1 at reduced power levels until the
assumed outage in the June timeframe will result in additional
incremental replacement power costs of approximately $25 million
after income taxes and (b) the June Unit 1 outage will result in
additional incremental replacement power costs of approximately
$15 million after income taxes. APS estimates that these reduced
power levels and the June Unit 1 outage will result in
additional PSA deferrals of $50 million after tax
($85 million pretax) in 2006. See “Deferred Fuel and Purchased Power Costs” below.
SunCor, our real estate development subsidiary, has been and is expected to be an important
source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive
commodity-related energy services and energy-related products and services to commercial and
industrial retail customers in the western United States. El Dorado, our investment subsidiary,
owns minority interests in several energy-related investments and Arizona community-based ventures.
Pinnacle West Energy is our subsidiary that previously owned and operated unregulated
generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29,2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case”
in Note 3. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006.
As a result Pinnacle West Energy no longer owns any generating plants and has ceased operations.
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 resources and our transmission and distribution systems
to meet the electricity needs of our growing retail customers and sustain reliability.
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a
discussion of several factors that could affect our future financial results.
PINNACLE WEST CONSOLIDATED –
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
We have three principal business segments (determined by products, services and the regulatory
environment):
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electric service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution;
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities; and
•
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services’
commodity-related energy services.
The following table summarizes net income for 2005, 2004 and 2003 (dollars in millions):
2005
2004
2003
Regulated electricity
$
167
$
152
$
170
Real estate
35
40
45
Marketing and trading
16
29
8
Other (a)
5
26
2
Income from continuing operations
223
247
225
Discontinued operations – net of tax:
Real estate (b)
17
4
10
Marketing and trading (c)
(67
)
(12
)
1
Other (d)
3
4
5
Net income
$
176
$
243
$
241
(a)
Includes a $21 million after-tax gain in 2004 related to the sale of a limited
partnership interest in the Phoenix Suns.
(b)
Primarily relates to sales of commercial properties.
(c)
See “Sale of Silverhawk” below.
(d)
Relates to the 2004 sale of NAC.
PINNACLE
WEST CONSOLIDATED — RESULTS OF OPERATIONS
General
Throughout the following explanations of our results of operations, we refer to “gross
margin.” With respect to our regulated electricity segment and our marketing and trading segment,
gross margin refers to electric operating revenues less fuel and purchased power costs. “Gross
margin” is a “non-GAAP financial measure,” as defined in accordance with Securities and Exchange
Commission rules. Exhibit 99.29 reconciles this non-GAAP financial measure to operating income,
which is the most directly comparable financial measure calculated and presented in accordance with
GAAP. We view gross margin as an important performance measure of the core profitability of our
operations. This measure is a key component of our internal financial reporting and is used by our
management in analyzing our business segments. We believe that investors benefit from having
access to the same financial measures that our management uses. In addition, we have reclassified
certain prior year amounts to conform to our current-period presentation.
Sale of Silverhawk
In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC. As
a result of the sale, we recorded an after-tax loss from discontinued operations of approximately
$56 million in the second quarter of 2005. The marketing and trading segment discontinued
operations in the chart above include this loss as well as revenues and expenses related to the
operations of Silverhawk. The sale was completed on January 10, 2006.
The settlement of APS’ 2003 general retail rate case became effective April 1, 2005. As part
of the settlement, the ACC approved a 4.2% annual retail rate increase and the PSA, which provides
mechanisms for adjusting rates to reflect variations in fuel and purchased power costs. In
accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual
fuel and purchased power costs, net of Off-System Sales margins, and the amount for such costs
currently included in base rates. The current base rate for fuel and purchased power costs is
based on 2003 price levels and spot prices for natural gas and wholesale power have increased over
40% since then. Although APS defers actual fuel and purchased power costs on a current basis, APS’
recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval
of periodic surcharge applications.
Actual fuel and purchased power costs are higher than in prior periods primarily due to higher
fuel prices and increased plant outage days.
APS’ pretax PSA deferrals were
approximately $173 million at December 31, 2005. Based on
recent forward market prices for natural gas and purchased power (which are subject to change), and
assuming no interim rate relief, APS estimates that its pretax PSA deferrals in 2006 will be
approximately $240 million to $250 million. In January 2006, the ACC approved the first annual adjustment
under the PSA mechanism, which is expected to recover approximately $110 million of the 2005
balance of $173 million from retail customers over twelve months beginning February 1, 2006. In
this same order, the ACC granted APS the authority to continue to defer fuel costs in excess of the
$776.2 million annual fuel cost cap established in the 2005 rate order and to seek recovery of
those amounts in a future proceeding. On February 2, 2006, APS filed a request with the ACC to
recover the remainder of the retail portion of the 2005 deferred fuel balance of $173 million —
approximately $60 million — through two surcharges. The
first surcharge is to recover $15
million over a twelve-month period proposed to begin with the date of the ACC’s decision in APS’
pending emergency interim rate case. The second surcharge is to recover approximately $45 million
over a twelve-month period proposed to begin no later than the ACC’s completion of its inquiry
regarding unplanned 2005 outages at Palo Verde. The $45 million of PSA deferrals represents
additional replacement power costs associated with these outages. See Note 3. See “Overview” in
this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the
related economic impact.
2005 Compared with 2004
Our consolidated net income for 2005 was $176 million compared with $243 million for the prior
year. The current-year net income included an after-tax net loss from discontinued operations of
$47 million compared with a $4 million after-tax loss in the prior year, which for both years is
related primarily to the sale and operations of Silverhawk (see “Sale of Silverhawk” above),
partially offset by sales of commercial properties at SunCor. Income from continuing operations
decreased $24 million in the period-to-period comparison, reflecting the following changes in
earnings by segment:
•
Regulated Electricity Segment – Income from continuing operations increased
approximately $15 million primarily due to deferred fuel and purchased power costs; a
retail price increase effective April 1, 2005; higher retail sales volumes due to
customer growth; lower depreciation due to lower depreciation rates; lower
regulatory asset amortization; and effects of weather on retail sales. These
positive factors were partially offset by the regulatory disallowance of plant costs
in accordance with the APS retail rate case settlement; higher fuel and purchased
power costs primarily due to higher prices and more plant outage days; higher
operations and maintenance expense related to generation and customer service; and
higher property taxes due to increased plant in service.
•
Real Estate Segment – Income from continuing operations decreased approximately $5
million primarily due to decreased parcel sales, partially offset by increased margins
on home sales. Income from discontinued real estate operations increased $13 million
due to higher commercial property sales.
•
Marketing and Trading Segment – Income from continuing operations decreased
approximately $13 million primarily due to lower unit margins on competitive retail
sales in California; the absence of Off-System Sales that we began reporting in the
regulated electricity segment in April 2005; and lower mark-to-market gains on
contracts for future delivery.
•
Other Segment – Income from continuing operations decreased approximately $21
million primarily due to an after-tax gain related to the sale of a limited partnership
interest in the Phoenix Suns recorded in the prior year.
Higher retail sales volumes due to customer growth,
excluding weather effects
58
35
Effects of weather on retail sales
14
9
Higher fuel and purchased power costs primarily due to
higher prices and more plant outage days
(126
)
(77
)
Miscellaneous items, net
(8
)
(5
)
Net increase in regulated electricity segment gross margin
174
106
Marketing and trading segment gross margin:
Lower unit margins on competitive retail sales in California
(13
)
(8
)
Lower realized margins on wholesale sales primarily
due to the absence of sales that we began reporting in the
regulated segment in April 2005
(4
)
(3
)
Lower mark-to-market gains on contracts for future delivery
due to changes in forward prices
(4
)
(2
)
Net decrease in marketing and trading segment
gross margin
(21
)
(13
)
Net increase in gross margin for regulated electricity
and marketing and trading segments
153
93
Regulatory disallowance, in accordance with the APS retail rate
case settlement
(139
)
(84
)
Lower real estate segment contribution primarily related to
decreased parcel sales, partially offset by increased
margins on home sales
(8
)
(5
)
Lower other income primarily due to sale of limited partnership
interest in Phoenix Suns recorded in the prior year,
partially offset by higher interest income
(30
)
(18
)
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls
(20
)
(12
)
Customer service costs, including regulatory demand-side
management programs and planned maintenance
(20
)
(12
)
Miscellaneous items, net
(4
)
(2
)
Depreciation and amortization decreases primarily due to:
Lower regulatory asset amortization
22
13
Lower depreciation rates, partially offset by
increased depreciable assets
22
13
Higher property taxes primarily due to increased plant in service
Regulated electricity segment revenues were $202 million higher for 2005 compared with the
prior year primarily as a result of:
•
an $81 million increase in retail revenues related to customer growth,
excluding weather effects;
•
a $65 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
a $40 million increase in Off-System Sales primarily resulting from
sales previously reported in the marketing and trading segment that were classified
beginning in April 2005 as sales in the regulated electricity segment in accordance
with the APS retail rate case settlement;
•
an $11 million increase in retail revenues related to weather; and
•
a $5 million increase due to miscellaneous factors.
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $49 million lower for 2005 compared with the prior
year primarily as a result of:
•
a $40 million decrease in Off-System Sales due to the absence of sales
previously reported in the marketing and trading segment that were classified beginning
in April 2005 as sales in the regulated electricity segment in accordance with the APS
retail rate case settlement;
•
a $4 million decrease in mark-to-market gains on contracts for future
delivery due to changes in forward prices;
•
a $3 million decrease in marketing and trading revenues due to lower
sales volumes; and
•
a $2 million decrease from lower volumes of competitive retail sales in California.
Real Estate Revenues
Real estate revenues were $12 million lower for 2005 compared with the prior year primarily
due to decreased parcel sales, partially offset by increased home sales at SunCor.
Other Revenues
Other revenues were $18 million higher for 2005 compared with the prior year primarily due to
increased sales of energy-related products and services by APS Energy Services.
Our consolidated net income for 2004 was $243 million compared with $241 million for the prior
year. 2004 net income included an after-tax net loss from discontinued operations of $4 million
primarily related to Silverhawk. The 2003 net income included a $16 million after-tax gain from
discontinued operations primarily related to sales of commercial properties at SunCor. Income from
continuing operations increased $22 million in the period-to-period comparison, reflecting the
following changes in earnings by segment:
•
Regulated Electricity Segment – Income from continuing operations decreased
approximately $18 million primarily due to higher costs (primarily interest expense,
depreciation, operation and maintenance costs and property taxes, net of gross margin
contributions) related to a new power plant placed in service in mid-2003; increased
operations and maintenance costs primarily related to customer service and personnel
costs; lower income tax credits; higher depreciation related to delivery and other
assets; the effects of milder weather on retail sales; and a retail electricity rate
decrease in mid-2003. These negative factors were partially offset by lower regulatory
asset amortization, and higher retail sales volumes due to customer growth and usage.
•
Real Estate Segment – Income from continuing operations decreased approximately $5
million due to decreased asset sales, partially offset by increased land sales. Income
from discontinued operations decreased $6 million primarily due to the 2003 gain on the
sale of SunCor’s water utility company (see Note 22).
•
Marketing and Trading Segment – Income from continuing operations increased
approximately $21 million primarily due to higher forward and realized prices for
wholesale electricity, partially offset by lower margins in California by APS Energy
Services. Income from discontinued operations decreased $13 million due to Silverhawk
(see Note 22).
•
Other Segment – Income from continuing operations increased approximately $24
million primarily due to a $21 million after-tax gain related to the sale of El
Dorado’s limited partnership interest in the Phoenix Suns.
Additional details on the major factors that increased (decreased) income from continuing
operations and net income are contained in the following table
(dollars in millions):
Increase (Decrease)
Pretax
After Tax
Regulated electricity segment gross margin:
Higher retail sales volumes due to customer growth, excluding
weather effects
$
43
$
26
Lower replacement power costs due to fewer unplanned outages
6
4
Effects of weather on retail sales
(17
)
(10
)
Retail electricity price reduction effective July 1, 2003
(13
)
(8
)
Increased purchased power and fuel costs due to higher fuel and
power prices
(4
)
(2
)
Miscellaneous factors, net
(8
)
(6
)
Net increase in regulated electricity segment gross margin
7
4
Marketing and trading segment gross margin:
Higher mark-to-market gains on contracts for future delivery due to higher
forward prices for wholesale electricity
28
17
Higher realized margins on energy trading primarily due to higher electricity
prices
18
11
Increase in Off-System Sales due to higher sales volumes and higher unit
margins
10
6
Lower unit margins and lower competitive retail sales volumes in California
by APS Energy Services
(22
)
(13
)
Net increase in marketing and trading segment gross margin
34
21
Net increase in gross margin for regulated electricity and marketing and
trading segments
41
25
Lower real estate segment contributions primarily due to decreased asset sales,
a portion of which was recorded in other income in the prior period, partially
offset by higher land sales (see Note 22)
(7
)
(5
)
Higher other income due to the sale of El Dorado’s limited partnership interest
in the Phoenix Suns
35
21
Higher operations and maintenance expense primarily related to
customer service costs, new power plants in service and personnel costs
(44
)
(26
)
Interest expense net of capitalized financing costs, decreases (increases):
New power plants in service
(16
)
(10
)
Lower other debt balances and rates partially offset by increased
utility plant in service
9
5
Depreciation and amortization decreases (increases):
Lower regulatory asset amortization
68
41
New power plants in service
(4
)
(2
)
Increased delivery and other assets
(20
)
(12
)
Higher property taxes due to increased plant in service
(10
)
(6
)
Lower income tax credits
—
(17
)
Miscellaneous items, net
3
8
Net increase in income from continuing operations
$
55
22
Discontinued operations (see Note 22)
(20
)
Net increase in net income
$
2
The increase in net costs (primarily interest expense, depreciation and operations and
maintenance expense, net of gross margin contributions) related to new power plants placed in
service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $26 million after
income taxes in 2004 compared with the prior year.
Includes $185 million in 2005 for the acquisition of the Sundance Plant.
(b)
Primarily information systems and facilities projects.
(c)
Consists primarily of capital expenditures for land development and retail and
office building construction reflected in “Real estate investments” on the Consolidated
Statements of Cash Flows.
Distribution and transmission capital expenditures are comprised of infrastructure additions
and upgrades, capital replacements, new customer construction and related information systems and
facility costs. Examples of the types of projects included in the forecast include lines,
substations, line extensions to new residential and commercial developments and upgrades to
customer information systems. Major transmission projects are driven by strong regional customer
growth.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil
and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam
generators (see below). 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. Generation also includes nuclear fuel expenditures of approximately $35
million annually for 2006 through 2008.
Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005
outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the
manufacture of one additional set of steam generators. These generators will be installed in Unit
3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS’
share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through
2005 with the remaining $55 million included in future years in the capital expenditure table
above. Capital expenditures will be funded with internally generated cash or external financings.
The following table summarizes Pinnacle West’s consolidated contractual requirements as of
December 31, 2005 (dollars in millions):
2007-
2009-
2006
2008
2010
Thereafter
Total
Long-term debt payments,
including interest: (a)
APS
$
219
$
259
$
480
$
3,350
$
4,308
Pinnacle West
312
—
—
—
312
SunCor
9
143
—
—
152
Total long-term debt payments,
including interest
540
402
480
3,350
4,772
Short-term debt payments,
including interest (b)
16
—
—
—
16
Capital lease payments
2
2
2
2
8
Operating lease payments
74
144
133
303
654
Minimum pension funding
requirement (c)
37
—
—
—
37
Purchased power and fuel
commitments (d)
316
419
256
908
1,899
Purchase obligations (e)
25
9
—
75
109
Nuclear decommissioning funding
requirements
21
42
46
259
368
Total contractual commitments
$
1,031
$
1,018
$
917
$
4,897
$
7,863
(a)
The long-term debt matures at various dates through 2035 and bears interest principally at
fixed rates. Interest on variable-rate long-term debt is determined by using the rates at
December 31, 2005 (see Note 6).
(b)
The short-term debt matures within 12 months and is primarily related to short-term loans at
SunCor. These loans are made up of multiple notes primarily with variable interest rates
based on prime plus 1.75% or LIBOR plus 2.25% and 2.50% at December 31, 2005 (see Note 5).
(c)
Future pension contributions are not determinable for time periods after 2006.
(d)
Our fuel and purchased power commitments include purchases of coal, electricity, natural gas
and nuclear fuel (see Note 11).
(e)
These contractual obligations include commitments for capital expenditures and other
obligations.
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.
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, 2005, APS would have been required to
assume approximately $234 million of debt and pay the equity participants approximately $185
million.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit in support of
our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services.
We have not recorded any liability on our Consolidated Balance Sheets with respect to these
obligations. 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.
Credit Ratings
The
ratings of securities of Pinnacle West and APS as of March 7, 2006 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 those companies’ cost of and access to capital. It may also require
additional collateral related to certain derivative instruments (see Note 18).
Moody’s
Standard & Poor’s
Pinnacle West
Senior unsecured
Baa2
BB+
Commercial paper
P
-2
A-3
Outlook
Under Review for
Stable
Possible Downgrade
APS
Senior unsecured
Baa1
BBB-
Secured lease
obligation bonds
Baa1
BBB-
Commercial paper
P
-2
A-3
Outlook
Under Review for
Stable
Possible Downgrade
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include a debt to capitalization ratio. 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 each
of
Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization cannot exceed 65%. At December 31, 2005, the ratio was approximately
49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a
minimum cash coverage of two times the interest requirements for APS. The interest coverage is
approximately 4 times under APS’ bank financing agreements as of December 31, 2005. 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.
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, in the event of a further rating downgrade, Pinnacle West and/or APS may be
subject to increased interest costs under certain financing agreements.
All of Pinnacle West’s bank 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.
Capital Needs and Resources
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest
payments on our long-term debt. On October 19, 2005, our Board of Directors increased the common
stock dividend to an indicated annual rate of $2.00 per share from $1.90 per share, effective with
the December 1, 2005 dividend payment. The level of our common 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.
Our primary sources of cash are dividends from APS, external financings and cash distributions
from our other subsidiaries, primarily SunCor. For the years 2003 through 2005, total dividends
from APS were $510 million and total cash contributions from SunCor were $243 million. For the
year ended December 31, 2005 cash contributions from APS were approximately $170 million and
distributions from SunCor were approximately $50 million. An ACC financing 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. At December 31, 2005, APS’
common equity ratio, as defined, was approximately 54%.
At December 31, 2005, Pinnacle West’s outstanding long-term debt, including current
maturities, was $299 million. In December 2005, we replaced the existing revolving credit facility
with a $300 million revolving credit facility that terminates in December 2010. This line of
credit is available to support the issuance of up to $250 million in commercial paper or to be used
as bank borrowings, including issuances of letters of credit. At December 31, 2005, we had no
commercial paper or short-term borrowings outstanding. We ended 2005 in an invested position.
Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our
subsidiaries. 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 the fund assets and our pension obligation. The assets in the plan are comprised of
common stocks, bonds, common and collective trusts and short-term investments. Future year
contribution amounts are dependent on fund performance and fund valuation assumptions. We
contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be
approximately $50 million. The expected contribution to our other postretirement benefit plans in
2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of
the contributions. APS’ share is approximately 96% of both plans.
On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior
Notes due November 1, 2005. The Company used cash on hand to redeem the notes.
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price
of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the
net proceeds for general corporate purposes, including making capital contributions to APS, which,
in turn, used a portion of such funds to acquire the Sundance Plant and fund other capital
expenditures to meet the growing needs of APS’ service territory.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with
Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement
provides the terms under which Pinnacle West may offer up to
$200 million of its senior notes for
purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes
issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28,2006, Pinnacle West issued and sold to Prudential affiliates
$175 million aggregate principal
amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”). Pinnacle
West will use the proceeds of the Series A Notes to repay at
maturity a portion of the $300 million
aggregate principal amount of its 6.40% Senior Notes due April 1, 2006 or for other general
corporate purposes.
See “Equity Infusions” in Note 3 for information regarding the ACC approval of Pinnacle West’s
infusion of more than $450 million of equity into APS, consisting of about $250 million of the
proceeds of Pinnacle West’s common equity issuance and about $210 million of the proceeds from the
sale of Silverhawk in January 2006.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory
redemptions of long-term debt. APS pays for its capital requirements with cash from operations
and, to the extent necessary, external financings. APS has historically paid its dividends to
Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a
discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle
West.
On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand
to redeem these notes.
On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million
of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were
issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are
payable solely from revenues obtained from APS pursuant to a loan agreement between APS and
Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term
debt on our Balance Sheets.
On May 12, 2003, APS issued $500 million of debt and made a $500 million loan to Pinnacle West
Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund
the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated
Assets. On April 11, 2005, this loan was repaid with the proceeds of a new debt issuance by
Pinnacle West Energy.
On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on
hand to repay these notes.
On August 22, 2005, APS issued $250 million of 5.50% Senior Unsecured Notes due September 1,2035. A portion of the net proceeds from the sale of the notes was used for general corporate
purposes and, on October 3, 2005, APS used the balance of the proceeds, along with cash on hand, to
fund the $500 million that it was obligated to transfer to Pinnacle West Energy in connection with
APS’ acquisition of the PWEC Dedicated Assets. See “Related Party Transactions” in Note S-6 for
information regarding the $500 million intercompany payable to Pinnacle West Energy. APS satisfied
this obligation to Pinnacle West Energy on October 3, 2005.
APS’ outstanding debt was approximately $2.6 billion at December 31, 2005. In December 2005,
APS replaced its $325 million revolving credit facility that would have terminated in May 2007 with
a $400 million revolving credit facility that terminates in December 2010. This line of credit 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. At December 31, 2005, APS had no
outstanding commercial paper or bank borrowings. APS ended 2005 in an invested position.
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.
See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in 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 PSA adjustments and ACC approval of periodic surcharge applications.
See “Cash Flow Hedges” in Note 18 for information related to increased collateral provided to
us by counterparties.
Pinnacle West Energy
On
April 11, 2005, Pinnacle West Energy issued $500 million Floating Rate Senior Notes due
April 1, 2007. Pinnacle West unconditionally guaranteed these notes. Pinnacle West Energy used
the proceeds of this issuance to repay the $500 million loan from APS to Pinnacle West Energy
described under “Capital Needs and Resources — APS” above. On October 3, 2005, Pinnacle West
Energy repaid the Floating Rate Senior Notes due April 1, 2007 with $500 million received from APS
in connection with the transfer of the PWEC Dedicated Assets.
See Note 22 of Notes to Consolidated Financial Statements above for a discussion of the sale
of our 75% ownership interest in Silverhawk.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and
its own external financings. SunCor’s capital needs consist primarily of capital expenditures for
land development and retail and office building construction. See the capital expenditures table
above for actual capital expenditures during 2005 and projected capital expenditures for the next
three years. SunCor expects to fund its future capital requirements with cash from operations and
external financings.
SunCor’s total outstanding debt was approximately $145 million as of December 31, 2005,
including $123 million of debt outstanding, which is classified as long-term debt, under a $150
million line of credit. SunCor’s total short-term debt was $16 million at December 31, 2005.
SunCor’s long-term debt, including current maturities, totaled $129 million at December 31, 2005.
See Note 6.
El Dorado expects minimal capital requirements over the next three years and intends to focus
on prudently realizing the value of its existing investments.
APS Energy Services expects minimal capital expenditures over the next three years.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosures at the date of the financial statements and during the reporting
period. Some of those judgments can be subjective and complex, and actual results could differ
from those estimates. We consider the following accounting policies to be our most critical
because of the uncertainties, judgments and complexities of the underlying accounting standards and
operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to
be reflected in our financial statements. Their actions may cause us to capitalize costs that
would otherwise be included as an expense in the current period by unregulated companies. If
future recovery of costs ceases to be probable, the assets would be written off as a charge in
current period earnings. A major component of our regulatory assets is the retail fuel and power
costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between
actual retail fuel and power costs and the amount of such costs currently included in base rates.
We had $324 million, including $173 million related to the PSA, of regulatory assets on the
Consolidated Balance Sheets at December 31, 2005. Included in the $173 million is approximately
$45 million related to the 2005 unplanned Palo Verde outages, which currently are the subject of
inquiry by the ACC. In addition, we had $592 million of regulatory liabilities on the Consolidated
Balance Sheets at December 31,
2005, which primarily are related to removal costs. See Notes 1 and 3 for more information about
regulatory assets, APS’ general rate case and power supply adjustor.
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, 2005 projected benefit obligation, our December 31,2005 reported pension liability on the Consolidated Balance Sheets and our 2005 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):
Increase(Decrease)
Impact on
Projected
Impact on
Impact on
Benefit
Pension
Pension
Actuarial Assumption (a)
Obligation
Liability
Expense
Discount rate:
Increase 1%
$
(207
)
$
(170
)
$
(8
)
Decrease 1%
237
195
8
Expected long-term rate
of return on plan
assets:
Increase 1%
—
—
(4
)
Decrease 1%
—
—
4
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant.
The following chart reflects the sensitivities that a change in certain actuarial assumptions
would have had on the December 31, 2005 accumulated other postretirement benefit obligation and our
2005 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):
Expected long-term rate
of return on plan
assets – pretax:
Increase 1%
—
(1
)
Decrease 1%
—
1
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant.
(b)
This assumes a 1% change in the initial and ultimate health care cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying
interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether
we use accrual accounting (for contracts designated as normal) or fair value (mark-to-market)
accounting. Mark-to-market accounting requires that changes in the fair value are recognized
periodically in income unless certain hedge criteria are met. For fair value hedges, the gain or
loss on the derivative as well as the offsetting loss or gain on the hedged item associated with
the hedged risk are recognized in earnings. For cash flow hedges, the effective portion of changes
in the fair value of the derivative are recognized in common stock equity (as a component of other
comprehensive income (loss)).
The fair value of our derivative contracts is not always readily determinable. In some cases,
we use models and other valuation techniques to determine fair value. The use of these models and
valuation techniques sometimes requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our marketing and trading
portfolio consists of structured activities hedged with a portfolio of forward purchases that
protects the economic value of the sales transactions. See “Market Risks – Commodity Price Risk”
below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for
a further discussion on derivative and energy trading accounting.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
General Electric operating revenues are derived from sales of electricity in regulated retail
markets in Arizona and from competitive retail and wholesale power markets in the western United
States. These revenues are affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer as well as electricity rates and tariffs and variations in
weather from period to period. Competitive sales of energy and energy-related products and
services are made by APS Energy Services in certain western states that have opened to competition.
Retail Rate Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is
the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed
in greater detail in Note 3, APS has pending before the ACC a general retail rate case, an
application for an emergency interim rate increase, and an application for two separate surcharges
under the PSA.
Fuel and Purchased Power Costs Fuel and purchased power costs 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, variances in deferrals and amortization of fuel and purchased power
beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply
Adjustor” in Note 3 for information regarding the PSA approved by the ACC. See “Natural Gas
Supply” in Note 11 for more information on fuel costs. See “Overview” in this Item 7 for
information about Palo Verde Unit 1 operating at reduced power levels
and the related economic impact.
Customer and Sales Growth The customer and sales growth referred to in this paragraph applies
to Native Load customers and sales to them. Customer growth in APS’ service territory averaged
about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to
average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity
sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of
weather variations. Customer growth for 2005 was 4.3%.
Actual sales growth, excluding weather-related variations, may differ from our projections as
a result of numerous factors, such as economic conditions, customer growth, usage patterns and
responses to retail price changes. Our experience indicates that a reasonable range of variation
in our kilowatt-hour sales projection attributable to such economic factors can result in increases
or decreases in annual net income of up to $10 million.
Weather In forecasting retail sales growth, we assume normal weather patterns based on
historical data. Historical extreme weather variations have resulted in annual variations in net
income in excess of $20 million. However, our experience indicates that the more typical
variations from normal weather can result in increases or decreases in annual net income of up to
$10 million.
Wholesale Power Market Conditions The marketing and trading division focuses primarily on
managing APS’ risks relating to fuel and purchased power costs in connection with its costs of
serving Native Load customer demand. The marketing and trading division, subject to specified
parameters, markets, hedges and trades in electricity, fuels and emission allowances and
credits. Our future earnings will be affected by the strength or weakness of the wholesale
power market.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by
growth, power plant additions and operations, 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, which include generation construction or
acquisition, changes in depreciation and amortization rates (see Note 1), and changes in regulatory
asset amortization. See Note 7 for information on APS’ acquisition of the Sundance Plant in 2005.
See “Purchased Power” in Part I, Item 1 of this report, for more information on requests for
proposal to acquire additional long-term resources in 2006 and 2007.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in-service and under construction. The average
property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed
value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition
of the Sundance Plant and our additions to transmission and distribution facilities are included in
the property tax base.
Interest Expense Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in the next several
years are expected to be our capital requirements and our 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. Interest expense is also affected by interest rates on variable-rate debt.
Retail Competition Although some very limited retail competition existed in Arizona in 1999
and 2000, there are currently no active retail competitors providing 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.
Subsidiaries SunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million
in 2005. See Note 22 for further discussion.
APS Energy Services’ and El Dorado’s historical results are not indicative of future
performance.
General Our financial results may be affected by a number of broad factors. See
“Forward-Looking Statements” 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.
Our major financial market risk exposure is to changing interest rates. Changing interest
rates will affect interest paid on variable-rate debt and interest earned by our nuclear
decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use
of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has
risk associated with the changing market value of equity 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 31,2005 and 2004. The interest rates presented in the tables below represent the weighted-average
interest rates as of December 31, 2005 and 2004 (dollars in thousands):
The tables below present contractual balances of APS’ long-term debt at the expected maturity
dates as well as the fair value of those instruments on December 31, 2005 and 2004. The interest
rates presented in the tables below represent the weighted-average interest rates as of December31, 2005 and 2004 (dollars in thousands):
Variable-Rate
Fixed-Rate
Long-Term Debt
Long-Term Debt
Interest
Interest
2005
Rates
Amount
Rates
Amount
2006
—
$
—
6.71
%
$
86,165
2007
—
—
5.76
%
1,075
2008
—
—
5.74
%
1,271
2009
—
—
5.70
%
1,005
2010
—
—
5.69
%
1,077
Years thereafter
3.25
%
565,855
5.79
%
1,918,026
Total
$
565,855
$
2,008,619
Fair value
$
565,855
$
2,025,001
Variable-Rate
Fixed-Rate
Long-Term Debt
Long-Term Debt
Interest
Interest
2004
Rates
Amount
Rates
Amount
2005
—
$
—
7.27
%
$
401,727
2006
—
—
6.72
%
86,082
2007
—
—
5.51
%
867
2008
—
—
5.51
%
1,054
2009
—
—
5.51
%
818
Years thereafter
1.89
%
565,860
4.79
%
1,669,901
Total
$
565,860
$
2,160,449
Fair value
$
565,799
$
2,254,061
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances. 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.
Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk
management activities and monitors the results of marketing and trading activities to ensure
compliance with our stated energy risk management and trading policies. As part of our risk
management program, we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodities. In addition, subject to specified risk
parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
The mark-to-market value of derivative instruments related to our risk management and trading
activities are presented in two categories consistent with our business segments:
•
Regulated Electricity – non-trading derivative instruments that hedge our purchases
and sales of electricity and fuel for APS’ Native Load requirements of our regulated
electricity business segment; and
•
Marketing and Trading – non-trading and trading derivative instruments of our
competitive business segment.
The following tables show the pretax changes in mark-to-market of our non-trading and trading
derivative positions in 2005 and 2004 (dollars in millions):
2005
2004
Regulated
Marketing and
Regulated
Marketing and
Electricity
Trading
Electricity
Trading
Mark-to-market of net positions
at beginning of period
$
33
$
107
$
—
$
69
Recognized in earnings:
Change in mark-to-market
gains for future period
deliveries
14
20
9
20
Mark-to-market
(gains) losses realized
including ineffectiveness
during the period
(8
)
(14
)
3
(15
)
Deferred as a regulatory liability
31
—
—
—
Recognized in OCI:
Change in mark-to-market
gains for future period
deliveries (a)
359
102
42
37
Mark-to-market
gains realized
during the period
(94
)
(34
)
(21
)
(6
)
Change in valuation techniques
—
—
—
2
Mark-to-market of net positions
at end of period
$
335
$
181
$
33
$
107
(a)
The increase in regulated mark-to-market recorded in OCI is due primarily to
increases in forward natural gas prices.
The tables below show the fair value of maturities of our non-trading and trading derivative
contracts (dollars in millions) at December 31, 2005 by maturities and by the type of valuation
that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more
discussion of our valuation methods.
Regulated Electricity
Total
Years
fair
Source of Fair Value
2006
2007
2008
2009
2010
thereafter
value
Prices actively quoted
$
162
$
58
$
39
$
7
$
—
$
—
$
266
Prices provided by
other external sources
21
61
1
—
—
—
83
Prices based on models
and other valuation
methods
(3
)
(2
)
(1
)
(2
)
(1
)
(5
)
(14
)
Total by maturity
$
180
$
117
$
39
$
5
$
(1
)
$
(5
)
$
335
Marketing and Trading
Total
Years
fair
Source of Fair Value
2006
2007
2008
2009
2010
thereafter
value
Prices actively quoted
$
22
$
—
$
—
$
(1
)
$
(1
)
$
—
$
20
Prices provided by
other external sources
76
87
20
—
—
—
183
Prices based on models
and other 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, 2005 and 2004 (dollars in millions).
These contracts are primarily structured sales activities hedged with a
portfolio of forward purchases that protects the economic value of the sales
transactions.
(b)
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. We
have risk management and trading contracts with many 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
General
Throughout the following explanations of our results of operations, we refer to “gross
margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs.
Gross margin is a “non-GAAP financial measure,” as defined
in accordance with SEC rules. Exhibit 99.30 reconciles this non-GAAP financial measure to operating income, which is the most directly
comparable financial measure calculated and presented in accordance with GAAP. We view gross
margin as an important performance measure of the core profitability of our operations. This
measure is a key component of our internal financial reporting and is used by our management in
analyzing our business. We believe that investors benefit from having access to the same financial
measures that our management uses. In addition, we have reclassified certain prior-period amounts
to conform to our current-period presentation.
The settlement of APS’ 2003 general retail rate case became effective April 1, 2005. As part
of the settlement, the ACC approved a 4.2% annual retail rate increase and the PSA, which provides
mechanisms for adjusting rates to reflect variations in fuel and purchased power costs. In
accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual
fuel and purchased power costs, net of Off-System Sales margins, and the amount for such costs
currently included in base rates. The current base rate for fuel and purchased power costs is
based on 2003 price levels and spot prices for natural gas and wholesale power have increased over
40% since then. Although APS defers actual fuel and purchased power costs on a current basis, APS’
recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval
of periodic surcharge applications.
Actual fuel and purchased power costs are higher than in prior periods primarily due to higher
fuel prices and increased plant outage days.
APS’ pretax PSA deferrals were approximately $173 million at December 31, 2005. Based on
recent forward market prices for natural gas and purchased power (which are subject to change), and
assuming no interim rate relief, APS estimates that its pretax PSA deferrals in 2006 will be
approximately $240 million to $250 million. In January 2006, the ACC approved the first annual
adjustment under the PSA mechanism, which is expected to recover approximately $110 million of the
2005 balance of $173 million from retail customers over twelve months beginning February 1, 2006.
In this same order, the ACC granted APS the authority to continue to defer fuel costs in excess of
the $776.2 million annual fuel cost cap established in the 2005 rate order and to seek recovery of
those amounts in a future proceeding. On February 2, 2006, APS filed a request with the ACC to
recover the remainder of the retail portion of the 2005 deferred fuel balance of $173 million —
approximately $60 million — through two surcharges. The
first surcharge is to recover $15
million over a twelve-month period proposed to begin with the date of the ACC’s decision in APS’
pending emergency interim rate case. The second surcharge is to recover approximately $45 million
over a twelve-month period proposed to begin no later than the ACC’s completion of its inquiry
regarding unplanned 2005 outages at Palo Verde. The $45 million of PSA deferrals represents
additional replacement power costs associated with these outages. See Note 3. See “Overview” in
this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the
related economic impact.
2005 Compared with 2004
APS’ net income for 2005 was $170 million compared with $200 million for the prior year. The
$30 million decrease was primarily due to the regulatory disallowance of plant costs in accordance
with the APS retail rate case settlement; higher fuel and purchased power costs primarily due to
higher prices and more plant outage days; higher operations and maintenance expense related to
generation and customer service costs; and higher property taxes due to increased plant in service.
These negative factors were partially offset by deferred fuel and purchased power costs; a retail
price increase effective April 1, 2005; higher retail sales volumes due to customer growth; lower
depreciation due to lower depreciation rates; lower regulatory asset amortization; and effects of
weather on retail sales.
Additional details on the major factors that increased (decreased) net income are contained in
the following table (dollars in millions):
Higher retail sales volumes due to customer growth,
excluding weather effects
58
35
Effects of weather on retail sales
14
9
Higher fuel and purchased power costs primarily due to
higher prices and more plant outage days
(146
)
(89
)
Miscellaneous items, net
(14
)
(9
)
Net increase in gross margin
148
90
Regulatory disallowance, in accordance with the retail rate settlement
(139
)
(84
)
Operations and maintenance increases primarily due to:
Customer service costs, including regulatory demand-side
management programs and planned maintenance
(22
)
(13
)
Generation costs, including planned maintenance and overhauls
(16
)
(10
)
Costs of PWEC Dedicated Assets not included in prior year
(14
)
(9
)
Depreciation and amortization decreases primarily due to:
Lower regulatory asset amortization
22
13
Higher depreciable assets due to transfer of PWEC
Dedicated Assets, partially offset by lower depreciation rates
(11
)
(7
)
Higher property taxes due to increased plant in service
(12
)
(7
)
Miscellaneous items, net
(7
)
(3
)
Net decrease in net income
$
(51
)
$
(30
)
Regulated Electricity Revenues
Regulated electricity revenues were $193 million higher for 2005 compared with the prior year
primarily as a result of:
•
an $81 million increase in retail revenues related to customer growth,
excluding weather effects;
•
a $65 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
a $40 million increase in Off-System Sales primarily resulting from
sales previously reported in marketing and trading that were classified beginning in
April 2005 as sales in regulated electricity in accordance with the APS retail rate
case settlement;
•
an $11 million increase in retail revenues related to weather; and
•
a $4 million decrease due to miscellaneous factors.
Marketing and trading revenues were $120 million lower for 2005 compared with the prior-year
period primarily as a result of:
•
a $69 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower volumes;
•
a $40 million decrease in Off-System Sales due to the absence of sales
previously reported in marketing and trading that were classified beginning in April
2005 as sales in regulated electricity in accordance with the APS retail rate case
settlement; and
•
an $11 million decrease on future mark-to-market gains due to higher
prices.
2004 Compared with 2003
APS’ net income for 2004 was $200 million compared with $181 million for the prior year. The
$19 million increase in the period-to-period comparison reflects lower regulatory asset
amortization; the benefit of customer growth; decreased purchased power and fuel costs primarily
due to lower prices for capacity purchases; increased interest income and lower replacement power
costs due to fewer unplanned outages. These positive factors were partially offset by increased
operations and maintenance costs related to increased generation, customer service and personnel
costs; the effects of weather on retail sales; higher depreciation and amortization related to
increased delivery and other assets; lower realized margins on energy trading due to higher
wholesale electricity prices; a retail electricity price reduction; lower income tax credits; and
higher interest expense primarily due to increased utility plant in service.
Additional details on the major factors that increased (decreased) net income for 2004
compared with the prior year are contained in the following table (dollars in millions).
$49 million of higher energy trading revenues on realized sales of
electricity primarily due to higher electricity prices; and
•
$4 million in higher mark-to-market gains for future-period deliveries
primarily as a result of higher forward prices for wholesale electricity.
LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY
Contractual Obligations
The following table summarizes contractual requirements for APS as of December 31, 2005
(dollars in millions):
2007-
2009-
There-
2006
2008
2010
after
Total
Long-term debt payments,
including interest (a)
$
219
$
259
$
480
$
3,350
$
4,308
Capital lease payments
2
2
2
2
8
Operating lease payments
66
129
122
288
605
Purchase power and fuel
commitments (b)
265
331
256
896
1,748
Minimum pension funding
requirement (c)
36
—
—
—
36
Purchase obligations (d)
25
9
—
75
109
Nuclear decommissioning
funding requirements
21
42
46
259
368
Total contractual
commitments
$
634
$
772
$
906
$
4,870
$
7,182
(a)
The long-term debt matures at various dates through 2035 and bears interest principally at
fixed rates. Interest on variable-rate long-term debt is determined by the rates at December31, 2005.
(b)
APS’ purchase power and fuel commitments include purchases of coal, electricity, natural gas,
and nuclear fuel (see Note 11).
(c)
Future pension contributions are not determinable for time periods after 2006.
(d)
These contractual obligations include commitments for capital expenditures and other
obligations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 7 above for
a discussion of quantitative and qualitative disclosures about market risk.
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 13(a)-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, 2005. Our
management’s assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public
accounting firm, as stated in their report which is included herein and relates also to the
Company’s consolidated financial statements.
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, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedule
listed in the Index at Item 15. We also have audited management’s assessment, included in the
accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company
maintained effective internal control over financial reporting as of December 31, 2005, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company’s management is responsible for these
financial statements and financial statement schedule, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion on these financial statements and
financial statement schedule, an opinion on management’s assessment, and an opinion on the
effectiveness of 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 audit of 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, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles and
that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 2005 and 2004, and the
results of its operations and its cash flows for each of the three years in the period ended
December 31, 2005, in conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, the financial statement schedule, when considered in relation to
the basic consolidated financial statements taken as a whole, presents fairly, in all material
respects, the information set forth therein. Also, in our opinion, management’s assessment that
the Company maintained effective internal control over financial reporting as of December 31, 2005,
is fairly stated, in all material respects, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005, based on the criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and
our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally
NAC). See Note 22 for a discussion of the sale of NAC in November 2004. Significant intercompany
accounts and transactions between the consolidated companies have been eliminated.
APS is a vertically-integrated electric utility that provides either retail or wholesale
electric service to substantially all of the state of Arizona, with the major exceptions of about
one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in
northwestern Arizona. Pinnacle West Energy, which was formed in 1999, was the subsidiary through
which we conducted our unregulated generation operations. See Note 3 for a discussion of the
transfer of the PWEC Dedicated Assets from Pinnacle West Energy to APS. As of January 10, 2006,
Pinnacle West Energy no longer owns any generating plants and has ceased operations. APS Energy
Services was formed in 1998 and provides competitive commodity energy and energy-related products
to key customers in competitive markets in the western United States. SunCor is a developer of
residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah.
El Dorado is an investment firm.
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. We have reclassified certain prior-year amounts
to conform to the current-year presentation.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances and in interest rates. We manage
risks associated with these market fluctuations by utilizing various instruments that qualify as
derivatives, including exchange-traded futures and options and over-the-counter forwards, options
and swaps. As part of our overall risk management program, we use such instruments to hedge
purchases and sales of electricity, fuels, and emissions allowances and credits. In addition,
subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading
activities intended to profit from market price movements.
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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 exception for contracts that meet the normal purchases and sales criteria specified in the
standard. Contracts that do not meet the definition of a derivative are accounted for on an
accrual basis with the associated revenues and costs recorded at the time the contracted
commodities are delivered or received.
Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of
energy commodities are reflected at fair market value, net of valuation adjustments, as current or
long-term assets and liabilities from risk management and trading activities on the Consolidated
Balance Sheets.
We determine fair market value using actively-quoted prices when available. We consider
quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers
to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by other external
sources. This includes quarterly and calendar year quotes from independent brokers, which we
convert into monthly prices using historical relationships.
For options, long-term contracts and other contracts for which price quotes are not available,
we use models and other valuation methods. The valuation models we employ utilize spot prices,
forward prices, historical market data and other factors to forecast future prices. The primary
valuation technique we use to calculate the fair value of contracts where price quotes are not
available is based on the extrapolation of forward pricing curves using observable market data for
more liquid delivery points in the same region and actual transactions at the more illiquid
delivery points. We also value option contracts using a variation of the Black-Scholes
option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on the average of the
bid and offer price, and we discount to reflect net present value. We maintain certain valuation
adjustments for a number of risks associated with the valuation of future commitments. These
include valuation adjustments for liquidity and credit risks based on the financial condition of
counterparties. The liquidity valuation adjustment represents the cost that would be incurred if
all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to
counterparties, taking into account netting arrangements, expected default experience for the
credit rating of the counterparties and the overall diversification of the portfolio.
Counterparties in the portfolio consist principally of major energy companies, municipalities,
local distribution companies and financial institutions. We maintain credit policies that
management believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings, financial condition,
project economics and collateral requirements. When applicable, we employ standardized agreements
that allow for the netting of positive and negative exposures associated with a single
counterparty.
The use of models and other valuation methods to determine fair market value often requires
subjective and complex judgment. Actual results could differ from the results estimated through
application of these methods. Our marketing and trading portfolio includes structured activities
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 18 for additional information about our derivative and energy trading accounting
policies.
Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the
rate-making policies of these commissions. For regulated operations, we prepare our financial
statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result, we capitalize certain costs that
would be included as expense in the current period by unregulated companies. Regulatory assets
represent incurred costs that have been deferred because they are probable of future recovery in
customer rates. Regulatory liabilities generally represent expected future costs that have already
been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery
by considering factors such as applicable regulatory environment changes and recent rate orders to
other regulated entities in the same jurisdiction. This determination reflects the current
political and regulatory climate in the state and is subject to change in the future. If future
recovery of costs ceases to be probable, the assets would be written off as a charge in current
period earnings.
A major component of our regulatory assets is the retail fuel and power costs deferred under
the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and
power costs and the amount of such costs currently included in base rates.
As part of a 1999 retail rate case settlement agreement, APS amortized certain regulatory
assets over a period that ended June 30, 2004. Amortization was $18 million in 2004 and $86
million in 2003.
The detail of regulatory assets is as follows (dollars in millions):
Regulatory liability related to asset retirement
obligations
101
86
Deferred fuel and purchased power –
mark-to-market
31
—
Regulatory liability for deferred income taxes
24
—
Deferred interest income
22
22
Deferred gains on utility property
20
20
Demand-side management
7
—
Other
2
3
Total regulatory liabilities
$
592
$
507
(a)
In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets,
even if there is no legal obligation for removal.
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports
electric service, consisting primarily of generation, transmission and distribution facilities. We
report utility plant at its original cost, which includes:
•
material and labor;
•
contractor costs;
•
capitalized leases;
•
construction overhead costs (where applicable); and
•
capitalized interest or an allowance for funds used during construction.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred.
We charge retired utility plant to accumulated depreciation. Liabilities associated with the
retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized
as part of the related tangible long-lived assets. Accretion of the liability due to the passage
of time is an operating expense and the capitalized cost is depreciated over the useful life of the
long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its
regulated assets. This regulatory liability represents the difference between the amount that has
been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for
Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the
costs calculated in accordance with SFAS No. 143.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We record depreciation on utility plant on a straight-line basis over the remaining useful
life of the related assets. The approximate remaining average useful lives of our utility property
at December 31, 2005 were as follows:
•
Fossil plant – 19 years;
•
Nuclear plant – 20 years;
•
Other generation – 28 years;
•
Transmission – 40 years;
•
Distribution – 32 years; and
•
Other – 6 years.
For the years 2003 through 2005, the depreciation rates ranged from a low of 1.2% to a high of
11.43%. The weighted-average rate was 3.0% for 2005, 3.36% for 2004 and 3.35% for 2003. We
depreciate non-utility property and equipment over the estimated useful lives of the related
assets, ranging from 3 to 34 years. See “APS 2003 Rate Case” in Note 3 for a discussion of changes
in depreciation rates.
Investments
El Dorado accounts for its investments using the equity (if significant influence) and cost
(less than 20% ownership) methods. See Note 22 for a discussion of the sale of NAC.
The Company’s investments are reviewed in accordance with EITF 03-1, “The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain 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
5.7% for 2005, 4.9% for 2004 and 4.7% for 2003. Capitalized interest ceases to accrue when
construction is complete.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and a
reasonable 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 7.7% for 2005, 8.4% for 2004 and 8.6% for
2003. 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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
electricity are generally recorded when service is rendered or electricity is delivered to
customers. However, the determination and 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. At the end of each month, amounts of electricity delivered to customers since the date
of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales
taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April
2005 in accordance with the order in the APS 2003 Rate Case, we exclude city franchise fees from
both electric revenues and operating expenses.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross
basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some
contracts to purchase energy are netted against other contracts to sell energy. This is called
“book-out” and usually occurs in contracts that have the same terms (quantities and delivery
points) and for which power does not flow. We net these book-outs, which reduces both revenues and
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 segment 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 assets’ title has
passed. Commercial property and management revenues are recorded over the term of the lease or
period in which services are provided. In addition, see Note 22 – Discontinued Operations.
Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory and investments in
joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and
capitalized interest directly associated with the acquisition and development of each project.
Land under development and land held for future development are stated at accumulated cost, except
that, to the extent that such land is believed to be impaired, it is written down to fair value.
Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to
sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and
property taxes on homes under construction. Home inventory is stated at the lower of accumulated
cost or estimated fair value less costs to sell. 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash and Cash Equivalents
We consider all highly liquid investments with an initial maturity of three months or less to
be cash equivalents.
We have investments in auction rate securities in which interest rates are reset on a
short-term basis; however, the underlying contract maturity dates extend beyond three months. We
classify the investments in auction rate securities as investment in debt securities on our
Consolidated Balance Sheets.
We
have changed the presentation of our nuclear decommissioning trust
investment in our Consolidated Statements of Cash Flows for the year ended December 31, 2005, to
present investing cash outflows separately from investing cash inflows. Investing cash inflows and
outflows in the nuclear decommissioning trust investment amounts were previously presented in Other
within the investing section of the Consolidated Statements of Cash Flows. In
addition, we
changed the presentation of prior year amounts in order to be consistent with the 2005
presentation. There was no impact to net cash provided by (used in) operating, investing or
financing activities as a result of this change in presentation.
During
2005, we revised the presentation of our Consolidated Statements of Cash Flows to include
the cash flows from discontinued operations within the categories of operating, investing, and
financing activities. A summary of the effects of the change in presentation on the Consolidated
Statements of Cash Flows for the years ended December 31, 2004 and 2003, is as follows (dollars in
millions):
Net cash flows from operating activities as previously reported
$
842
$
901
Change in net cash flows from discontinued operations
9
1
Net cash flows from operating activities as currently reported
$
851
$
902
Net cash flows used for investing activities as previously
reported
$
(532
)
$
(815
)
Change in net cash flows used for discontinued operations
(13
)
6
Net cash flows used for investing activities as currently
reported
$
(545
)
$
(809
)
Net cash flows used for financing activities as previously
reported
$
(278
)
$
(32
)
Change in net cash flows used for discontinued operations
(2
)
(2
)
Net cash flows used for financing activities as currently
reported
$
(280
)
$
(34
)
Nuclear Fuel
APS charges nuclear fuel to fuel expense by using the unit-of-production method. The
unit-of-production method is an amortization method 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The
DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per
kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note
12 for information on nuclear decommissioning costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109,
“Accounting for Income Taxes.” 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 subsidiary
as though each 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. See
Note 4.
Reacquired Debt Costs
APS defers gains and losses incurred upon early retirement of debt. These costs are amortized
equally on a monthly basis over the remaining life of the original debt consistent with its
ratemaking treatment.
Stock-Based Compensation
We apply the fair value method of accounting for stock-based compensation, as provided for in
SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is
the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied
the fair value method prospectively, beginning with 2002 stock grants. In prior years, we
recognized stock compensation expense based on the intrinsic value method allowed in Accounting
Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” In addition,
SFAS No. 123R is effective for us as of January 1, 2006. We have evaluated the impacts of this new
guidance and do not believe it will have a material impact on our financial statements.
The following chart compares our net income, stock compensation expense and earnings per share
to what those items would have been if we had recorded stock compensation expense based on the fair
value method for all stock grants through 2005 (dollars in thousands, except per share amounts):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2005
2004
2003
Net Income as reported:
$
176,267
$
243,195
$
240,579
Add: Stock compensation
expense included in reported
net income (net of tax)
3,738
4,690
3,514
Deduct: Total stock
compensation expense
determined under fair value
method (net of tax)
(3,738
)
(5,311
)
(5,220
)
Pro forma net income
$
176,267
$
242,574
$
238,873
Earnings per share – basic:
As reported
$
1.83
$
2.66
$
2.64
Pro forma (fair value
method)
$
1.83
$
2.65
$
2.62
Earnings per share – diluted:
As reported
$
1.82
$
2.66
$
2.63
Pro forma (fair value
method)
$
1.82
$
2.65
$
2.61
In order to calculate the fair value of the 2004 and 2003 stock option grants (no stock
options were granted in 2005) and the pro forma information above, we calculated the fair value of
each stock option granted under the incentive plans using the Black-Scholes option-pricing model.
The fair value was calculated as of the date the option was granted. The following
weighted-average assumptions were used to calculate the fair value of the stock options:
2004
2003
Risk-free interest rate
3.15
%
3.35
%
Dividend yield
4.76
%
5.26
%
Volatility
17.04
%
38.03
%
Expected life (months)
60
60
See Note 16 for further discussion about our stock compensation plans.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily
software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142,
“Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite
useful lives. Amortization expense was $33 million in 2005, $34 million in 2004, and $25 million
in 2003. Estimated amortization expense on existing intangible assets over the next five years is
$31 million in 2006, $25 million in 2007, $14 million in 2008, $4 million in 2009, and $3 million
in 2010. At December 31, 2005, the weighted average remaining amortization period for intangible
assets is 3 years.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. New Accounting Standards
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” The standard
establishes accounting for transactions in which an entity exchanges its equity instruments for
goods or services. It also addresses transactions in which an entity incurs liabilities in
exchange for goods or services that are based on the fair value of the entity’s equity instruments
or that may be settled by the issuance of those equity instruments. In 2002, we began accounting
for stock-based compensation using the fair value method. We adopted SFAS No. 123R on January 1,2006. We believe the impacts of this new guidance on our financial statements will be immaterial.
Effective December 31, 2005, we adopted FIN 47, “Accounting for Conditional Asset Retirement
Obligations — an interpretation of FASB Statement No. 143.” FIN 47 clarifies that an entity must
record a liability for the fair value of an asset retirement obligation for which the timing and/or
method of settlement are conditional on a future event if the liability’s fair value can be
reasonably estimated. We have evaluated our asset retirement obligations under this new guidance
and determined that no additional liabilities need to be recorded at this time.
3. Regulatory Matters
APS General Rate Case
On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other
data in the general rate case that APS originally filed on November 4, 2005. As requested by the
ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test
period instead of the test year ended December 31, 2004 used in APS’ original filing. As a result
of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail
electricity revenues effective no later than December 31, 2006. The original filing requested a
19.9%, or $409.1 million, retail rate increase.
The updated requested rate increase is designed to recover the following (dollars in
millions):
Rate base update, including acquisition of
Sundance Plant
46.2
2.2
%
42.5
2.1
%
Pension funding
41.3
1.9
%
41.2
2.0
%
Other items
(30.9
)
(1.4
)%
(18.2
)
(0.9
)%
Total increase
$
453.9
21.3
%
$
409.1
19.9
%
The request is based on (a) a rate base of $4.4 billion, which approximates the
ACC-jurisdictional portion of the book value of utility plant, net of accumulated depreciation, as
of
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.031904 per
kilowatt-hour based on estimated 2006 prices; and (c) a proposed capital structure of 45% long-term
debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for
long-term debt and 11.50% for common stock equity). The requested increase in annual retail
electricity revenues from the original filing is based solely on increased fuel and purchased power
costs, slightly offset by other items (see the above chart). If the ACC approves the requested
base rate increase for fuel and purchased power costs (see clause (b) of this paragraph),
subsequent PSA rate adjustments and/or PSA surcharges would be reduced because such costs would
otherwise be eligible for recovery in the future under APS’ PSA.
The updated request does not include the PSA annual adjustor rate increase of approximately 5%
that took effect February 1, 2006 or the application for two separate PSA surcharges that APS filed
on February 2, 2006. See “Power Supply Adjustor” below.
Application for Emergency Interim Rate Increase
On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate
increase of $299 million, or approximately 14%, to be effective April 1, 2006. The purpose of the
emergency interim rate increase is solely to address APS’ under-collection of higher annual fuel
and purchased power costs. The increase would accelerate recovery of the fuel and purchased power
component of APS’ general rate case and is not an additional increase and would be subject to
refund. On February 28, 2006, several parties filed direct
testimony in this matter. The ACC
staff and the Residential Utility Consumer Office each recommended
that the ACC deny APS’ request for emergency rate relief, and
each cited the ACC’s January 25, 2006 modification of the
PSA as a basis for its recommendation (see “Power Supply
Adjustor” below). Because “concern continues to exist regarding the build-up of
deferred fuel balances in 2006 and the uncertain time frame for recovery
of prudently incurred fuel and purchased power costs,” the ACC staff also recommended, among other
things, that the ACC allow APS to file for PSA surcharge requests in
2006 on a quarterly basis, with the first request to be filed no
earlier than June 30, 2006.
A business coalition that advocates on behalf of retail electric
customers in Arizona and a major APS customer filed joint testimony
recommending that the ACC approve an interim rate increase of
$126 million in calendar-year 2006. Hearings on the emergency interim rate
increase request are scheduled to begin on March 20, 2006. We
cannot predict the outcome of this matter.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power Supply Adjustor
PSA Provisions
The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for
adjustment of retail rates to reflect variations in retail fuel and purchased power costs. On
January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject
to specified parameters and procedures, including the following:
•
APS will record deferrals for recovery or refund to the extent actual retail fuel
and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);
•
the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb
10% of the retail fuel and purchased power costs above the base fuel amount and may
retain 10% of the benefit from the retail fuel and purchased power costs that are below
the base fuel amount;
•
amounts to be recovered or refunded through the annual PSA adjustment are limited to
a cumulative plus or minus $0.004 per kWh over the life of the PSA;
•
the recoverable amount of annual retail fuel and purchased power costs through
current base rates and the PSA was originally capped at $776.2 million; however, the
ACC has removed the cap pending the ACC’s final ruling on APS’ pending request to have
the cap eliminated or substantially raised;
•
the PSA will remain in effect for a minimum five-year period, but the ACC may
eliminate the PSA at any time, if appropriate, in the event APS files a rate case
before the expiration of the five-year period (which APS did by filing the general rate
case noted above) or if APS does not comply with the terms of the PSA; and
•
APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor
rate has been set each year. The amount available for potential PSA surcharges will be
limited to the amount of accumulated deferrals through the prior year-end which are not
expected to be recovered through the annual adjustor or any PSA surcharges previously
approved by the ACC.
2006 PSA Annual Adjustor The effective date of the PSA’s annual adjustor is
February 1, and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective
February 1, 2006. The change in the adjustor rate represents a retail rate increase of
approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over
the twelve-month period beginning February 1, 2006.
Application for PSA Surcharges On February 2, 2006, APS filed with the ACC an application for
two separate surcharges under the PSA. The surcharges would recover approximately $60 million in
retail fuel and purchased power costs deferred by APS in 2005 under the PSA. The combined
surcharges would represent a temporary rate increase of approximately 2.6% during the overlapping
portion of the twelve-month recovery periods for the two surcharges. The other component of the
2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
discussed in the preceding paragraph. The first surcharge would recover approximately $15 million
over a twelve-month period, representing a temporary rate increase of approximately 0.66%, proposed
to begin with the date of the ACC’s decision in APS’ pending emergency interim rate case. The
second requested surcharge would recover approximately $45 million over a twelve-month period,
representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the
ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. The $45 million
of PSA deferrals represents replacement power costs associated with these outages.
Proposed Modifications to PSA (Requested In General Rate Case)
In its pending general rate case, APS has requested the following modifications to the PSA:
•
The $0.004 per kWh maximum adjustor rate over the life of the PSA would be
eliminated, while the $0.004 per kWh maximum annual change in the adjustor rate would
remain in effect;
•
The $776.2 million annual limit on the retail fuel and purchased power costs under
APS’ current base rates and the PSA would be removed or increased (although APS may
defer fuel and purchased power costs above $776.2 million per year pending the ACC’s
final ruling on APS’ pending request to have the cap eliminated or substantially
raised);
•
The current provision that APS is required to file a surcharge application with the
ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100
million would be eliminated, thereby giving APS flexibility in determining when a
surcharge filing should be made;
•
The costs of renewable energy and capacity costs attributable to purchased power
obtained through competitive procurement would be excluded from the existing 90/10
sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power
costs above the base fuel amount and retains 10% of the benefit from retail fuel and
purchased power costs that are below the base fuel amount; and
•
10% of any realized gains or losses resulting from APS’ hedges of Retail Fuel and
Power Costs would be retained or absorbed by APS before being subject to the 90/10
sharing provision under the PSA.
APS 2003 Rate Case
On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003.
In addition to the ACC’s approval of the PSA discussed under “Power Supply Adjustor” above, certain
key financial components of the order include:
•
APS received an annual retail rate increase of approximately 4.2%, which was
effective as of April 1, 2005. This increase does not include the impact of the PSA.
•
APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy,
with a net carrying value of approximately $850 million, and to rate base the
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a
mandatory rate base disallowance of approximately $150 million. Due to depreciation
and other miscellaneous factors, the actual disallowance was $139 million at December31, 2005. This transfer was completed on July 29, 2005. As a result, for financial
reporting purposes, APS recognized a one-time, after-tax net plant regulatory
disallowance of approximately $84 million in 2005.
•
Effective April 1, 2005, APS adopted longer service lives for certain depreciable
assets. This change is expected to have the effect of reducing annual depreciation
expense for financial reporting purposes by approximately $30 million. APS also
adopted longer service lives for the PWEC Dedicated Assets, which is expected to have
the effect of reducing annual depreciation expense for financial reporting purposes by
approximately $10 million.
Equity Infusions
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 consist 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 (see Note 22). Pinnacle West has made these equity infusions into APS.
Federal
In July 2002, the FERC adopted a price mitigation plan that constrains the price of
electricity in the wholesale spot electricity market in the western United States. The FERC
adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices
above the cap must be justified and are subject to potential refund.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are
for financial statements purposes. The tax effect of these differences is recorded as deferred
taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its
Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary
differences, primarily the allowance for equity funds used during construction. The regulatory
liability relates to excess deferred taxes resulting primarily from the reduction in federal income
tax rates as part of the Tax Reform Act of 1986. APS amortizes this amount 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 the 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. In 2002, we received an
income tax refund of approximately $115 million related to our 2001 federal consolidated income tax
return. The 2001 federal consolidated income tax return is currently under examination by the IRS.
As part of this ongoing examination, the IRS is reviewing this accounting method change and the
resultant deduction. During 2004 and again in 2005, the current income tax liability was
increased, with a
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
corresponding decrease to plant-related deferred tax liability, to reflect the expected
outcome of this audit. We do not expect the ultimate outcome of this examination to have a
material adverse impact on our financial position or results of
operations. We expect that it will have a negative impact on cash
flows.
The income tax liability accounts reflect the tax and interest associated with the most
probable resolution of all known and measurable tax exposures.
In 2004 and 2003, we resolved certain prior-year issues with the taxing authorities and
recorded tax benefits associated with tax credits and other reductions to income tax expense.
The components of income tax expense are as follows (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following chart compares pretax income from continuing operations at the 35% federal
income tax rate to income tax expense – continuing operations (dollars in thousands):
Deferred fuel and purchased power –
mark-to-market
11,923
—
Other
29,720
8,282
Pension liability
83,753
91,973
Deferred gain on Palo Verde Unit 2 sale
leaseback
17,868
19,816
Other
91,015
70,849
Total deferred tax assets
762,147
480,368
DEFERRED TAX LIABILITIES
Plant-related
(1,426,158
)
(1,516,174
)
Risk management and trading activities
(524,940
)
(146,037
)
Regulatory assets:
Deferred fuel and purchased power
(67,461
)
—
Other
(63,551
)
(54,767
)
Total deferred tax liabilities
(2,082,110
)
(1,716,978
)
Accumulated deferred income taxes – net
$
(1,319,963
)
$
(1,236,610
)
5. Lines of Credit and Short-Term Borrowings
Pinnacle West had committed lines of credit of $300 million at December 31, 2005 and December31, 2004, which were available either to support the issuance of up to $250 million in commercial
paper or to be used for bank borrowings, including issuance of letters of credit. The current
lines mature in December 2010. Pinnacle West had no outstanding borrowings at December 31, 2005
and December 31, 2004. Pinnacle West had approximately $11 million of letters of credit issued
under the line at December 31, 2005 ($7 million of which terminated as a result of the sale of
Silverhawk – see Note 22) and approximately $13 million of letters of credit issued under the line
at December 31, 2004. The commitment fees were 0.15% in 2005 and 0.175% in 2004. Pinnacle West
had no commercial paper borrowings outstanding at December 31, 2005 and 2004. All Pinnacle West
and APS bank lines of credit and commercial paper agreements are unsecured.
APS had committed lines of credit with various banks of $400 million at December 31, 2005 and
$325 million at December 31, 2004, which were available either to support the issuance of up to
$250 million in commercial paper or to be used for bank borrowings, including the
issuance of letters of credit. The current line matures in December 2010. The commitment
fees at December 31, 2005 and 2004 for these lines of credit were 0.11% and 0.15% per annum. APS
had no bank borrowings
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
outstanding under these lines of credit at December 31, 2005 and 2004. APS had approximately
$4.8 million of letters of credit issued under the line at December 31, 2005.
APS had no commercial paper borrowings outstanding at December 31, 2005 and 2004. By Arizona
statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by
the ACC.
SunCor had revolving lines of credit totaling $150 million at December 31, 2005 and $90
million at December 31, 2004. The commitment fees were 0.125% in 2005 and 2004. SunCor had $123
million outstanding at December 31, 2005 and $35 million outstanding at December 31, 2004. The
weighted-average interest rate was 5.93% at December 31, 2005 and 4.50% at December 31, 2004.
Interest was based on LIBOR plus 1.5% for 2005 and LIBOR plus 2% or prime plus 0.5% for 2004. The
balance is included in long-term debt on the Consolidated Balance Sheets at December 31, 2005 and
it was in short-term debt on the Consolidated Balance Sheets at December 31, 2004. SunCor had
other short-term loans in the amount of $16 million at December 31, 2005 and $36 million at
December 31, 2004. These loans are made up of multiple notes primarily with variable interest
rates based on LIBOR plus 2.25% and 2.50% or prime plus 1.75% at December 31, 2005 and LIBOR plus
2.5% at December 31, 2004.
6. Long-Term Debt
Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is
collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The
following table presents the components of long-term debt on the Consolidated Balance Sheets
outstanding at December 31, 2005 and 2004 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31,
Maturity
Interest
Dates (a)
Rates
2005
2004
APS
Pollution control bonds (b)
2024-2034
(c
)
$
565,855
$
565,860
Pollution control bonds with senior
notes
2029
5.05
%
90,000
90,000
Unsecured notes (d)
2005
6.25
%
—
100,000
Unsecured notes (e)
2005
7.625
%
—
300,000
Unsecured notes
2011
6.375
%
400,000
400,000
Unsecured notes
2012
6.50
%
375,000
375,000
Unsecured notes
2033
5.625
%
200,000
200,000
Unsecured notes
2015
4.650
%
300,000
300,000
Unsecured notes (e)
2014
5.80
%
300,000
300,000
Secured note
2014
6.00
%
1,745
1,900
Senior notes
2006
6.75
%
83,695
83,695
Senior notes (f)
2035
5.50
%
250,000
—
Unamortized discount and premium
(9,151
)
(7,968
)
Capitalized lease obligations
2006-2012
(g
)
8,179
9,854
Subtotal
2,565,323
2,718,341
SUNCOR
Notes payable
2006-2008
(h
)
129,040
15,467
Capitalized lease obligations
2005-2007
8.91
%
266
507
Subtotal
129,306
15,974
PINNACLE WEST
Senior notes (i)
2006
6.40
%
298,518
302,589
Unamortized discount and premium
(29
)
(143
)
Floating rate senior notes
2005
(j
)
—
165,000
Capitalized lease obligations
2005-2007
5.45
%
284
389
Subtotal
298,773
467,835
Total long-term debt
2,993,402
3,202,150
Less current maturities
384,947
617,165
TOTAL LONG-TERM DEBT LESS CURRENT
MATURITIES
$
2,608,455
$
2,584,985
(a)
This schedule does not reflect the timing of redemptions that may occur prior to
maturity.
(b)
On March 1, 2005, Maricopa County Arizona Pollution Control Corporation issued $164 million
of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were
issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds
are payable solely from revenues obtained from APS pursuant to a loan agreement between APS
and Maricopa County Arizona Pollution Control Corporation. These bonds are classified as
long-term debt on our Consolidated Balance Sheets.
(c)
The weighted-average rate was 3.25% at December 31, 2005 and 1.89% at December 31, 2004.
Changes in short-term interest rates would affect the costs associated with this debt.
(d)
On January 15, 2005, APS repaid its $100 million 6.25% notes due 2005. APS used cash on hand
to repay these notes.
(e)
On August 1, 2005, APS repaid $300 million of its 7.625% notes due 2005. APS used cash from
the issuance of $300 million 5.8% senior unsecured notes due June 30, 2014.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(f)
On August 22, 2005, APS issued $250 million of 5.50% senior notes dues 2035. A portion of
the proceeds from the sale of the notes was used for general corporate purposes and, on
October 3, 2005, the balance of the proceeds, along with cash on hand, was used to fund the
$500 million that APS was obligated to transfer to Pinnacle West Energy in connection with
APS’ acquisition of the PWEC Dedicated Assets.
SunCor had $123 million outstanding at December 31, 2005 under its revolving line of credit.
The weighted-average interest rate was 5.93% at December 31, 2005. The remaining amount of
approximately $6 million at December 31, 2005 was made up of multiple notes with variable
interest rates based on the lenders’ prime rates plus 0.25% or LIBOR plus 2.00%. There is
also a note at a fixed rate of 4.25%.
(i)
On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction
related to the $300 million 6.40% senior note. The transaction qualifies as a fair value
hedge under SFAS No. 133.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with
Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement
provides the terms under which Pinnacle West may offer up to
$200 million of its senior notes for
purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes
issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28,2006, Pinnacle West issued and sold to Prudential affiliates
$175 million aggregate principal
amount of its 5.91% Senior Notes, Series A, Due February 28, 2011 (the “Series A Notes”). Pinnacle
West will use the proceeds of the Series A Notes to repay at
maturity a portion of the $300 million
aggregate principal amount of its 6.40% Senior Notes due April 1, 2006 or for other general
corporate purposes.
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include a debt to capitalization ratio. 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 each
of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization cannot exceed 65%. At December 31, 2005, the ratio was approximately
49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a
minimum cash coverage of two times the interest requirements for APS. The interest coverage is
approximately 4 times under APS’ bank financing agreements as of December 31, 2005. 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.
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, in the event of a further rating downgrade, Pinnacle West and/or APS may be
subject to increased interest costs under certain financing agreements.
All of Pinnacle West’s bank 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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows principal payments due on Pinnacle West’s and APS’ total long-term
debt and capitalized lease requirements (dollars in millions):
Year
Pinnacle West
APS
2006
$
387
$
86
2007
1
1
2008
129
1
2009
1
1
2010
224
224
Thereafter
2,261
2,261
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2005, 2004 and
2003 is as follows (dollars in thousands):
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an
offering price of $42 per share, resulting in net proceeds of approximately $248
million. Pinnacle West used the net proceeds for general corporate purposes, including
making capital contributions to APS, which, in turn, used such funds to pay a portion
of the approximately $190 million purchase price to acquire the Sundance Plant and for
other capital expenditures incurred to meet the growing needs of APS’ service
territory.
(b)
Represents shares of common stock withheld from certain stock
awards for tax purposes.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and
its subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan
for all new employees in place of the defined benefit plan and, as of April 1, 2003, the plan was
offered as an alternative to the defined benefit plan for all existing employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive using information
about the participant. The pension plan covers nearly all employees. The supplemental excess
benefit retirement plan covers officers of the Company and highly compensated employees designated
for participation by the Board of Directors. Our employees do not contribute to the plans.
Generally, we calculate the benefits based on age, years of service and pay.
Pinnacle West also sponsors other postretirement benefits for the employees of Pinnacle West
and our subsidiaries. We provide medical and life insurance benefits to retired employees.
Employees must retire to become eligible for these retirement benefits, which are based on years of
service and age. For the medical insurance plans, retirees make contributions to cover a portion
of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the
right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date for its pension and other postretirement
benefit plans. The market-related value of our plan assets is their fair value at the measurement
date.
On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and
Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of
prescription drug cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the
accounting for the effects of the Act. Pinnacle West adopted FSP 106-2 retroactive to the
beginning of 2004. The effect of this was to reduce the accumulated postretirement benefit
obligation (APBO) at January 1, 2004 by $66 million, and net periodic cost for 2004 by $11 million,
as compared with the amount calculated without considering the effects of the subsidy.
The following table provides details of the plans’ benefit costs. Also included is the
portion of these costs charged to expense, including administrative
costs and excluding amounts capitalized as overhead construction or billed to
electric plant participants (dollars in
thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension
Other Benefits
2005
2004
2003
2005
2004
2003
Service cost-benefits
earned during the
period
$
45,027
$
41,207
$
37,662
$
20,913
$
17,557
$
15,858
Interest cost on benefit
obligation
87,189
81,873
76,951
34,223
29,488
30,163
Expected return on plan
assets
(88,403
)
(78,790
)
(65,046
)
(30,471
)
(24,773
)
(18,762
)
Amortization of:
Transition
(asset) obligation
(3,227
)
(3,227
)
(3,227
)
3,005
3,005
3,005
Prior service
cost (credit)
2,401
2,401
2,401
(125
)
(125
)
(125
)
Net actuarial
loss
19,810
17,946
18,135
9,243
7,414
9,714
Net periodic benefit cost
$
62,797
$
61,410
$
66,876
$
36,788
$
32,566
$
39,853
Portion of cost charged to
expense
$
26,375
$
25,792
$
30,094
$
15,451
$
13,678
$
17,934
APS share of costs charged to
expense
$
24,169
$
22,483
$
25,450
$
14,159
$
11,923
$
15,166
The following table shows the plans’ changes in the benefit obligations for the years 2005 and
2004 (dollars in thousands):
Pension
Other Benefits
2005
2004
2005
2004
Benefit obligation at January 1
$
1,454,244
$
1,307,628
$
536,213
$
540,181
Service cost
45,027
41,207
20,913
17,557
Interest cost
87,189
81,873
34,223
29,488
Benefit payments
(46,109
)
(45,195
)
(16,962
)
(14,332
)
Actuarial losses (gains)
55,717
68,731
11,291
(36,681
)
Benefit obligation at December 31
$
1,596,068
$
1,454,244
$
585,678
$
536,213
The following table shows the qualified pension plan and other benefit plan changes in the
fair value of plan assets for the years 2005 and 2004 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows a reconciliation of the funded status of the plans to the amounts
recognized on the Consolidated Balance Sheets as of December 31, 2005 and 2004 (dollars in
thousands):
Pension
Other Benefits
2005
2004
2005
2004
Funded status at December 31
$
(531,220
)
$
(471,962
)
$
(169,504
)
$
(184,129
)
Unrecognized net transition (asset)
obligation
(645
)
(3,873
)
21,034
24,039
Unrecognized prior service
cost (credit)
11,833
14,234
(1,296
)
(1,422
)
Unrecognized net actuarial
losses
426,991
375,980
170,011
158,271
Benefit (liability) asset
recognized in
the Consolidated Balance Sheets
$
(93,041
)
$
(85,621
)
$
20,245
$
(3,241
)
The following table shows the projected benefit obligation and the accumulated benefit
obligation for pension plans in excess of plan assets as of December 31, 2005 and 2004 (dollars in
thousands):
2005
2004
Projected benefit obligation
$
1,596,068
$
1,454,244
Accumulated benefit obligation
$
1,329,324
$
1,216,727
Less fair value of plan assets
1,064,848
982,282
Pinnacle West pension liability
$
264,476
$
234,445
APS share of pension liability
$
233,342
$
203,668
The following table shows the details related to benefits included on the Consolidated Balance
Sheets as of December 31, 2005 and 2004 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the other comprehensive income (loss) arising from the change in
additional minimum liability for the years ended December 31, 2005 and 2004 (dollars in thousands):
2005
2004
Increase in minimum liability included in other
comprehensive income – net of tax:
Pinnacle West consolidated
$
(15,489
)
$
(15,224
)
APS share
$
(15,045
)
$
(13,929
)
The following table shows the weighted-average assumptions used for both the pension and other
benefits to determine benefit obligations and net periodic benefit costs:
In selecting the pretax expected long-term rate of return on plan assets we consider past
performance and economic forecasts for the types of investments held by the plan. For the year
2006, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable
given our asset allocation in relation to historical and expected performance.
Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates
would have the following effects (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1% Increase
1% Decrease
Effect on other postretirement benefits
expense, after consideration of amounts
capitalized or billed to electric plant
participants
$
7
$
(6
)
Effect on service and interest cost
components of net periodic other
postretirement benefit costs
$
11
$
(9
)
Effect on the accumulated other
postretirement benefit obligation
$
100
$
(79
)
Plan Assets
Pinnacle West’s qualified pension plan asset allocation at December 31, 2005 and 2004 is as
follows:
Percentage of Plan Assets
at December 31,
Target Asset Allocation
2005
2004
Asset Category:
Equity securities
59
%
60
%
60
%
Fixed income
26
27
30
%
Other
15
13
10
%
Total
100
%
100
%
The Board of Directors has established an investment policy for the pension plan assets and
has delegated oversight of the plan assets to an Investment Management Committee. The investment
policy sets forth the objective of providing for future pension benefits by maximizing return
consistent with acceptable levels of risk. The primary investment strategies are diversification
of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West
securities, and external management of plan assets.
Pinnacle West’s other postretirement benefit plans’ asset allocation at December 31, 2005 and
2004, is as follows:
Percentage of Plan Assets
at December 31,
Target Asset Allocation
2005
2004
Asset Category:
Equity securities
69
%
71
%
70
%
Fixed income
26
23
27
%
Other
5
6
3
%
Total
100
%
100
%
The Investment Management Committee, described above, has also been delegated oversight of the
plan assets for the other postretirement benefit plans. The investment policy for other
postretirement benefit plans’ assets is similar to that of the pension plan assets described above.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contributions
The contribution to our pension plan in 2006 is estimated to be approximately $50 million.
The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately
$29 million. APS’ share is approximately 96% of both plans.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and
the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
Year
Pension
Other Benefits (a)
2006
$
52,675
$
16,340
2007
56,891
17,751
2008
62,263
19,166
2009
68,651
20,775
2010
75,273
22,847
Years 2011-2015
520,961
149,784
(a)
The expected future other benefit payments take into account the Medicare Part
D subsidy.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle
West and its subsidiaries. In 2005, costs related to APS’ employees represented 96% of the total
cost of this plan. In a defined contribution savings plan, the benefits a participant receives
result from regular contributions participants make to their own individual account. Under this
plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle
West stock. After a five year vesting period, participants have an option to transfer the Company
matching contributions out of the Pinnacle West Stock Fund to other investment funds within the
plan. At December 31, 2005, approximately 22% of total plan assets were in Pinnacle West stock.
Pinnacle West recorded expenses for this plan of approximately $6 million for 2005 and $5 million
for each of the years 2004 and 2003. APS recorded expenses for this plan of approximately $6
million in 2005, $5 million in 2004 and $5 million in 2003.
9. Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in
three separate sale leaseback transactions. APS accounts for these leases as operating leases.
The gain resulting from the transaction of approximately $140 million was deferred and is being
amortized to operations and maintenance expense over 29.5 years, the original term of the leases.
There are options to renew the leases and to purchase the property for
fair market value at the end of the lease terms. Rent expense is calculated on a straight-line
basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale
leaseback transactions.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other
items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $71 million in
2005, $69 million in 2004 and $67 million in 2003. APS’ lease expense was $58 million in 2005,
$57 million in 2004 and $66 million in 2003.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year
for the years 2006 to 2015.
Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases are
approximately as follows (dollars in millions):
Pinnacle West
Year
Consolidated
APS
2006
$
74
$
66
2007
73
65
2008
71
64
2009
68
62
2010
65
60
Thereafter
303
288
Total future lease commitments
$
654
$
605
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other
companies. Pinnacle West Energy shared ownership of Silverhawk, which was sold on January 10,2006. See Note 22. Our share of operations and maintenance expense related to these facilities is
included in the Consolidated Statements of Income. The following table shows APS’ interests in
those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2005
(dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Construction
Percent
Plant in
Accumulated
Work in
Owned
Service
Depreciation
Progress
Generating facilities:
Palo Verde Units 1 and 3
29.1
%
$
1,931,736
$
923,052
$
41,391
Palo Verde Unit 2 (see Note
9)
17.0
%
671,775
260,840
6,363
Four Corners Units 4 and 5
15.0
%
158,129
78,588
317
Navajo Generating Station
Units 1, 2 and 3
14.0
%
252,348
108,182
3,963
Cholla common facilities (a)
62.6
%(b)
87,165
38,832
2,109
Transmission facilities:
ANPP 500KV System
35.8
%(b)
81,117
22,829
815
Navajo Southern System
31.4
%(b)
29,809
13,273
6,813
Palo Verde – Yuma 500KV
System
23.9
%(b)
9,580
3,945
386
Four Corners Switchyards
27.5
%(b)
3,120
1,267
—
Phoenix – Mead System
17.1
%(b)
36,020
3,770
—
Palo Verde – Estrella 500KV
System
55.5
%(b)
74,243
2,023
—
Harquahala
80.0
%(b)
—
—
112
(a)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common
facilities at Cholla are jointly-owned.
(b)
Weighted average of interests.
11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with
the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste
Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent
nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and
it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the
United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a
decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin
accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities,
including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against
the DOE in the Court of Federal Claims.
APS has existing fuel storage pools at Palo Verde and is operating a facility for on-site dry
storage of spent nuclear fuel. With the existing storage pools and the addition of the new
facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by
Palo Verde to allow its continued operation through the term of the operating license for each Palo
Verde unit.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Although some low-level waste has been stored on-site in a low-level waste facility, APS is
currently shipping low-level waste to off-site facilities. APS currently believes interim
low-level waste storage methods are or will be available for use by Palo Verde to allow its
continued operation and to safely store low-level waste until a permanent disposal facility is
available.
APS currently estimates it will incur $147 million (in 2005 dollars) over the life of Palo
Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At
December 31, 2005, APS had a regulatory asset of $6 million that represents amounts spent for
on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that
was effective April 1, 2005.
APS believes that scientific and financial aspects of the issues of spent nuclear fuel and
low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges
that their ultimate resolution in a timely fashion will require political resolve and action on
national and regional scales which APS is less able to predict. APS expects to vigorously protect
and pursue its rights related to this matter.
Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $300 million
and the balance by an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, APS could be assessed
retrospective premium adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $101 million, subject to an annual limit of $15 million per
incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo
Verde units, APS’ maximum potential assessment per incident for all three units is approximately
$88 million, with an annual payment limitation of approximately $13 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for
property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75
billion, a substantial portion of which must first be applied to stabilization and decontamination.
APS has also secured insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen accidental outage of any of
the three units. The property damage, decontamination, and replacement power coverages are
provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments
under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum
amount of retrospective assessments APS could incur under the current NEIL policies totals $17.8
million. The insurance coverage discussed in this and the previous paragraph is subject to certain
policy conditions and exclusions.
Fuel and Purchased Power Commitments
Pinnacle West and APS are parties to various fuel and purchased power contracts with terms
expiring between 2006 and 2025 that include required purchase provisions. Pinnacle
West estimates the contract requirements to be approximately $316 million in 2006; $239
million
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
in 2007; $180 million in 2008; $139 million in 2009; $117 million in 2010 and $908 million
thereafter. APS estimates the contract requirements to be approximately $265 million in 2006; $179
million in 2007; $152 million in 2008; $139 million in 2009; $117 million in 2010 and $896 million
thereafter. However, these amounts may vary significantly pursuant to certain provisions in such
contracts that permit us to decrease required purchases under certain circumstances.
Of the various fuel and purchased power contracts mentioned above some of those contracts have
take-or-pay provisions. The contracts APS has for the supply of its coal supply have take-or-pay
provisions. The current take-or-pay coal contracts have terms that expire in 2024.
The following table summarizes our actual and estimated take-or-pay commitments (dollars in
millions):
Actual
Estimated (a)
2003
2004
2005
2006
2007
2008
2009
2010
Thereafter
Coal take-or-pay
commitments
$
43
$
41
$
48
$
67
$
69
$
78
$
93
$
73
$
611
(a)
Total take-or-pay commitments are approximately $991 million. The total net
present value of these commitments is approximately $598 million.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation.
APS’ coal mine reclamation obligation was $75 million at December 31, 2005 and $61 million at
December 31, 2004 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.
California Energy Market Issues and Refunds in the Pacific Northwest
FERC
In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot
market transactions in California during a specified time frame. APS was a seller and a purchaser
in the California markets at issue, and to the extent that refunds are ordered, APS should be a
recipient as well as a payor of such amounts. The FERC is still considering the evidence and
refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit
issued a decision, concluding that the FERC may not order refunds from entities that are not within
the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s
calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of
refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing
sellers in the California markets to demonstrate that its refund methodology results in an overall
revenue shortfall for their transactions in the relevant markets over a specified time frame. More
than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these
sellers. Correspondingly, this will reduce the recovery of total refunds in the California
markets. We currently believe the refund claims at FERC will have no material adverse impact on
our financial position, results of operations, cash flow or liquidity.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 19, 2002, the State of California filed a complaint with the FERC alleging that
wholesale sellers of power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the present under
market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any
rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the
FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an
order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit
market-based rates, but rejected the FERC’s claim that it was without authority to consider
retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements
of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the
FERC for further proceedings. Several of the intervenors in this appeal filed a petition for
rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted
upon, and the outcome of the further proceedings cannot be predicted at this time.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific
Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.
This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC
ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the
specific refund amounts due in California, we do not expect that the resolution of these issues, as
to the amounts alleged in the proceedings, will have a material adverse impact on our financial
position, results of operations or cash flows.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets,
prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated
that a significant number of entities who participated in the California markets during the
2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
that allegedly violated certain provisions of the Independent System Operator tariff. After
reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the
claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on
January 22, 2004. Certain parties have sought rehearing of this order, and that request is
pending.
California Civil Energy Market Litigation
APS has been named in a lawsuit regarding wholesale contracts in California, which, after
moving to state court, has been removed to the federal court for a second time. The First Amended
Complaint alleges basically that the contracts entered into were the result of an unfair and
unreasonable market, in violation of California unfair competition laws. The PX has filed a
lawsuit against the State of California regarding the seizure of forward contracts and the State
has filed a cross complaint against APS and numerous other PX participants. Various motions
continue to be filed, and we currently believe these claims will have no material adverse impact on
our financial position, results of operations, cash flow or liquidity.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Construction Program
Consolidated capital expenditures in 2006 are estimated to be (dollars in millions):
APS
$
649
SunCor
232
Other
6
Total
$
887
Natural Gas Supply
Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural
Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium
through December 31, 2005.
On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the
1996 settlement but maintained the cost responsibility provisions agreed to by parties to that
settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter
the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain
the cost responsibility provisions of the settlement, a party has sought appellate review and is
seeking to reallocate the costs responsibility associated with the changed contractual obligations
in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9,2003 order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual
capacity cost could be increased by approximately $3 million per year, for the period September
2003 through December 2005. This appeal has been stayed pending further consideration by the FERC.
Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on
June 30, 2005, which proposed new rates and new services to become effective on January 1, 2006.
The FERC suspended the effectiveness of these new rates and services until January 1, 2006 and made
the rates subject to refund pending the outcome of a hearing. As part of an ongoing technical
conference and settlement discussions, El Paso has agreed to postpone the implementation and the
associated cost impact of the new services until April 1, 2006. APS will be able to evaluate the
cost impact of these new services once the FERC issues a final order on the technical conference.
APS cannot currently predict the outcome of this matter.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United
States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project,
several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company
and other defendants, and citing various claims in connection with the renegotiations of the coal
royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and
the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt
River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained
a favorable coal royalty rate by improperly influencing the outcome of a federal administrative
process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages,
treble damages, punitive damages of not less than $1 billion, and the ejection
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary
coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
In January, 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of
St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other
things, a declaration that the participants “are obligated to reimburse Peabody for any royalty,
tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the
Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the
litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.
Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating
the soil, water or air. Those who generated, transported or disposed of hazardous substances at a
contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and
severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers
APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in
Phoenix, Arizona. APS has facilities that are within this superfund site. APS and Pinnacle West
have agreed with the EPA to perform certain investigative activities of the APS facilities within
OU3. Because the investigation has not yet been completed and ultimate remediation requirements
are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which
may be required.
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary
course of business, including but not limited to environmental matters related to the Clean Air
Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial position, results of
operations or liquidity.
12. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other
generation, transmission and distribution assets. The Palo Verde asset retirement obligation
primarily relates to final plant decommissioning. This obligation is based on the NRC’s
requirements for disposal of radiated property or plant and agreements APS reached with the ACC for
final decommissioning of the plant. The non-nuclear generation asset retirement obligations
primarily relate to requirements for removing portions of those plants at the end of the plant life
or lease term.
Some of APS’ transmission and distribution assets have asset retirement obligations
because they are subject to right of way and easement agreements that require final removal. These
agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS
cannot reasonably estimate the fair value of the asset retirement obligation related to such
distribution and transmission assets.
Additionally, APS has aquifer
protection permits for some of its generation sites that require
the closure of certain facilities at those sites. The generation
sites are strategically located to serve APS native load customers.
Management expects to continuously use the sites and, thus, cannot
estimate a potential closure date. The asset retirement
obligations associated with our non-regulated assets are immaterial.
To fund the costs APS expects to incur to decommission Palo Verde, APS established
external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in
fixed- income debt securities and domestic equity securities. APS applies the provisions of
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for
investments in decommissioning trust funds, and classifies these investments as available for sale.
As a result, we record the decommissioning trust funds at their fair value on our Consolidated
Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in
accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the
offsetting amount of unrealized gains (losses) on investment securities in other regulatory
liabilities/assets. The following table summarizes the fair value of APS’ nuclear
decommissioning trust fund assets at December 31, 2005 and December 31, 2004 (dollars in millions):
Total
Total
Unrealized
Unrealized
Fair Value
Gains
Losses
2005
Equity securities
$
150
$
50
$
—
Debt securities
144
3
1
Total
$
294
$
53
$
1
2004
Equity securities
$
135
$
45
$
—
Debt securities
133
6
—
Total
$
268
$
51
$
—
The costs of securities sold are determined on the basis of specific identification. The
following table sets forth approximate gains and losses and
proceeds from the sale of securities by the nuclear decommissioning
trust funds (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following schedule shows the change in our asset retirement obligations for 2005 and 2004
(dollars in millions):
2005
2004
Asset retirement obligation at the
beginning of year
$
252
$
234
Changes attributable to:
Liabilities settled
(2
)
(1
)
Accretion expense
17
17
Estimated cash flow revisions
2
2
Asset retirement obligation at the
end of year
$
269
$
252
In accordance with SFAS No. 71, APS accrues for removal costs for its regulated utility
assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in
Note 1.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Selected Quarterly Financial Data (Unaudited)
The following note presents quarterly financial information for 2005 and 2004. We are
disclosing originally reported amounts and revised amounts in each period for the reclassification
of certain commercial properties at SunCor and Silverhawk as discontinued operations (see Note 22).
Consolidated quarterly financial information for 2005 and 2004 is as follows (dollars in
thousands, except per share amounts):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Earnings per share:
2005 Quarter Ended
March 31,
June 30,
September 30,
December 31,
As
originally reported — Basic earnings per share
(a):
Income from continuing operations
$
0.26
$
0.89
$
0.86
$
0.24
Net income
0.27
0.28
1.05
0.22
After SunCor
and Silverhawk reclassifications — Basic
earnings per share (a):
Income from continuing operations
0.32
0.88
0.86
0.24
Net income
0.27
0.28
1.05
0.22
As
originally reported — Diluted earnings per
share (a):
Income from continuing operations
0.26
0.88
0.86
0.24
Net income
0.27
0.28
1.05
0.22
After
SunCor and Silverhawk reclassifications —
Diluted earnings per share (a):
Income from continuing operations
$
0.32
$
0.88
$
0.86
$
0.24
Net income
0.27
0.28
1.05
0.22
2004 Quarter Ended
March 31,
June 30,
September 30,
December 31,
As
originally reported — Basic earnings per share
(a):
Income from continuing operations
$
0.34
$
0.78
$
1.14
$
0.32
Net income
0.34
0.80
1.15
0.37
After SunCor
and Silverhawk reclassifications — Basic
earnings per share (a):
Income from continuing operations
0.33
0.81
1.14
0.41
Net income
0.34
0.80
1.15
0.37
As
originally reported — Diluted earnings per
share (a):
Income from continuing operations
0.34
0.78
1.14
0.32
Net income
0.34
0.79
1.15
0.37
After
SunCor and Silverhawk reclassifications —
Diluted earnings per share (a):
Income from continuing operations
$
0.33
$
0.81
$
1.14
$
0.41
Net income
0.34
0.79
1.15
0.37
(a)
The difference between originally reported and revised basic and diluted earnings per
share related to the sale of certain commercial properties at SunCor and the sale of
Silverhawk (see Note 22), which changed reported amounts for the quarters in 2005 and 2004.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. Fair Value of Financial Instruments
Pinnacle West and APS believe that the carrying amounts of their cash equivalents are
reasonable estimates of their fair values at December 31, 2005 and 2004 due to their short
maturities.
Pinnacle West and APS hold investments in debt securities for purposes other than trading. We
believe that the carrying amounts of these investments represent reasonable estimates of their fair
values at December 31, 2005 and 2004 due to the short-term reset of interest rates.
We also hold investments in fixed income and domestic equity securities for purposes other
than trading. The December 31, 2005 and 2004 fair values of such investments, which we determine
by using quoted market prices, approximate their carrying amount. For further information, see
disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
On December 31, 2005, the carrying value of our long-term debt for Pinnacle West, excluding
capitalized lease obligations and interest rate swap (see “Fair Value Hedges” – Note 18), was $2.99
billion, with an estimated fair value of $3.00 billion. See Note 18 for fair value of the interest
rate swap. The carrying value of our long-term debt for Pinnacle West (excluding capitalized lease
obligations) was $3.19 billion on December 31, 2004, with an estimated fair value of $3.30 billion.
On December 31, 2005, the carrying value of APS’ long-term debt (excluding capitalized lease
obligations) was $2.56 billion, with an estimated fair value of $2.57 billion. The carrying value
of APS’ long-term debt (excluding capital lease obligations) was $2.71 billion on December 31,2004, with an estimated fair value of $2.81 billion. The fair value estimates are based on quoted
market prices of the same or similar issues.
15. Earnings Per Share
The following table presents earnings per weighted-average common share outstanding for the
years ended December 31, 2005, 2004 and 2003:
2005
2004
2003
Basic earnings per share:
Income from continuing operations
$
2.31
$
2.70
$
2.47
Income (loss) from discontinued
operations
(0.48
)
(0.04
)
0.17
Earnings per share – basic
$
1.83
$
2.66
$
2.64
Diluted earnings per share:
Income from continuing operations
$
2.31
$
2.69
$
2.47
Income (loss) from discontinued
operations
(.49
)
(0.03
)
0.16
Earnings per share – diluted
$
1.82
$
2.66
$
2.63
Dilutive stock options increased average common shares outstanding by approximately 106,000
shares in 2005, 135,000 shares in 2004 and 140,000 shares in 2003. Total average common shares
outstanding for the purposes of calculating diluted earnings per share were 96,589,949 shares in
2005, 91,532,473 shares in 2004 and 91,405,134 shares in 2003.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options to purchase 495,367 shares of common stock were outstanding at December 31, 2005 but
were not included in the computation of diluted earnings per share because the options’ exercise
price was greater than the average market price of the common shares. Options to purchase shares
of common stock that were not included in the computation of diluted earnings per share were
1,058,616 at December 31, 2004 and 2,291,646 at December 31, 2003.
16. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle
West and our subsidiaries.
The 2002 Long-Term Incentive Plan (2002 plan) allows Pinnacle West to grant performance
shares, stock ownership incentive awards and non-qualified and performance-accelerated stock
options to key employees. We have reserved 6 million shares of common stock for issuance under the
2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards
and stock ownership incentive awards. The plan also provides for the granting of new non-qualified
stock options at a price per share not less than the fair market value of the common stock at the
time of grant. The stock options vest over three years, unless certain performance criteria are
met, which can accelerate the vesting period. The term of the option cannot be longer than 10
years and the option cannot be repriced during its term.
The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new
options will be granted under the plan. Options vested one-third of the grant per year beginning
one year after the date the option is granted and expire ten years from the date of the grant. The
1994 Plan also provided for the granting of any combination of shares of restricted stock, stock
appreciation rights or dividend equivalents.
In the third quarter of 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123. In accordance with the transition
requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002
stock grants. In prior years, we recognized stock compensation expense based on the intrinsic
value method allowed in APB No. 25.
In addition, see Note 2 for discussion of a new standard on share based payments (SFAS No.
123R).
Total stock-based compensation cost, including restricted stock, performance shares, stock
options, and stock ownership incentives was $6 million in 2005, $8 million in 2004 and $6 million
in 2003 for Pinnacle West. APS’ share was $5 million in 2005, $6 million in 2004 and $3 million in
2003.
The following table is a summary of the status of outstanding stock options under our equity
incentive plans as of December 31, 2005, 2004 and 2003 and changes during the years ending on those
dates:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the amount and weighted-average grant date fair value of
stock compensation awards granted, other than options, during the years ended December 31, 2005,
2004 and 2003:
2005 Grant
2004 Grant
2003 Grant
2005
Date Fair
2004
Date Fair
2003
Date Fair
Shares
Value
Shares
Value
Shares
Value
Restricted stock
—
$
—
4,000
$
37.68
(a)
4,000
$
32.20
(a)
Performance share
awards
215,300
41.36
(b)
215,285
37.85
(b)
119,085
32.29
(b)
Stock ownership
incentive awards
11,322
44.13
(b)
9,015
40.29
(b)
—
—
(a)
Restricted stock priced at the average of the high and low market price on the
grant date.
(b)
Performance shares and stock ownership incentive awards priced at the closing
market price on the grant date.
17. Business Segments
We have three principal business segments (determined by products, services and the regulatory
environment):
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electricity service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution;
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities; and
•
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services’
commodity-related energy services.
Financial data for 2005, 2004 and 2003 by business segments is provided as follows (dollars in
millions):
Income from continuing
operations before income taxes
240
73
11
4
328
Income taxes
70
28
3
2
103
Income from continuing operations
170
45
8
2
225
Income from discontinued
operations — net of income
taxes of $9 (see Note 22)
(b)(c)
—
10
1
5
16
Net income
$
170
$
55
$
9
$
7
$
241
Capital expenditures
$
686
$
72
$
9
$
—
$
767
(a)
Effective April 1, 2005, revenues of approximately $40 million from Off-System
Sales, which were previously reported in the marketing and trading segment, began being
reported in the regulated electricity segment in accordance with the retail rate case
settlement.
(b)
The marketing and trading segment relates to the sale and operations of
Silverhawk. See Note 22.
(c)
The other segment relates to the sale and operations of NAC. See Note 22.
(d)
The other segment includes a $35 million pre-tax ($21 million after-tax) gain
related to the sale of a limited partnership interest in the Phoenix Suns in 2004.
18. Derivative and Energy Trading Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage
risks associated with these market fluctuations by utilizing various instruments that qualify as
derivatives, including exchange-traded futures and options and over-the-counter forwards, options
and swaps. As part of our overall risk management program, we use such instruments to hedge our
exposure to changes in interest rates and to hedge purchases and sales of electricity, fuels, and
emissions allowances and credits. As of December 31, 2005, we hedged certain exposures to the
price variability of commodities for a maximum of 3.25 years. The changes in market value of such
contracts have a high correlation to price changes in the hedged transactions. In addition,
subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading
activities intended to profit from market price movements.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We recognize all derivatives, except those which qualify for a scope exception, as either
assets or liabilities on the balance sheet and measure those instruments at fair value in
accordance with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the
physical delivery of purchase and sale quantities transacted in the normal course of business
qualify for the normal purchase and sales exception and are accounted for under the accrual method
of accounting. Changes in the fair value of derivative instruments are recognized periodically in
income unless certain hedge criteria are met. For cash flow hedges, the effective portion of
changes in the fair value of the derivative are recognized in common stock equity (as a component
of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative
as well as the offsetting loss or gain on the hedged item associated with the hedged risk are
recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on
forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value
of an asset or liability.
For its regulated operations, APS defers for future rate recovery 90% of gains and losses on
derivatives that would otherwise be recognized in income. 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.
We assess hedge effectiveness both at inception and on a continuing basis. Hedge
effectiveness is related to the degree to which the derivative contract and the hedged item are
correlated. It is measured based on the relative changes in fair value between the derivative
contract and the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or
the amount by which the derivative contract and the hedged commodity are not directly correlated,
is recognized immediately in net income.
Both non-trading and trading derivatives that do not qualify for a scope exception are
classified as assets and liabilities from risk management and trading activities on the
Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge
accounting treatment. Non-trading derivatives, or any portion thereof that are not effective
hedges, are adjusted to fair value through income. Realized gains and losses related to
non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in
revenue or purchased power and fuel expense as an offset to the related item being hedged when the
underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted
transaction will not occur, we discontinue the use of hedge accounting and recognize in income the
unrealized gains and losses that were previously recorded in other comprehensive income (loss). In
the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain
in other comprehensive income (loss), and are recognized in income when the underlying transaction
impacts earnings.
All gains and losses (realized and unrealized) on trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the Consolidated Statements
of Income on a net basis. Trading contracts that do not meet the definition of a derivative are
accounted for on an accrual basis with the associated revenues and costs recorded at the time the
contracted commodities are delivered or received.
In the electricity business, some contracts to purchase energy are netted against other
contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the
same terms (quantities and delivery points) and for which power does not flow. We net these
book-outs,
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
which reduces both revenues and fuel and purchased power costs in our Consolidated
Statement of Income, but this does not impact our financial condition, net income or cash flows.
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Consolidated Statements
of Income, after consideration of amounts deferred under the PSA, for the years ended December 31,2005, 2004 and 2003 are comprised of the following (dollars in thousands):
2005
2004
2003
Gains (losses) on the ineffective
portion of
derivatives qualifying for hedge
accounting
$
14,289
$
(1,568
)
$
8,237
Gains from the change in options’
time value excluded from measurement
of effectiveness
620
185
181
Gains from the discontinuance of
cash flow hedges
556
1,137
—
During 2006, we estimate that a net gain of $216 million before income taxes will be
reclassified from accumulated other comprehensive income as an offset to the effect of market price
changes for the related hedged transactions. To the extent the amounts are eligible for inclusion
in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no
effect on earnings (see Note 3).
Our assets and liabilities from risk management and trading activities are presented in two
categories, consistent with our business segments.
The following table summarizes our assets and liabilities from risk management and trading
activities at December 31, 2005 and 2004 (dollars in thousands):
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was a liability of $123 million at December 31, 2005 and $9 million
at December 31, 2004 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against our open positions on
certain energy-related contracts. Collateral provided to counterparties was $6 million at December31, 2005 and $1 million at December 31, 2004, and is included in other current assets on the
Consolidated Balance Sheets. Collateral provided to us by counterparties was $216 million at
December 31, 2005 and $24 million at December 31, 2004, and is included in other current
liabilities on the Consolidated Balance Sheets.
Fair Value Hedges
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on
our $300 million 6.4% Senior Notes. The purpose of these hedges is to protect against significant
fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully
effective with any resulting gains or losses on the derivative offset by a similar loss or gain
amount on the underlying fair value of debt. The fair value of the interest rate swaps was a loss
of $1.5 million at December 31, 2005 and is included in other current liabilities with the
corresponding offset in current maturities of long-term debt on the Consolidated Balance Sheets.
The fair value of the interest rate swaps was $2.6 million at December 31, 2004 and is included in
investments and other assets with the corresponding offset in long-term debt less current
maturities on the Consolidated Balance Sheets.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. We
have risk management and trading contracts with many counterparties. Our risk management
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
process assesses and monitors the financial exposure of all counterparties. Despite the fact
that the great majority of counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could default, resulting
in a material impact on consolidated earnings for a given period. Counterparties in the portfolio
consist principally of financial institutions, major energy companies, municipalities and local
distribution companies. We maintain credit policies that we believe minimize overall credit risk
to within acceptable limits. Determination of the credit quality of our counterparties is based
upon a number of factors, including credit ratings and our evaluation of their financial condition.
In many contracts, we employ collateral requirements and standardized agreements that allow for
the netting of positive and negative exposures associated with a single counterparty. Valuation
adjustments are established representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 “Derivative Accounting” for a discussion of our credit valuation
adjustment policy.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for the years 2005, 2004
and 2003 (dollars in thousands):
2005
2004
2003
Other income:
Investment gains — net (a)
$
752
$
38,256
$
3,649
Interest income
14,793
6,770
4,412
SunCor (b)
2,623
4,458
24,740
Asset sales
3,187
3,026
618
Miscellaneous
2,005
779
2,144
Total other income
$
23,360
$
53,289
$
35,563
Other expense:
Non-operating costs (c)
$
(13,589
)
$
(15,524
)
$
(14,959
)
Asset dispositions
(9,759
)
(1,212
)
(1,522
)
Miscellaneous
(3,368
)
(4,604
)
(4,093
)
Total other expense
$
(26,716
)
$
(21,340
)
$
(20,574
)
(a)
Includes a $35 million gain ($21 million after tax) related to the sale of a limited
partnership interest in the Phoenix Suns in 2004.
(b)
Primarily related to the sale at SunCor of a land interest and profit participation agreement
in 2003 for $18 million. Includes joint venture and other non-operating income.
(c)
As defined by the FERC, includes below-the-line non-operating utility costs (primarily
community relations and other costs excluded from utility rate recovery).
20. Variable-Interest Entities
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and
lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in
accordance with GAAP. See Note 9 for further information about the sale leaseback transactions.
We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate
them.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2005, APS would have been required to assume
approximately $234 million of debt and pay the equity participants approximately $185 million.
SunCor has certain land development arrangements that are required to be consolidated under
FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests
reflected in our Consolidated Balance Sheets related to these arrangements were approximately $34
million at December 31, 2005 and 2004.
21. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our unregulated subsidiaries. Our parental guarantee for Pinnacle West Energy relates to a
purchased power agreement. Our credit support instruments enable APS Energy Services to offer
commodity energy and energy-related products. Non-performance or non-payment under the original
contract by our unregulated 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 guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral
provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate
terms of our guarantees and surety bonds for each subsidiary at December 31, 2005 are as follows
(dollars in millions):
Guarantees
Surety Bonds
Term
Term
Amount
(in years)
Amount
(in years)
Parental:
Pinnacle West Energy
$
5
1
$
—
—
APS Energy Services
20
1
65
1
Total
$
25
$
65
At December 31, 2005, we had entered into approximately $37 million of letters of credit which
supported transmission agreements related to Silverhawk. These letters of credit terminated as a
result of the sale of Silverhawk. See Note 22 for a discussion of the sale of Silverhawk. At
December 31, 2005, Pinnacle West had approximately $4 million of letters of credit related to
workers’ compensation expiring in 2006. We intend to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At December 31, 2005, approximately $200 million of letters of credit were outstanding
to support existing pollution control bonds of approximately $200 million. The letters of credit
are available to fund the payment of principal and interest of such debt obligations and expire in
2010. APS has also entered into approximately $98 million of letters of credit to support certain
equity
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the
Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally,
APS has approximately $5 million of letters of credit related to counterparty collateral
requirements expiring in 2006. APS intends to provide from either existing or new facilities for
the extension, renewal or substitution of the letters of credit to the extent required.
We enter into agreements that include indemnification provisions relating to liabilities
arising from or related to certain of our agreements. APS has agreed to indemnify the equity
participants and other parties in the Palo Verde sale leaseback transactions with respect to
certain tax matters. Generally, a maximum obligation is not explicitly stated in the
indemnification provisions and therefore, the overall maximum amount of the obligation under such
indemnification provisions cannot be reasonably estimated. Based on historical experience and
evaluation of the specific indemnities, we do not believe that any material loss related to such
indemnification provisions is likely.
22. Discontinued Operations
Silverhawk (marketing and trading segment) – In June 2005, we entered into an agreement to
sell our 75% interest in Silverhawk to NPC. The sale was completed on January 10, 2006. As a
result of this sale, we recorded a loss from discontinued operations of approximately $56 million
($91 million pretax) in the second quarter of 2005. The amounts in the chart below also include
the revenues and expenses related to the operations of Silverhawk. The assets held for sale at
December 31, 2005 were $203 million, of which property, plant and equipment accounted for
approximately $197 million.
Concurrent with the execution of the agreement to sell our interest in Silverhawk, GenWest and
NPC also entered into a Purchase Power Agreement (“PPA”) providing for the sale of GenWest’s share
of the capacity and output of Silverhawk to NPC. The PPA commenced on October 1, 2005 and was
terminated on January 10, 2006, the date of the sale under the Purchase Agreement.
SunCor (real estate segment) – In 2005, SunCor sold commercial properties, which are required
to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in
accordance with SFAS No. 144. As a result of the sales, we recorded a gain from discontinued
operations of approximately $15 million ($25 million pretax) in the third quarter of 2005.
NAC (other segment) – In 2004, we sold our investment in NAC, and in 2005 we recognized a gain
of $4 million ($6 million pretax) in connection with the sale that had previously been subject to
contingencies.
The following table provides revenue, income (loss) before income taxes and after-tax income
classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the
years ended December 31, 2005, 2004 and 2003 (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2005
2004
2003
Revenue:
Silverhawk
$
95
$
61
$
1
SunCor – commercial operations
9
21
71
NAC
—
34
58
Total revenue
$
104
$
116
$
130
Income (loss) before taxes:
Silverhawk (a)
$
(111
)
$
(18
)
$
—
SunCor – commercial operations
28
6
17
NAC
6
7
8
Total income (loss) before taxes
$
(77
)
$
(5
)
$
25
Income (loss) after taxes:
Silverhawk
$
(67
)
$
(12
)
$
1
SunCor – commercial operations
17
4
10
NAC
3
4
5
Total income (loss) after taxes
$
(47
)
$
(4
)
$
16
(a)
Income before income taxes includes an interest expense allocation, net of
capitalized amounts, of $13 million in 2005 and $6 million in 2004. The allocation was
based on Pinnacle West’s weighted-average interest rate applied to the net property,
plant and equipment.
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rules 13(a)-15(f), for Arizona Public
Service Company. Management conducted an evaluation of the effectiveness of our internal control
over financial reporting based on the framework in Internal Control – Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation
under the framework in Internal Control – Integrated Framework, our management concluded that our
internal control over financial reporting was effective as of December 31, 2005. Our management’s
assessment of the effectiveness of our internal control over financial reporting as of December 31,2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm,
as stated in their report which is included herein and relates also to the Company’s financial
statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”)
as of December 31, 2005 and 2004, and the related statements of income, changes in common stock
equity, and cash flows for each of the three years in the period ended December 31, 2005. Our
audits also included the financial statement schedule listed in the Index at Item 15. We also have
audited management’s assessment, included in the accompanying Management’s Report on Internal
Control Over Financial Reporting, that the Company maintained effective internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company’s management is responsible for these financial statements and financial
statement schedule, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting. Our
responsibility is to express an opinion on these financial statements and financial statement
schedule, an opinion on management’s assessment, and an opinion on the effectiveness of 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 audit of 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, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles and
that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of the Company as of December 31, 2005 and 2004, and the results
of its operations and its cash flows for each of the three years in the period ended December 31,2005, in conformity with accounting principles generally accepted in the United States of America.
Also, in our opinion, the financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material respects, the information
set forth therein. Also, in our opinion, management’s assessment that the Company maintained
effective internal control over financial reporting as of December 31, 2005, is fairly stated, in
all material respects, based on the criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in
our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2005, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
Certain notes to Arizona Public Service Company’s financial statements are combined with the
notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are
the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements,
the majority of which also relate to Arizona Public Service Company’s financial statements. In
addition, listed below are the supplemental notes which are required disclosures for Arizona Public
Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s
Consolidated Notes.
Pinnacle West offers stock-based compensation plans for officers and key employees of APS. In
2002, APS began applying the fair value method of accounting for stock-based compensation, as
provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the
transition requirements of SFAS No. 123, APS applied the fair value method prospectively, beginning
with 2002 stock grants. In prior years, APS recognized stock compensation expense based on the
intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for
Stock Issued to Employees.”
The following chart compares APS’ net income and stock compensation expense to what those
items would have been if APS had recorded stock compensation expense based on the fair value method
for all stock grants through 2005 (dollars in thousands):
2005
2004
2003
Net income, as reported
$
170,479
$
199,627
$
180,937
Add: Stock compensation
expense included in reported
net income (net of tax)
3,102
3,353
2,035
Deduct: Total stock
compensation expense
determined under fair
value method (net of tax)
(3,102
)
(3,713
)
(3,024
)
Pro forma net income
$
170,479
$
199,267
$
179,948
S-2. Income Taxes
APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West
allocates income taxes to APS, it is done based on APS’ taxable income or loss alone.
Certain assets and liabilities are reported differently for income tax purposes than they are
for financial statements purposes. The tax effect of these differences is recorded as deferred
taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its
Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary
differences, primarily the allowance for equity funds used during construction. The regulatory
liability relates to excess deferred taxes resulting primarily from the reduction in federal income
tax rates as part of the Tax Reform Act of 1986. APS amortizes this amount as the differences
reverse.
As a result of a change in IRS guidance, Pinnacle West claimed a tax deduction related to an
APS tax accounting method change on the 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. In 2002, Pinnacle West
received an income tax refund of approximately $115 million related to our 2001 federal
consolidated income tax
return. The 2001 federal consolidated income tax return is currently under examination by the IRS.
As part of this ongoing examination, the IRS is reviewing this accounting method change and the
resultant deduction. During 2004 and again in 2005, the current income tax liability was
increased, with a corresponding decrease to plant-related deferred tax liability, to reflect the
expected outcome of this audit. APS does not expect the ultimate outcome of this examination to
have a material adverse impact on its financial position or results
of operations. We expect that it will have a negative impact on cash
flows.
The income tax liability accounts reflect the tax and interest associated with the most
probable resolution of all known and measurable tax exposures.
In 2004 and 2003, we resolved certain prior-year issues with the taxing authorities and
recorded tax benefits associated with tax credits and other reductions to income tax expense.
The components of APS’ income tax expense are as follows (dollars in thousands):
S-3. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2005 and 2004 is as follows (dollars in thousands):
2005 Quarter Ended,
2005
March 31,
June 30,
September 30,
December 31,
Total
Operating revenues
$
441,292
$
588,757
$
748,348
$
492,396
$
2,270,793
Operations and maintenance
142,294
138,314
149,198
162,135
591,941
Operating income
58,743
95,321
174,415
53,134
381,613
Net income
27,045
63,998
61,093
18,343
170,479
2004 Quarter Ended,
2004
March 31,
June 30,
September 30,
December 31,
Total
Operating revenues
$
441,102
$
569,658
$
700,512
$
485,849
$
2,197,121
Operations and maintenance
125,912
126,871
143,338
144,156
540,277
Operating income
67,050
83,604
129,682
48,645
328,981
Net income
34,429
54,934
95,192
15,072
199,627
S-4. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk
management program, APS uses various commodity instruments that qualify as derivatives to hedge
purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31,2005, APS hedged certain exposures to these risks for a maximum of 3.25 years.
Cash Flow Hedges
The changes in the fair value of APS’ hedged positions included in the APS Statements of
Income, after consideration of amounts deferred under the PSA, for the years ended December 31,2005, 2004 and 2003 are comprised of the following (dollars in thousands):
2005
2004
2003
Gains (losses) on the ineffective
portion of
derivatives qualifying for hedge
accounting
$
14,452
$
(1,570
)
$
7,033
Gains from the change in options
time value excluded from measurement
of effectiveness
620
185
181
Gains from the discontinuance of
cash flow hedges
473
575
—
During 2006, APS estimates that a net gain of $158 million before income taxes will be
reclassified from accumulated other comprehensive income as an offset to the effect of market price
changes for the related hedged transactions. To the extent the amounts are eligible for inclusion
in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no
effect on earnings (see Note 3).
APS’ assets and liabilities from risk management and trading activities are presented in two
categories:
•
Regulated Electricity – non-trading derivative instruments that hedge APS’ purchases
and sales of electricity and fuel for its Native Load requirements; and
•
Marketing and Trading – both non-trading and trading derivative instruments.
The following table summarizes APS’ assets and liabilities from risk management and trading
activities at December 31, 2005 and 2004 (dollars in thousands):
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was a liability of $123 million at December 31, 2005 and $9 million
at December 31, 2004 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against APS’ open positions on
certain energy-related contracts. No collateral was provided to counterparties at December 31,2005 or at December 31, 2004. Collateral provided to us by counterparties was $175 million at
December 31, 2005 and $6 million at December 31, 2004, and is included in other current liabilities
on the Balance Sheets.
S-5. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for the years ended
December 31, 2005, 2004 and 2003 (dollars in thousands):
As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and other costs excluded from utility rate recovery).
From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s
subsidiaries. The following table summarizes the amounts included in the APS Statements of Income
and Balance Sheets related to transactions with affiliated companies (dollars in millions):
Electric revenues include sales of electricity to affiliated companies at contract prices.
Purchased power includes purchases of electricity from affiliated companies at contract prices.
APS purchases electricity from and sells electricity to APS Energy Services; however, these
transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held
for Trading Purposes’ As Defined in EITF Issue No. 2-3.”
Intercompany receivables primarily include amounts related to the intercompany sales of
electricity. Intercompany payables primarily include amounts related to the intercompany purchases
of electricity. Intercompany receivables and payables are generally settled on a current basis in
cash.
The December 31, 2004 intercompany receivable included a $500 million loan that APS made to
Pinnacle West Energy. This loan was repaid in May 2005.
APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net
carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate
base value of $700 million, which resulted in a mandatory rate base disallowance of approximately
$150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was
$139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result,
for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory
disallowance of approximately $84 million in 2005. In connection
with the transfer, APS recorded a $500
million intercompany payable to Pinnacle West Energy. On October 3, 2005, APS settled the
intercompany payable.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
The term “disclosure controls and procedures” means controls and other procedures of a company
that are designed to ensure that information required to be disclosed by a company in the reports
that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C.
78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in
the SEC’s rules and forms. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be disclosed by a company
in the reports that it files or submits under the Exchange Act is accumulated and communicated to a
company’s management, including its principal executive and principal financial officers, or
persons performing similar functions, as appropriate to allow timely decisions regarding required
disclosure.
Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer
and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure
controls and procedures as of December 31, 2005. Based on that evaluation, Pinnacle West’s Chief
Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s
disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December31, 2005. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have
concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) Management’s Annual Reports on Internal Control Over Financial Reporting
Reference is made to “Management’s Report on Internal Control Over Financial Reporting
(Pinnacle West Capital Corporation)” on page 67 of this report and “Management’s Report on
Internal Control Over Financial Reporting (Arizona Public Service
Company)” on page 126 of this
report.
(c) Attestation Reports of the Registered Public Accounting Firm
Reference
is made to “Report of Independent Registered Public Accounting
Firm” on page 68 of
this report and “Report of Independent Registered Public
Accounting Firm” on page 127 of this
report on the internal control over financial reporting of Pinnacle West and APS, respectively.
(d) Changes In Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to
the process of a company that is designed to provide reasonable assurance regarding the reliability
of
financial reporting and the preparation of financial statements for external purposes in
accordance with GAAP.
No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during
the fiscal quarter ended December 31, 2005 that materially affected, or is reasonably likely to
materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF PINNACLE WEST
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate
Governance,”“Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting
Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to
be held on May 17, 2006 (the “2006 Proxy Statement”) and to the Supplemental Item — “Executive
Officers of Pinnacle West” in Part I of this report.
Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to
professional employees in the areas of finance, accounting, internal audit, energy risk management,
marketing and trading financial control, tax, investor relations, and treasury and also includes
Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and
officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of
Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com.
Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure
of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by
posting such information on Pinnacle West’s website.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate
Governance — How are directors compensated?”; “Performance Graph”; and “Executive Compensation” in
the 2006 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management
and Large Shareholders?” in the 2006 Proxy Statement.
Securities Authorized For Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2005 with respect to our
compensation plans and individual compensation arrangements under which our equity securities were
authorized for issuance.
Equity Compensation Plan Information
Number of securities
Number of
remaining available for
securities to be
Weighted-average
future issuance under
issued upon exercise
exercise price of
equity compensation
of outstanding
outstanding
plans (excluding
options, warrants
options, warrants
securities reflected in
and rights
and rights
column (a))
Plan category
(a)
(b)
(c)
Equity compensation
plans approved
by security
holders
1,695,772
$
39.65
4,245,671
Equity compensation
plans not
approved by
security
holders
—
—
145,100
Total
1,695,772
$
39.65
4,390,771
Equity Compensation Plans Approved By Security Holders
The Company has four equity compensation plans that were approved by its shareholders: the
Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may
be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan, under which no new
options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under
which no stock awards may be granted; and the Pinnacle West Capital Corporation 2002 Long-Term
Incentive Plan. See Note 16 for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000
Director Equity Plan (the “2000 Plan”), for which the approval of shareholders was not required.
Number of Shares Subject to the 2000 Plan. The total number of shares of the
Company’s common stock granted under the 2000 Plan may not exceed 200,000. In the case of a
significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan
provides for adjustment of the above limit, the number of shares to be awarded automatically to
eligible non-employee directors and the number of shares of the Company’s common stock non-employee
directors are required to own to receive an annual grant of common stock under the 2000 Plan.
Eligibility for Participation. Only non-employee directors may participate in the
2000 Plan. A non-employee director is an individual who is a director of the Company but who is
not also an employee of the Company or any of its subsidiaries.
Terms of Awards. The 2000 Plan provides for: (1) annual grants of common stock to
eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee
directors and (3) grants of non-qualified stock options to eligible non-employee directors.
Annual Grants of Stock
Each individual who is a non-employee director as of July 1 of a calendar year, and who meets
requirements of ownership of the Company’s common stock set forth below, will receive 1,100 shares
of the Company’s common stock for such calendar year. In the first calendar year in which a
non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900
shares of the Company’s common stock as of December 31 of the same calendar year to receive a grant
of 1,100 shares of the Company’s common stock. If the non-employee director owns 900 shares of
common stock as of June 30, he or she will receive a grant of 1,100 shares of common stock as of
July 1 of the same calendar year. If the non-employee director does not own 900 shares of the
Company’s common stock as of June 30, but acquires the necessary shares on or before December 31 of
the same year, he or she will receive a grant of 1,100 shares of common stock within a reasonable
time after the Company verifies that the requisite number of shares has been acquired. In each
subsequent year, the number of shares of the Company’s common stock the non-employee director must
own to receive a grant of 900 shares of common stock will increase by 1,100 shares, until reaching
a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the
requisite number of shares of the Company’s common stock as of June 30 of the relevant calendar
year.
Discretionary Grants of Stock
The Human Resources Committee of the Board of Directors administers the 2000 Plan and may
grant shares of the Company’s common stock to non-employee directors in its discretion. No
discretionary grants of common stock have been made under the 2000 Plan.
Grants of Non-qualified Stock Options
The Committee can grant non-qualified stock options under the 2000 Plan. The terms and the
conditions of the option grant, including the exercise price per share, which may not be less than
fair market value on the date of grant, will be set by the Committee in a written award agreement.
The Committee will determine the time or times at which any such options may be exercised in whole
or in part. The Committee will also determine the performance or other conditions, if any, that
must be satisfied before all or part of an option may be exercised. Any such options granted to a
participant will expire on the tenth anniversary date of the date of grant, unless the option is
earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the
applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company
director for any reason, including death or disability, any such options held by that participant
will expire on the second anniversary of the date on which the participant ceased to be a Company
director, unless otherwise provided in the applicable award agreement. Unless the Committee
provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise
alienated, other than by will, the laws of descent and distribution, or under any other
circumstances allowed by the Committee. No options have been granted under the 2000 Plan.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management
and Large Shareholders?”; “Does the Company Have Any
Related Party Transactions to Disclose?”; “Executive Compensation — Human Resources Committee Interlocks and
Insider Participation” and “What are the Company’s
Defined Benefit Plans — Employment and
Change-in-Control Agreement” in the 2006 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
Reference is hereby made to “Audit Matters — What fees were paid to our independent
registered public accountants in 2005 and 2004?” and “- What are the Audit Committee’s pre-approval policies?” in the
2006 Proxy Statement.
APS
The
following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP,
for the last two fiscal years:
Type of Service
2004
2005
Audit Fees (1)
$
1,910,089
$
2,167,319
Audit-Related Fees (2)
318,750
33,899
Tax Fees (3)
1,559,928
1,025
(1)
The aggregate fees billed for services rendered for the audit of annual financial statements
and for review of financial statements included in Forms 10-Q.
(2)
The aggregate fees billed for assurance services that are reasonably related to the
performance of the audit or review of the financial statements that are not included in Audit
Fees reported above, which primarily consist of fees for Sarbanes-Oxley Section 404 readiness.
(3)
The aggregate fees billed primarily for investment tax credit services, tax compliance and
tax planning.
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be
provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman
of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by
the independent public accountants if the services are not expected to cost more than $50,000. The
Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled
meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the
Audit Committee.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
The documents listed below are being filed or have previously been filed on behalf of Pinnacle
West or APS and are incorporated herein by reference from the documents indicated and made a part
hereof. Exhibits not identified as previously filed are filed herewith.
Agreement, dated
March 21, 1994,
relating to the
filing of
instruments
defining the
rights of holders
of APS long-term
debt not in excess
of 10% of APS’
total assets
4.1 to APS’ 1993 Form 10-K Report, File
No. 1-4473
Specimen
Certificate of
Pinnacle West
Capital Corporation
Common Stock, no
par value
4.2 to Pinnacle West’s 1988 Form 10-K
Report, File No. 1-8962
3-31-89
4.24
Pinnacle West
Agreement, dated
March 29, 1988,
relating to the
filing of
instruments
defining the rights
of holders of
long-term debt not
in excess of 10% of
the Company’s total
assets
4.1 to Pinnacle West’s 1987 Form 10-K
Report, File No. 1-8962
Amended and
Restated Rights
Agreement, dated as
of March 26, 1999,
between Pinnacle
West Capital
Corporation and
BankBoston, N.A.,
as Rights Agent,
including (i) as
Exhibit A thereto
the form of Amended
Certificate of
Designation of
Series A
Participating
Preferred Stock of
Pinnacle West
Capital
Corporation, (ii)
as Exhibit B
thereto the form of
Rights Certificate
and (iii) as
Exhibit C thereto
the Summary of
Right to Purchase
Preferred Shares
Amendment No. 4 to
the Decommissioning
Trust Agreement
(PVNGS Unit 1),
dated as of
December 19, 2003
10.3 to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
3-15-04
10.2
Pinnacle West
APS
Amendment No. 7 to
the Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of
December 19, 2003
10.4 to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
3-15-04
10.3
Pinnacle West
APS
Amendment No. 4 to
the Decommissioning
Trust Agreement
(PVNGS Unit 3),
dated as of
December 19, 2003
10.5 to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
3-15-04
10.4
Pinnacle West
APS
Fourth Amendment to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.6 to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
3-15-04
10.5
Pinnacle West
APS
Pinnacle West
Capital Corporation
Supplement Excess
Benefit Retirement
Plan, amended and
restated as of
January 1, 2003
10.7 to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
Two separate
Decommissioning
Trust Agreements
(relating to PVNGS
Units 1 and 3,
respectively), each
dated July 1, 1991,
between APS and
Mellon Bank, N.A.,
as Decommissioning
Trustee
10.2 to APS’ September 1991 Form 10-Q
Report, File No. 1-4473
11-14-91
10.7
Pinnacle West
APS
Amendment No. 1 to
Decommissioning
Trust Agreement
(PVNGS Unit 1),
dated as of
December 1, 1994
10.1 to APS’ 1994 Form
10- K Report, File No. 1-4473
3-30-95
10.8
Pinnacle West
APS
Amendment No. 1 to
Decommissioning
Trust Agreement
(PVNGS Unit 3),
dated as of
December 1, 1994
10.2 to APS’ 1994 Form
10-K Report, File No. 1-4473
3-30-95
10.9
Pinnacle West
APS
Amendment No. 2 to
APS Decommissioning
Trust Agreement
(PVNGS Unit 1)
dated as of July 1,
1991
10.4 to APS’ 1996 Form
10-K Report , File No. 1-4473
3-28-97
10.10
Pinnacle West
APS
Amendment No. 2 to
APS Decommissioning
Trust Agreement
(PVNGS Unit 3)
dated as of July 1,
1991
10.6 to APS’ 1996 Form
10-K Report, File No. 1-4473
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2)
dated as of January31, 1992, among
APS, Mellon Bank,
N.A., as
Decommissioning
Trustee, and State
Street Bank and
Trust Company, as
successor to The
First National
Bank of Boston, as
Owner Trustee under
two separate Trust
Agreements, each
with a separate
Equity Participant,
and as Lessor under
two separate
Facility Leases,
each relating to an
undivided interest
in PVNGS Unit 2
10.1 to Pinnacle West’s 1991 Form 10-K
Report, File No. 1-8962
3-26-92
10.12
Pinnacle West
APS
First Amendment to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of
November 1, 1992
10.2 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
10.13
Pinnacle West
APS
Amendment No. 2 to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of
November 1, 1994
10.3 to APS’ 1994 Form
10-K Report, File No. 1-4473
3-30-95
10.14
Pinnacle West
APS
Amendment No. 3 to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of January31, 1992
10.1 to APS’ June 1996 Form 10-Q Report,
File No. 1-4473
Amendment No. 4 to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2)
dated as of January31, 1992
APS 10.5 to APS’ 1996 Form 10-K Report,
File No. 1-4473
3-28-97
10.16
Pinnacle West
APS
Amendment No. 5 to
the Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of June30, 2000
10.1 to Pinnacle West’s March 2002 Form
10-Q Report, File No. 1-8962
5-15-02
10.17
Pinnacle West
APS
Amendment No. 3 to
the Decommissioning
Trust Agreement
(PVNGS Unit 1),
dated as of March18, 2002
10.2 to Pinnacle West’s March 2002 Form
10-Q Report, File No. 1-8962
5-15-02
10.18
Pinnacle West
APS
Amendment No. 6 to
the Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of March18, 2002
10.3 to Pinnacle West’s March 2002 Form
10-Q Report, File No. 1-8962
5-15-02
10.19
Pinnacle West
APS
Amendment No. 3 to
the Decommissioning
Trust Agreement
(PVNGS Unit 3),
dated as of March18, 2002
10.4 to Pinnacle West’s March 2002 Form
10-Q Report, File No. 1-8962
5-15-02
10.20
Pinnacle West
APS
Asset Purchase and
Power Exchange
Agreement dated
September 21, 1990
between APS and
PacifiCorp, as
amended as of
October 11, 1990
and as of July 18,
1991
10.1 to APS’ June 1991 Form 10-Q Report,
File No. 1-4473
Long-Term Power
Transaction
Agreement dated
September 21, 1990
between APS and
PacifiCorp, as
amended as of
October 11, 1990,
and as of July 8,
1991
10.2 to APS’ June 1991 Form 10-Q Report,
File No. 1-4473
8-8-91
10.22
Pinnacle West
APS
Amendment No. 1
dated April 5, 1995
to the Long-Term
Power Transaction
Agreement and Asset
Purchase and Power
Exchange Agreement
between PacifiCorp
and APS
10.3 to APS’ 1995 Form
10-K Report, File No. 1-4473
3-29-96
10.23
Pinnacle West
APS
Restated
Transmission
Agreement between
PacifiCorp and APS
dated April 5, 1995
10.4 to APS’ 1995 Form
10-K Report, File No. 1-4473
3-29-96
10.24
Pinnacle West
APS
Contract among
PacifiCorp, APS and
United States
Department of
Energy Western Area
Power
Administration,
Salt Lake Area
Integrated Projects
for Firm
Transmission
Service dated May5, 1995
10.5 to APS’ 1995 Form
10-K Report, File No. 1-4473
3-29-96
10.25
Pinnacle West
APS
Reciprocal
Transmission
Service Agreement
between APS and
PacifiCorp dated as
of March 2, 1994
10.6 to APS’ 1995 Form
10-K Report, File No. 1-4473
Contract, dated
July 21, 1984, with
DOE providing for
the disposal of
nuclear fuel and/or
high -level
radioactive waste,
ANPP
10.31 to Pinnacle West’s Form S-14
Registration Statement, File No. 2-96386
3-13-85
10.27
Pinnacle West
APS
Indenture of Lease
with Navajo Tribe
of Indians, Four
Corners Plant
5.01 to APS’ Form S-7 Registration
Statement, File No. 2-59644
9-1-77
10.28
Pinnacle West
APS
Supplemental and
Additional
Indenture of Lease,
including
amendments and
supplements to
original lease with
Navajo Tribe of
Indians, Four
Corners Plant
5.02 to APS’ Form S-7 Registration
Statement, File No. 2-59644
9-1-77
10.29
Pinnacle West
APS
Amendment and
Supplement No. 1 to
Supplemental and
Additional
Indenture of Lease
Four Corners, dated
April 25, 1985
10.36 to Pinnacle West’s Registration
Statement on Form 8-B Report, File No.
1-8962
7-25-85
10.30
Pinnacle West
APS
Application and
Grant of
multi-party
rights-of-way and
easements, Four
Corners Plant Site
5.04 to APS’ Form S-7 Registration
Statement, File No. 2-59644
9-1-77
10.31
Pinnacle West
APS
Application and
Amendment No. 1 to
Grant of
multi-party
rights-of-way and
easements, Four
Corners Power Plant
Site dated April
25, 1985
10.37 to Pinnacle West’s Registration
Statement on Form 8-B, File No. 1-8962
Application and
Grant of Arizona
Public Service
Company rights-
of-way and
easements, Four
Corners Plant Site
5.05 to APS’ Form S-7 Registration
Statement, File No. 2-59644
9-1-77
10.33
Pinnacle West
APS
Four Corners
Project Co-Tenancy
Agreement Amendment
No. 6
10.7 to Pinnacle West’s 2000 Form 10-K
Report, File No. 1-8962
3-14-01
10.34
Pinnacle West
APS
Application and
Amendment No. 1 to
Grant of Arizona
Public Service
Company
rights-of-way and
easements, Four
Corners Power Plant
Site dated April
25, 1985
10.38 to Pinnacle West’s Registration
Statement on Form 8-B, File No. 1-8962
7-25-85
10.35
Pinnacle West
APS
Indenture of Lease,
Navajo Units 1, 2,
and 3
5(g) to APS’ Form S-7 Registration
Statement, File No. 2-36505
3-23-70
10.36
Pinnacle West
APS
Application of
Grant of
rights-of-way and
easements, Navajo
Plant
5(h) to APS Form S-7 Registration
Statement, File No. 2-36505
3-23-70
10.37
Pinnacle West
APS
Water Service
Contract Assignment
with the United
States Department
of Interior, Bureau
of Reclamation,
Navajo Plant
5(l) to APS’ Form S-7 Registration
Statement, File No. 2-394442
Arizona Nuclear
Power Project
Participation
Agreement, dated
August 23, 1973,
among APS Salt
River Project
Agricultural
Improvement and
Power District,
Southern California
Edison Company,
Public Service
Company of New
Mexico, El Paso
Electric Company,
Southern California
Public Power
Authority, and
Department of Water
and Power of the
City of Los
Angeles, and
amendments 1-12
thereto
10. 1 to APS’ 1988 Form
10-K Report, File No. 1-4473
3-8-89
10.39
Pinnacle West
APS
Amendment No. 13,
dated as of April
22, 1991, to
Arizona Nuclear
Power Project
Participation
Agreement, dated
August 23, 1973,
among APS, Salt
River Project
Agricultural
Improvement and
Power District,
Southern California
Edison Company,
Public Service
Company of New
Mexico, El Paso
Electric Company,
Southern California
Public Power
Authority, and
Department of Water
and Power of the
City of Los Angeles
10.1 to APS’ March 1991 Form 10-Q
Report, File No. 1-4473
Amendment No. 14 to
Arizona Nuclear
Power Project
Participation
Agreement, dated
August 23, 1973,
among APS, Salt
River Project
Agricultural
Improvement and
Power District,
Southern California
Edison Company,
Public Service
Company of New
Mexico, El Paso
Electric Company,
Southern California
Public Power
Authority, and
Department of Water
and Power of the
City of Los Angeles
99.1 to Pinnacle West’s June 2000 Form
10-Q Report, File No. 1-8962
8-14-00
10.41c
Pinnacle West
APS
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, in its
capacity as Owner
Trustee, as Lessor,
and APS, as Lessee
4.3 to APS’ Form S-3 Registration
Statement, File No. 33-9480
10-24-86
10.42c
Pinnacle West
APS
Amendment No. 1,
dated as of
November 1, 1986,
to Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, in its
capacity as Owner
Trustee, as Lessor,
and APS, as Lessee
10.5 to APS’ September 1986 Form 10-Q
Report by means of Amendment No. 1 on
December 3, 1986 Form 8, File No. 1-4473
Amendment No. 2
dated as of June 1,
1987 to Facility
Lease dated as of
August 1, 1986
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as
Lessor, and APS, as
Lessee
10.3 to APS’ 1988 Form
10-K Report, File No. 1-4473
3-8-89
10.44c
Pinnacle West
APS
Amendment No. 3,
dated as of March17, 1993, to
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as
Lessor, and APS, as
Lessee
10.3 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
10.45
Pinnacle West
APS
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
capacity as Owner
Trustee, as Lessor,
and APS, as Lessee
10.1 to APS’ November 18, 1986 Form 8-K
Report, File No. 1-4473
Amendment No. 1,
dated as of August
1, 1987, to
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as
Lessor, and APS, as
Lessee
4.13 to APS’ Form S-3 Registration
Statement No. 33-9480 by means of
August 1, 1987 Form 8-K Report, File No.
1-4473
8-24-87
10.47
Pinnacle West
APS
Amendment No. 2,
dated as of March17, 1993, to
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as
Lessor, and APS, as
Lessee
10.4 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
10.48b
Pinnacle West
APS
Pinnacle West
Capital Corporation
Supplemental Excess
Benefit Retirement
Plan, as amended
and restated, dated
December 18, 2003
Trust for the
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company and
SunCor Development
Company Deferred
Compensation Plans
dated August 1,1996
10.14 to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.50b
Pinnacle West
APS
First Amendment
dated December 7,1999 to the Trust
for the Pinnacle
West Capital
Corporation,
Arizona Public
Service Company and
SunCor Development
Company Deferred
Compensation Plans
10.15 to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.51b
Pinnacle West
APS
Directors’ Deferred
Compensation Plan,
as restated,
effective January
1, 1986
10.1 to APS’ June 1986 Form 10-Q Report,
File No. 1-4473
8-13-86
10.52b
Pinnacle West
APS
Second Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan,
effective as of
January 1, 1993
10.2 to APS’ 1993 Form
10-K Report, File No. 1-4473
3-30-94
10.53b
Pinnacle West
APS
Third Amendment to
the Arizona Public
Service Company
Directors’ Deferred
Compensation Plan,
effective as of May1, 1993
10.1 to APS’ September 1994 Form 10-Q
Report, File No. 1-4473
Fourth Amendment
to the Arizona
Public Service
Company Directors
Deferred
Compensation Plan effective as of January 1, 1999
10.8 to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.55b
Pinnacle West
APS
Arizona Public
Service Company
Deferred
Compensation Plan,
as restated,
effective January
1, 1984, and the
second and third
amendments thereto,
dated December 22,
1986, and December
23, 1987
respectively
10.4 to APS’ 1988 Form
10-K Report, File No. 1-4473
3-8-89
10.56b
Pinnacle West
APS
Third Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan,
effective as of
January 1, 1993
10.3 to APS’ 1993 Form
10-K Report, File No. 1-4473
3-30-94
10.57b
Pinnacle West
APS
Fourth Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan
effective as of May1, 1993
10.2 to APS’ September 1994 Form 10-Q
Report, File No. 1-4473
11-10-94
10.58b
Pinnacle West
APS
Fifth Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan effective January 1, 1997
10.3 to APS’ 1996 Form 10-K Report, File
No. 1-4473
3-28-97
10.59b
Pinnacle West
APS
Sixth Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan effective January 1, 2001
10.8 to Pinnacle West’s 2000 Form 10-K
Report, File No. 1-8962
3-14-01
10.60b
Pinnacle West
APS
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
as amended and
restated effective
January 1, 1996
10.10 to APS’ 1995 Form 10-K Report,
File No. 1-4473
First Amendment
effective as of
January 1, 1999, to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.7 to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.62b
Pinnacle West
APS
Second Amendment
effective January1, 2000 to the
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.10 to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.63b
Pinnacle West
APS
Third Amendment to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.3 to Pinnacle West’s March 2003 Form
10-Q Report, File No. 1-8962
5-15-03
10.64b
Pinnacle West
APS
Fourth Amendment to the Pinnacle
West Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan, effective January 1, 2003.
10.65b
Pinnacle West
APS
Schedules of William J. Post and
Jack E. Davis to Arizona Public Service Company Deferred Compensation
Plan, as amended.
10.2 to Pinnacle West Form 10-K Report,
File No. 1-8962
Pinnacle West
Capital Corporation
2002 Long-Term
Incentive Plan
10.5 to Pinnacle West’s 2002 Form 10-K
Report
3-31-03
10.81b
Pinnacle West
Pinnacle West
Capital Corporation
2000 Director
Equity Plan
99.1 to Pinnacle West’s Registration
Statement on Form S-8 (No. 333-40796),
File No. 1-8962
7-3-00
10.82
Pinnacle West
APS
Agreement No. 13904
(Option and
Purchase of
Effluent) with
Cities of Phoenix,
Glendale, Mesa,
Scottsdale, Tempe,
Town of Youngtown,
and Salt River
Project
Agricultural
Improvement and
Power District,
dated April 23,
1973
10.3 to APS’ 1991 Form
10-K Report, File No. 1-4473
3-19-92
10.83
Pinnacle West
APS
Territorial
Agreement between
the Company and
Salt River Project
10.1 to APS’ March 1998 Form 10-Q
Report, File No. 1-4473
5-15-98
10.84
Pinnacle West
APS
Power Coordination
Agreement between
the Company and
Salt River Project
10.2 to APS’ March 1998 Form 10-Q
Report, File No. 1-4473
Stock Ownership
Incentive Agreement
under Pinnacle West
Capital Corporation
2002 Long-Term
Incentive Plan
10.99 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.91bd
Pinnacle West
APS
Performance Share Agreement
under the Pinnacle West
Capital Corporation
2002 Long-Term
Incentive Plan
10.92 bd
Pinnacle West
APS
Summary of 2006 CEO
Variable Incentive
Plan and Officer
Variable Incentive
Plan
10.93
Pinnacle West
APS
Amended and
Restated
Reimbursement
Agreement among
APS, the Banks
party thereto, and
JPMorgan Chase
Bank, as
Administrative
Agent and Issuing
Bank, dated as of
July 22, 2002
10.100 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.94
Pinnacle West
APS
Three-Year Credit
Agreement dated as
of May 21, 2004
between APS as
Borrower, and the
banks, financial
institutions and
other institutional
lenders and initial
issuing banks
listed on the
signature pages
thereof
10.101 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.95
Pinnacle West
APS
Amended and
Restated Five-Year
Credit Agreement
dated as of
December 9, 2005
between APS, as
Borrower, Citibank,
N.A., as Agent, and
the lenders and
other parties
thereto
10.96
Pinnacle West
$200,000,000 Senior
Notes Uncommitted
Master Shelf
Agreement dated as
of February 28,2006
Amended and
Restated Credit
Agreement dated as
of December 9, 2005
among Pinnacle West
Capital
Corporation, as
Borrower, JPMorgan
Chase Bank, N.A.,
as Agent, and the
other agent parties
thereto
10.98
Pinnacle West
APS
Agreement between
Pinnacle West
Energy Corporation
and Arizona Public
Service Company for
Transportation and
Treatment of
Effluent by and
between Pinnacle
West Energy
Corporation and APS
dated as of the
10th day
of April, 2001
10.102 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.99
Pinnacle West
APS
Agreement for the
Transfer and Use of
Wastewater and
Effluent by and
between APS, SRP
and PWE dated June1, 2001
10.103 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.100
Pinnacle West
APS
Agreement for the
Sale and Purchase
of Wastewater
Effluent dated
November 13, 2000,
by and between the
City of Tolleson,
Arizona, APS and
SRP
10.104 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.101
Pinnacle West
APS
Operating Agreement
for the
Co-Ownership of
Wastewater Effluent
dated November 16,2000 by and between
APS and SRP
10.105 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
Agreement for the
Sale and Purchase
of Wastewater
Effluent with City
of Tolleson and
Salt River
Agricultural
Improvement and
Power District,
dated June 12,
1981, including
Amendment No. 1
dated as of
November 12, 1981
and Amendment No. 2
dated as of June 4,
1986
Navajo Project Co-Tenancy Agreement
dated as of March 23, 1976, and Supplement No. 1 thereto
dated as of October 18, 1976, Amendment No. 1 dated as of
July 5, 1988, and Amendment No. 2 dated as of
June 14, 1996, Amendment No. 3 dated as of
February 11, 1997; Amendment No. 4 dated as of
January 21, 1997; Amendment No. 5 dated as of
January 23, 1998; Amendment No. 6 dated as of July 31,1998.
10.108
Pinnacle West
APS
Navajo Project Participation
Agreement dated as of September 30, 1969, and Amendment and
Supplement No. 1 dated as of January 16, 1970, and
Coordinating Committee Agreement No. 1 dated as of September 31, 1971.
12.1
Pinnacle West
Ratio of Earnings
to Fixed Charges
12.2
APS
Ratio of Earnings
to Fixed Charges
12.3
Pinnacle West
Ratio of Earnings
to Combined Fixed Charges
and Preferred Stock Dividend Requirements
21.1
Pinnacle West
Subsidiaries of
Pinnacle West
23.1
Pinnacle West
Consent of Deloitte
& Touche LLP
23.2
APS
Consent of Deloitte
& Touche LLP
31.1
Pinnacle West
Certificate of
William J. Post,
Chief Executive
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
Certificate of
Donald E. Brandt,
Chief Financial
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
31.3
APS
Certificate of Jack
E. Davis, Chief
Executive Officer,
pursuant to Rule
13a-14(a) and Rule
15d-14(a) of the
Securities Exchange
Act, as amended
31.4
APS
Certificate of
Donald E. Brandt,
Chief Financial
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
32.1
Pinnacle West
Certification of
Chief Executive
Officer and Chief
Financial Officer,
pursuant to 18
U.S.C. Section
1850, as adopted
pursuant to Section
906 of the
Sarbanes-Oxley Act
of 2002
32.2
APS
Certification of
Chief Executive
Officer and Chief
Financial Officer,
pursuant to 18
U.S.C. Section
1850, as adopted
pursuant to Section
906 of the
Sarbanes-Oxley Act
of 2002
Collateral Trust
Indenture among
PVNGS II Funding
Corp., Inc., APS
and Chemical Bank,
as Trustee
4.2 to APS’ 1992 Form 10-K Report, File
No. 1-4473
3-30-93
99.2
Pinnacle West
APS
Supplemental
Indenture to
Collateral Trust
Indenture among
PVNGS II Funding
Corp., Inc., APS
and Chemical Bank,
as Trustee
4.3 to APS’ 1992 Form 10-K Report, File
No. 1-4473
3-30-93
99.3c
Pinnacle West
APS
Participation
Agreement, dated as
of August 1, 1986,
among PVNGS Funding
Corp., Inc., Bank
of America National
Trust and Savings
Association, State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee, APS, and
the Equity
Participant named
therein
28.1 to APS’ September 1992 Form 10-Q
Report, File No. 1-4473
Amendment No. 1
dated as of
November 1, 1986,
to Participation
Agreement, dated as
of August 1, 1986,
among PVNGS Funding
Corp., Inc., Bank
of America National
Trust and Savings
Association, State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee, APS, and
the Equity
Participant named
therein
10.8 to APS’ September 1986 Form 10-Q
Report by means of Amendment No. 1, on
December 3, 1986 Form 8, File No. 1-4473
Amendment No. 2,
dated as of March17, 1993, to
Participation
Agreement, dated
as of August 1,
1986, among PVNGS
Funding Corp.,
Inc., PVNGS II
Funding Corp.,
Inc., State Street
Bank and Trust
Company, as
successor to The
First National Bank
of Boston, in its
individual
capacity and as
Owner Trustee,
Chemical Bank, in
its individual
capacity and as
Indenture Trustee,
APS, and the Equity
Participant named
therein
28.4 to APS’ 1992 Form
10-K Report, File No. 1-4473
Trust Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Indenture Trustee
4.5 to APS’ Form S-3 Registration
Statement, File No. 33-9480
10-24-86
99.7c
Pinnacle West
APS
Supplemental
Indenture No. 1,
dated as of
November 1, 1986 to
Trust Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as
Owner Trustee, and
Chemical Bank, as
Indenture Trustee
10.6 to APS’ September 1986 Form 10-Q
Report by means of Amendment No. 1 on
December 3, 1986 Form 8, File No.
1-4473
Supplemental
Indenture No. 2 to
Trust Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Lease Indenture
Trustee
4.4 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
99.9c
Pinnacle West
APS
Assignment,
Assumption and
Further Agreement,
dated as of August
1, 1986, between
APS and State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee
28.3 to APS’ Form S-3 Registration
Statement, File No. 33-9480
10-24-86
99.10c
Pinnacle West
APS
Amendment No. 1,
dated as of
November 1, 1986,
to Assignment,
Assumption and
Further Agreement,
dated as of August
1, 1986, between
APS and State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as
Owner Trustee
10.10 to APS’ September 1986 Form 10-Q
Report by means of Amendment No. l on
December 3, 1986 Form 8, File No.
1-4473
Amendment No. 2,
dated as of March17, 1993, to
Assignment,
Assumption and
Further Agreement,
dated as of August
1, 1986, between
APS and State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee
28.6 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
99.12
Pinnacle West
APS
Participation
Agreement, dated as
of December 15,
1986, among PVNGS
Funding Report
Corp., Inc., State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee under a
Trust Indenture,
APS, and the Owner
Participant named
therein
28.2 to APS’ September 1992 Form 10-Q
Report, File No. 1-4473
Amendment No. 1,
dated as of August
1, 1987, to
Participation
Agreement, dated as
of December 15,
1986, among PVNGS
Funding Corp., Inc.
as Funding
Corporation, State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee, Chemical
Bank, as Indenture
Trustee, APS, and
the Owner
Participant named
therein
28.20 to APS’ Form S-3 Registration
Statement No. 33-9480 by means of a
November 6, 1986 Form 8-K Report, File
No. 1-4473
8-10-87
99.14
Pinnacle West
APS
Amendment No. 2,
dated as of March17, 1993, to
Participation
Agreement, dated as
of December 15,
1986, among PVNGS
Funding Corp.,
Inc., PVNGS II
Funding Corp.,
Inc., State Street
Bank and Trust
Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee, APS, and
the Owner
Participant named
therein
28.5 to APS’ 1992 Form
10-K Report, File No. 1-4473
Trust Indenture,
Mortgage Security
Agreement and
Assignment of
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Indenture Trustee
10.2 to APS’ November 18, 1986 Form
10-K Report, File No. 1-4473
1-20-87
99.16
Pinnacle West
APS
Supplemental
Indenture No. 1,
dated as of August
1, 1987, to Trust
Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Indenture Trustee
4.13 to APS’ Form S-3 Registration
Statement No. 33-9480 by means of August
1, 1987 Form 8-K Report, File No. 1-4473
Supplemental
Indenture No. 2 to
Trust Indenture
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Lease Indenture
Trustee
4.5 to APS’ 1992 Form 10-K Report, File
No. 1-4473
3-30-93
99.18
Pinnacle West
APS
Assignment,
Assumption and
Further Agreement,
dated as of
December 15, 1986,
between APS and
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as Owner
Trustee
10.5 to APS’ November 18, 1986 Form 8-K
Report, File No. 1-4473
1-20-87
99.19
Pinnacle West
APS
Amendment No. 1,
dated as of March17, 1993, to
Assignment,
Assumption and
Further Agreement,
dated as of
December 15, 1986,
between APS and
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as Owner
Trustee
28.7 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
99.20c
Pinnacle West
APS
Indemnity Agreement
dated as of March17, 1993 by APS
28.3 to APS’ 1992 Form
10-K Report, File No. 1-4473
Opinion and Order,
ACC Decision No.
67744 dated April7, 2005 (see
Exhibit 99.24
herein for
Attachment A to the
Opinion and Order,
the 2004 Settlement
Agreement)
99.5 to Pinnacle West/APS March 2005
Form 10-Q Report, File Nos. 1-8962 and
1-4473
5-10-05
99.26
Pinnacle West
Purchase Agreement
by and among
Pinnacle West
Energy Corporation
and GenWest, L.L.C.
and Nevada Power
Company, dated June21, 2005
99.5 to Pinnacle West/APS June 2005 Form
10-Q Report, File Nos. 1-8962 and 1-4473
8-9-05
99.27
Pinnacle West
APS
Amended and
Restated
Reimbursement
Agreement among
Arizona Public
Service Company,
The Banks party
thereto and
JPMorgan Chase
Bank, N.A., as
Administrative
Agent and Issuing
Bank, and Barclays
Bank PLC, as
Syndication Agent,
dated as of May 19,2005
99.6 to PinnacleWest/APS June 2005 Form
10-Q Report, File Nos. 1-8962 and 1-4473
8-9-05
99.28
Pinnacle West
APS
Application for
Emergency Interim
Rate Increase and
Interim Amendment
to Decision No.
67744
Non-GAAP Financial
Measure
Reconciliation -
Operating Income
(GAAP measure) to
Gross Margin
(non-GAAP financial
measure)
99.30
APS
Non-GAAP Financial
Measure
Reconciliation -
Operating Income
(GAAP measure) to
Gross Margin
(non-GAAP financial
measure)
a
Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
b
Management contract or compensatory plan or arrangement to be filed as an exhibit
pursuant to Item 14(c) of Form 10-K.
c
An additional document, substantially identical in all material respects to this
Exhibit, has been entered into, relating to an additional Equity Participant. Although such
additional document
may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates
of execution), there are no material details in which such document differs from this Exhibit.
d
Additional agreements, substantially identical in all material respects to this
Exhibit have been entered into with additional persons. Although such additional documents may
differ in other respects (such as dollar amounts and dates of execution), there are no material
details in which such agreements differ from this Exhibit.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
(William J. Post, Chairman of the
Board of Directors and Chief
Executive Officer)
Power of Attorney
We, the undersigned directors and executive officers of Pinnacle West Capital Corporation,
hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them,
our true and lawful attorneys with full power to them and each of them to sign for us, and in our
names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K
filed with the Securities and Exchange Commission.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
(Jack E. Davis, President and Chief Executive Officer)
Power of Attorney
We, the undersigned directors and executive officers of Arizona Public Service Company, hereby
severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our
true and lawful attorneys with full power to them and each of them to sign for us, and in our names
in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed
with the Securities and Exchange Commission.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
Pinnacle West
Capital Corporation
Supplemental Excess
Benefit Retirement
Plan, as amended
and restated, dated
December 18, 2003
10.64b
Pinnacle West
APS
Fourth Amendment to the Pinnacle
West Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan, effective January 1, 2003.
10.77bd
Pinnacle West
APS
Key Executive
Employment and
Severance Agreement
between Pinnacle
West and certain
executive officers
of Pinnacle West
and its
subsidiaries
10.91bd
Pinnacle West
APS
Performance Share Agreement
under the Pinnacle West
Capital Corporation
2002 Long-Term
Incentive Plan
10.92bd
Pinnacle West
APS
Summary of 2006 CEO
Variable Incentive
Plan and Officer
Variable Incentive
Plan
10.95
Pinnacle West
APS
Amended and
Restated Five-Year
Credit Agreement
dated as of
December 9, 2005
between APS, as
Borrower, Citibank,
N.A., as Agent, and
the lenders and
other parties
thereto
10.96
Pinnacle West
$200,000,000 Senior
Notes Uncommitted
Master Shelf
Agreement dated as
of February 28,2006
10.97
Pinnacle West
Amended and
Restated Credit
Agreement dated as
of December 9, 2005
among Pinnacle West
Capital
Corporation, as
Borrower, JPMorgan
Chase Bank, N.A.,
as Agent, and the
other agent parties
thereto
10.107
Pinnacle West
APS
Navajo Project Co-Tenancy Agreement
dated as of March 23, 1976, and Supplement No. 1 thereto
dated as of October 18, 1976, Amendment No. 1 dated as of
July 5, 1988, and Amendment No. 2 dated as of June 14, 1996, Amendment No. 3 dated as of
February 11, 1997; Amendment No. 4 dated as of
January 21, 1997; Amendment No. 5 dated as of
January 23, 1998; Amendment No. 6 dated as of July 31,1998.
10.108
Pinnacle West
APS
Navajo Project Participation
Agreement dated as of September 30, 1969, and Amendment and
Supplement No. 1 dated as of January 16, 1970, and
Coordinating Committee Agreement No. 1 dated as of September 31, 1971.
12.1
Pinnacle West
Ratio of Earnings
to Fixed Charges
12.2
APS
Ratio of Earnings
to Fixed Charges
12.3
Pinnacle West
Ratio of Earnings
to Combined Fixed Charges
and Preferred Stock Dividend Requirements
21.1
Pinnacle West
Subsidiaries of
Pinnacle West
23.1
Pinnacle West
Consent of Deloitte
& Touche LLP
23.2
APS
Consent of Deloitte
& Touche LLP
31.1
Pinnacle West
Certificate of
William J. Post,
Chief Executive
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
31.2
Pinnacle West
Certificate of
Donald E. Brandt,
Chief Financial
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
31.3
APS
Certificate of Jack
E. Davis, Chief
Executive Officer,
pursuant to Rule
13a-14(a) and Rule
15d-14(a) of the
Securities Exchange
Act, as amended
31.4
APS
Certificate of
Donald E. Brandt,
Chief Financial
Officer, pursuant
to Rule 13a-14(a)
and Rule 15d-14(a)
of the Securities
Exchange Act, as
amended
32.1
Pinnacle West
Certification of
Chief Executive
Officer and Chief
Financial Officer,
pursuant to 18
U.S.C. Section
1850, as adopted
pursuant to Section
906 of the
Sarbanes-Oxley Act
of 2002
32.2
APS
Certification of
Chief Executive
Officer and Chief
Financial Officer,
pursuant to 18
U.S.C. Section
1850, as adopted
pursuant to Section
906 of the
Sarbanes-Oxley Act
of 2002
99.29
Pinnacle West
Non-GAAP Financial
Measure
Reconciliation -
Operating Income
(GAAP measure) to
Gross Margin
(non-GAAP financial
measure)
99.30
APS
Non-GAAP Financial
Measure
Reconciliation -
Operating Income
(GAAP measure) to
Gross Margin
(non-GAAP financial
measure)
a
Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
b
Management contract or compensatory plan or arrangement to be filed as an exhibit
pursuant to Item 14(c) of Form 10-K.
c
An additional document, substantially identical in all material respects to this
Exhibit, has been entered into, relating to an additional Equity Participant. Although such
additional document
may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates
of execution), there are no material details in which such document differs from this Exhibit.
d
Additional agreements, substantially identical in all material respects to this
Exhibit have been entered into with additional persons. Although such additional documents may
differ in other respects (such as dollar amounts and dates of execution), there are no material
details in which such agreements differ from this Exhibit.
Dates Referenced Herein and Documents Incorporated by Reference
